Note: Descriptions are shown in the official language in which they were submitted.
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DRILLING FLUID
The present invention relates to drilling fluid and more
particularly, the present invention relates to a drilling
fluid composition adapted for use in high oil viscosity
applications such as steam assisted gravity drainage (SAGD)
and soak radial wells.
In the existing technology, there is a wide variety of
documents relating to drilling fluids and related materials.
It is known that drilling fluid, also referred to as drilling
mud, is an important part of a drilling operation. The fluid
is important to effect transport of debris, undesirable
materials, gas etc. The fluid also functions to maintain
lubrication and act as a coolant of the drill bit which
experiences enormous force, friction and other stresses.
Typical of the presently used fluids is Kim Mud. This
material provides high carrying capacity by an inherent
thixotropic viscosity. The composition may contain potassium
ions for reducing volume increases (swelling). This has the
advantage of preventing hydration of moisture sensitive
clays.
D-limonene has also been used in drilling fluid and is
particularly favored in view of the fact that it is a natural
substance extracted from citrus rind.
Various amines have also been used to augment drilling fluid
and provide a variety of advantages in different operating
conditions.
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It would be desirable to have a fluid capable of cleaning tar
out of sand and incorporate the oil in an emulsion with
subsequent release. Most of the fluids in current use are
based upon preventing the tar (heavy oil) from entering the
mud.
One object of one embodiment of the present invention is to
provide an improved drilling fluid which is not limited as
the prior art compositions.
One aspect of one embodiment of the present invention is to
provide a drilling fluid for use in drilling high oil
viscosity formations (tar, sand and oil entrained therein),
comprising:
a water base viscosifying polymer in an amount from
between .05% and 5% by volume;
a solvent in ari amount from between 1% and 20%
by volume; and
a de-emulsifier in an amount from between .05% and 10%
by volume.
Advantageously, the composition is environmentally friendly,
results in greater than 90% sand removal and is resistant to
common drilling contaminants such as solids, gypsum, lime and
salt inter alia.
Perhaps one of the most important features of the composition
is ease with which the emulsion is broken to provide the oil
and water as discrete phases. By enzymatic action, the
emulsion is de-emulsified and this has been observed over a
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wide temperature range. In fact, the emulsion is broken in
the absence of energy input, a significant feature.
A further aspect of one embodiment of the present invention
is to provide a method of recovering oil from tar sands
containing tar oil and sand, comprising
providing a composition containing a polymer, solvent
for solving oil and tar from said tar sands and an
emulsifier;
mixing compounds of said composition;
treating the tar sands with the composition to remove
sand from the tar sands;
forming an emulsion with oil contained in treated tar
sands where the emulsion is oil in water emulsion; and
de-emulsifying, under either energized or static
conditions, the emulsion to release the oil as a
separate phase from the water.
The composition in use has easily maintainable rheology and
filtration control over a broad range of downhole operations.
The following experiments are representative of the invention
methodology and set forth experimental details in respect of
the solution of the components of which the polymer system
was made.
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EXPERIMENT 1
A surfactant (Ho Flo) was evaluated in Kim Mud for its effect
on tar sand. Testing was done at 30 C. It was found that Ho
Flo at 0.1L/m3 in Kim Mud improves the clumping of tar sand
oil and prevents the stickiness of the oil to the testing
container.
EXPERIMENT 2
As an extension of Experiment No. 1, further testing was
performed on Ho Flo surfactant in Kim Mud regarding its
ability to prevent the tar sand oil from sticking to steel.
Lab results showed no apparent sticking of oil to steel in
straight Kim Mud. Consequently, Ho Flo was not required.
EXPERIMENT 3
Solubility of two tar sand samples was tested in DMO 100 at
room temperature (23 C) and 35 C. At 23 C, DMO solubilized
most of the tar leaving clean and freely moving sand.
Temperature elevation to 35 C resulted in higher solubility
and complete removal of the tar from sand.
EXPERIMENT 4
Four lubricants were tested in Stable K mud to select the one
with the least effect on tar sand. Testing was done at 23 C
and lubricant concentration of 1.5 and 3.0 kg/m3.
EZ Drill and EZ Drill II appeared to soften the tar sand,
although no obvious sign of dissolvability of tar sand was
noticed.
Tork-trol II and EZ Slide produced no change in the tar sand
appearance.
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EXPERIMENT 5
Stable K mud, Gel Chem mud, Stable K/K2SO4 mud and Polymer mud
were evaluated for their ability to prevent blinding/sticking
of bitumen from tar sands to screens. The testing temperature
5 ranged from 5 to 20 C and the screens used were 50, 70, 84
and 110 mesh. The Stable K mud was tested at 25 and 30 C as
well.
No blinding/sticking of bitumen to any screen occurred with
any of the muds. The bitumen behaved the same in each mud.
EXPERIMENT 6
Various additives were tested in Polymer mud, Stable K mud
and K2S04 /Gel mud to select the best combination that water
wets the shaker screen and prevents sticking of tar sands to
screen.
Drilltreat at 5L/m3 was the best additive improving the water
wetting ability of all muds. K2S04 worked similar in a Gel mud
and less in Polymer mud. Q'Flow (Glycol) produced a
softening of tar sands and dissolved some of the tar.
The second part of testing searched for an effective solvent
of tar sands. Diesel, DMO 100 and HT-40N were tested at 23 C.
The best solvent of tar from sand was Diesel with HT-40N
being second best. DMO 100 was not found effective in
removing the tar.
Experiments 7 - 9 represent lab work performed to develop a
drilling fluid that solved the problems associated with
drilling through tar sands. Thus, tar sand stickiness to
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equipment and shaker screen blinding was prevented with the
new drilling fluid by removing the tar from the sand.
The idea behind the new drilling fluid was to formulate a
direct emulsion where the external phase is water based and
the internal phase is the organic solvent that removes the
tar. Thus, the drilling fluid works by using the internal
phase to clean the sand and keeping the removed oil in
emulsion as fine drops. The emulsion is of loose structure
and is readily broken or demulsified.
EXPERIMENT 7
The experiment relates to tests performed to select the
organic solvent.
In order to find the best tar remover, over 50 products were
tested at various concentrations. Q'CleanT" was selected as
the best tar remover. Generally speaking, the product
comprises hydrogenated heavy petroleum naphtha together with
an organic solvent.
While Q'CleanTM was found as the tar remover and internal
phase in the new drilling fluid, the external (continuous)
phase selected was a Polymer/Stable K fluid.
No emulsifiers were required. Testing showed that emulsifiers
had an adverse reaction by creating too small a drop of
Q'CleanT " in the drilling fluid reducing its ability for
cleaning the sand.
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The new drilling fluid, Polymer/Stable K/ Q'CleanT" was
effective in removing the tar from the sand over a large
range of temperatures, namely 5-30 C.
EXPERIMENT 8
This experiment sets forth work done to evaluate the
performance of drilling fluid on a different sample of tar
sands.
The Polymer/Stable K/Q'Clean' fluid was tested at
temperatures between 5 and 30 C on tar sand from ECR 3B 102
Leismer LSD 2/13-16-76-6w4. Testing confirmed that
Polymer/Stable K/Q'CleanT" fluid worked very well; the tar
sand was cleaned at the temperature range indicated.
EXPERIMENT 9
This experiment related to developing the optimum formulation
for the drilling fluid. The objective was to find the
drilling fluid that dissolved and incorporated the tar, was
least affected by contaminants and could be easily disposed
of at the end of the well.
The project had 3 parts:
designing and testing for the optimum formulation of
drilling fluid with regards to tar removing ability;
testing the likely contaminants on the fluid to see if
any fluid formulation adjustment is required; and
testing for emulsion breaking and oil phase separation
for fluid disposal at the end of the well.
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8
A new drilling fluid formulation containing Polymers/sized
Calcium Carbonate/ Q'Clean"" was designed and tested. Various
viscosifiers were tested at different concentrations with
regards to mud rheology, cleaning ability and effect on
emulsion breaking.
The following fluid formulation was selected for its good
rheology, fluid loss and tar sand cleaning ability:
PolyTarTM System
Kelzan XCD 0.75 kg/m3
Staf lo R 2 kg/m3
Starpak DP 6 kg/m3
Calcarb 325 10 kg/m3
Calcarb 0 10 kg/m3
Caustic Soda pH 10
Q' CleanTM 5 % v/v
Date illustrating the effectiveness will be presented herein
after.
Contaminants testing on the drilling fluid showed minimal
effects on its rheology and cleaning ability. Thus, gypsum
and salt (NaCI) produced a moderate decrease in fluid
rheology. The cleaning ability was affected only by salt;
slightly reduced from 96% wt. to 80% wt. Solids contamination
was simulated by adding 6% v/v tar sand to the drilling fluid
already containing 5% v/v tar sand. The fluid behaved very
well, cleaning 26% wt. tar sand of f of the extra 6% v/v tar
sand added.
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After finding the fluid formulation and testing the
contaminants, the environmental aspect of fluid development
was reviewed. At the end of the well, the drilling fluid is a
direct emulsion that contains as the internal phase (oil
phase) the solvent (Q'Clean') and the dissolved tar. In order
to be able to dispose of the drilling fluid, the emulsion has
to be broken and oil phase has to be separated and removed.
Breaking the emulsion of PolyTar'" System was attempted in
three ways:
l. By making use of chemical demulsifiers. Eight
demulsifiers were tested with no good results;
2. Making use of non-emulsifiers (two products) in the mud
formulation to prevent the forming of a stable emulsion;
and
3. Using a polymer breaker (four products, enzymes and
bleach) to reduce the fluid viscosity and speed up the
oil separation.
Q'BreakT" (enzyme) at concentration of 2 kg/m3 is the best
product to help with emulsion breaking and oil separation
from the drilling fluid. It produces a fast reduction in mud
viscosity, the emulsion breaks easily and the oil (Q'CleanTM
+Tar) separates on top of fluid. After the treatment with
Q'BreakTM 2 kg/m3 and 24 hours static at 22 C, the oil left in
emulsion in the mud was only 0.47 % v/v. Most of the oil
phase (Q'Clean' " and dissolved Tar) was separated from the mud
as a top layer and could be skimmed off.
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Q'BreakTM is an enzyme that works well at low temperatures,
however, higher concentrations are recommended. Also, the
product is safe and environmentally friendly.
5 A new approach to tar sand drilling resulted in development
of a new drilling fluid addressing specific problems
encountered in SAGD drilling projects.
The new drilling fluid was designed to solve the problem of
10 tar sand stickiness by removing the tar from the sand. Lower
toxicity and lower cost were pursued as attributes of the new
drilling fluid designed.
Tables 1 and 2 set forth data and observations noted.
In respect of the drilling fluid composition, the following
procedure was observed.
Various additives at various concentrations were added
to water to examine the capacity to remove tar and
clean the sand.
200 ml of the testing fluid received 20g of tar sands.
The mixture was mixed on a Barnant mixer for 30 minutes
at room temperature. The range of temperature for the
testing was between 5 C and 30 C.
Table 1 tabulates the data and observations noted
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Table 1
Fluid Additive selection
Additive & concentration WTS, Visual observations
in water
Blank (water) 19.580 Tar sands appeared unchanged. Fluid hase is clear and
clean.
PAW 2315 1% v/v 19.660 Tar sands appeared unchanged. Fluid phase is clear.
PAW 2315 @ 3% v/v 20.125 There is a very small amount of clean sand. The tar
sand left is broken into smaller pieces;
however, they remained hard. Fluid phase contains suspended small oil drops
cleaned off
the sand.
PAW 3900 1% v/v 20.138 Similar to PAW 2315 1% v/v.
PAW 3900 @ 3% v!v 20.632 There is a very small amount of clean sand. The tar
sand left seems to remain in same size
pieces; however, they remained hard. Fluid phase contains suspended small oil
drops
cleaned off the sand.
WAW 3917 3% v/v 19.883 Siniilar to PAW 2315 1% v/v.
WAO 3919U @ 3% v/v 20.281 Works well. Most sand is loose and fairly clean and
the fluid phase is dark coloured. There
1 O are a few small soft pieces of tar sand left on the bottom of the beaker.
WAO 3919U @ 1% v/v 20.002 Similar to PAW 3919U @ 3% v/v. Just not quite as
effective in cleaning the sand.
Beta Cyclod. @ 5 kg/m 20.420 There is a very small amount of clean sand. The
tar sand left seems to remain in same size
pieces. Fluid phase has a thin oily film on top. There are lost of small tar
sand particles.
Beta Cyclod. @ 10 kg/m 21.940 No significant improvement.
Beta Cyclod. @ 20 kg/m 20.600 No significant improvement. Noticeable is the
fact that 20 kg/m appears to be above its
solubility.
Cut Clean@ 1% v/v 20.283 There is a large amount of clean sand and large
pieces of tar sand left. The fluid phase is
clear with no suspended solids. It has an oil Slm and a rin at the surface.
Cut Clean @ 2% v/v 20.146 The tar sand is completely broken down. On top of
the sand layer there is a layer of large oil
globules separated when agitation ceased. The fluid phase is cloudy, tan, with
the odd
suspended globule of oil and a thick layer of oil on top.
Cut Clean @ 3% v/v 19.948 The sand is completely entrapped in what appears to
be a water in oil emulsion on the
bottom of the beaker. This very viscous layer with a gel like consistency is
easily moved
with a itation. The fluid phase is similar to the one above.
= Mudd Lite 2"/o v/v 20.885 Tar sands appeared unchan , Fluid ase is tan in
colour and has a layer of foam on t.
Mudd late 6% v/v 19.962 Similar to Mudd I,ite 2% v/v.
DH6-115-2 19.802 Tar sands appeared unchanged. Fluid phase is clear.
E X107 3% v/v 20.800 Tar sands appeared unc . Fluid liase is clear.
E X1501 @ 3% v/v 20.670 There is a very.small amount of clean sand. The tar
sand left seerns to remain in sanie size
pieces. hi water, this additive coagulated in a cream-yellow layer that
separates on top of the
fluid phase when at rest,
B XA923 3% v/v 20.791 Tar sands appeared unchanged, Fluid phase is clear.
E X1033 3% v/v 19.703 It broke the large tar sand pieces into sniall ones but
there is no clean sand.
S DN82 @ 3% v/v 20.799 The sand is completely entrapped in what appears to be
a water in oil emulsion on the
bottom of the beaker. The G uid phase above this bottom layer is clean and
clear.
E X1557 @ 3% v/v 19.600 - 75% of tar sand is completely clean. The rest of tar
sand is in pieces looking unchanged.
Under the microscope can see the oil in water emulsion that has a dark colour.
Theie is a
thin filtn of oil on tpp of fluid phase.
E X1557 1% v1v 20.557 Sitnilar to above test, just that on the sand 'ns are
not ' uite as clean.
E XI557 5% v/v Sarre as 3% v/v.
E X 606 @ 3% v/v 20.903 There is a very small amount of clean sand. The tar
sand left seems to remain in same size
pieces. The fluid phase is li t tan in colour and contains few tar particles
suspmded.
E X 109 @ 3o/a v/v 19.282 - 75% of tar sand is completely clean. The rest of
tar sand is in pieces looking unchanged.
Under the mieroscope can see the fluid as oil in water emulsion that has a
dark colour.
There is a thin film of oil on top of fluid phase.
E X 109 5% v/v 20.104 Same as 3% v/v.
S DN71 @ 3% vfv 20.120 - 50% of sand is partially clean and the other 50% is
left unchanged in tar sand pieces. The
fluid phase is oil in water emuision.
S DN 120 @ 3% v/v 20.322 'There is less than 1% of clean sand. The tar sand
left seems to temain in sanie size pieces.
The fluid phase is clean and clear.
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Table 1 cont'd
Fluid Additive selection
Additive & concentration WTS, Visual observations
in water
S DN114 3% v/v 19.820 As above
15 - 20% of sand is clean. The rest appears unchanged. The fluid phase is
milky-gray in
S DN 121 3% v/v 20.026 colour.
- 75% of sand is completely clean. The rest of tar sand is in fairly small
pieces. Under the
S DN87 3% v/v 20.735 microsco can see the fluid as oil in water emulsion that
has a dark colour.
S DN87 3% v/v 20.610 Some improvement from 3% v/v, however,there still are a
few tar sand pieces left.
Most of tar sand (-75%) is a flowing sludge on the bottom of beaker. There are
a few pieces
S DN76 3% v/v 21.028 of tar sand
- 80 - 90% of sand is fairly clean but the oil is not emulsioned and just lays
and sticks to the
DT78 3% v/v 20.782 sandla er.
There is less than 1% of clean sand. The tar sand left seems to remain in same
size pieces.
DG56 3% v/v 20.980 The fluid phase is clean and clear.
- 50% of sand is fairly clean and the other 50% is left small tar sand pieces.
The fluid phase
M38 3% v/v 20.853 is oil in water emulsion.
-- 50% of loose sand, dark, still coated with oil. The rest of tar sand seems
to remain in same
M150 3% v/v 19:320 size pieces. The fluid phase is dark
- 75% of tar sand is completely clean . The rest of tar sand is in pieces
looking unchanged..
Under the microscope can see the oil in water emulsion that has a dark colour.
There is a thin
M192 3% v/v 20.962 fihnofoilonto .
M192 5% v/v 20,042 Some improvement from 3% v/v, however there still are a few
tar sand pieces left.
M187 3% v/v 20.178 - 15 - 20% of sand is clean. The rest a unchanged. The
fluid phase is tan in colour.
Solvent 5% v/v 19.314 - 80% of sand is loose, free flowing but still covered
by oil material
-- 50% of sand is fairly clean and the other 50% is left small tar sand
pieces. The fluid phase
P2-181-9 1%v/v 20.386 is an emulsion.
P2-181-11B 1% v/v 20.408 - 15 - 20% of sand is clean. The rest appears
unchanged.
- 50% of sand is fairly clean and the other 50% is left small tar sand pieces.
The fluid phase
P2-181-15B 1% v/v 20.560 is an emulsion.
P2-181-19B 1"/o v/v 21.300 Complete balling of tar sands that became soft (it
incorporated water) and stic .
P2-181-16B 1% v/v 21.107 - 15 - 20% of sand is clean. The rest appears
unchanged.
P2-181-21B 1% v/v 20.144 - 15 - 20% of sand is clean. The rest of tar sand is
soft and sticky.
Travis 2095 1% v/v 21.893 - 5% of sand is clean. The rest appeaTs unchanged.
Travis 2704 1% v/v 20.982 Tar sands appeared unchanged. Fluid phase is clear.
Drilling Fluid selection - Polymer/Stable K system
WTS, Visual Observations
Additive & concentration
In drilling fluid g
Blank (Poly./Stable K)
E XZ1557 1% v/v 20.634 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
- 40% of tar sand remained on the 30 mesh screen as small and large pieces.
Dark fluid
E XZ1557 3% v/v 20.049 phase of oil in water emulsion.
Xylene/Isopropanol 20.250 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
3% v/v
There is a small amount of loose sand. Tar sand left remained in same size
pieces. Fluid
Diesel 3% v/v 20.975 phase is emulsion with suspended tar particles.
Diesel 10% v/v 19.580 Most solids are loose, still covered by oil and flowing.
Diesel @ 10% v/v + 20.078 Tar sands appeared unchanged. The oil is emulsioned
as extremely small drops that could
XZ1557 % v/v not contact the tar sands and is fairly clean.
BDDt00 3% v/v 20.980 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
BDS300 @3% v/v 19.047 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
BDS200 @3% v/v 20.382 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
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Table 1 cont'd
E X1577 @3% v/20.490 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
E X1421 % v/v 20.195 It produced rapid precipitation-coagulation of the
Polymer/Stable K system.
E X1262 @3% v/v 20.728 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
E X1667 @3% v/v 20.801 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
DWB-1-5 @3% v/v 20.221 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
DWB-1-9 @3% v/v 20.453 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
DWB-1-6 3% v/v 20.735 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
DWB-1-7 3% v/v 20.466 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
DWB-1-8 3% v/v 19.952 Tar sands appeared unchanged. Fluid phase contains small
tar particles suspended.
Some clean sand grains seen under microscope. Most tar sand is left uncleaned
as small
Solvent @ 3% v/v + 20.942
XZ 1557 1% v/v pieces.
'10 Cleaned most of sand. Mixture is poured on a 30 mesh screen. - 10% of tar
sand reniained
20.631 on the screen. Can see the clear - clean sand grains suspended in the
fluid and the dark oil
Solvent 10% v/v drops. Fluid phase is very dark due to the dissolved oil.
Solvent @ 10% v/v + 20.17 < 5% of tar sand left on the 30 mesh screen as
sniall and soft pieces. Dark fluid phase
Rev Dust 4% v/v containing almost completely clean sand.
Solvent @ 7% v/v + 20.353
Rev Dust 4% v/v ~5 - 7 % of tar sand left on the 30 mesh screen. The rest as
above.
20.824 - 70% of tar sand remained on the 30 niesh screen as small and large
pieces. Dark fluid
M 192 5% v/v phase.
20.560 "' 30% of tar sand remained on the 30 mesh screen as small and large
pieces. Dark fluid
Amodrill 1400 10% v/v phase.
Emulam D30 5% v/v 20.106 -100% of tar sand remained on the 30 mesh screen as
unchanged small and large pieces.
20.929 - 30% of tar sand remained on the 30 mesh screen as small and large
pieces. Dark fluid
Cut Clean 5% v/v phase.,
Drilling Fluid selection - Gel Chem system
WTS, Visual Observations
Additive & concentration
in drilling fluid g
Blank (Gel Chem s s. 20.651 Tar sands appeared unchanged. Fluid phase contains
small tar particles suspended.
- 20% of tar sand remained on the 30 mesh screen as small and large pieces.
Dark fluid
Tar Solvent 10% v/v 20.920 Phase with fairly cleafi sand suspended.
Tar Solvent @ 10% v/v + 20.700 As above.
Rev Dust 4% v/v
Additive concentration WTS, Visual Observations
and
rnixture temperature 9 - 10% of tar sand left on the 30 mesh screen as sniall
and soft . pieces. Dark fluid phase
Tar Solvent @ 20% v/v
5 C 20 878 containing almost completely sand.
Tar Solvent @ 10% v/v - 50% of tar sand left on the 30 mesh screen as small
and soft pieces. Dark fluid phase.
- 10 C 19.968
Tar Solvent @ 15% v/v - 20% of tar sand left on the 30 mesh screen as small
and soft pieces. Dark fluid phase.
10 C 20.261
- 10% of tar sand left on the 30 mesh screen as small and soft pieces. Dark
fluid phase
Tar Solvent @ 20% v/v
- 10 C 20.325 containing almost completely sand.
Tar Solvent @ 15% v/v - 20% of tar sand left on the 30 mesh screen as small
and soft pieces. Dark fluid phase.
- 15 C 20.380
- 10% of tar sand left on the 30 niesh screen as small and soft pieces. Dark
fluid phase
Tar Solvent @ 20% v/v
15 C 20.375 containing almost completely sand.
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Table 1 cont'd
- 5% of tar sand left on the 30 mesh screen as sniall and soft pieces. Dark
fluid phase
Tar Solvent @ 10% v/v containing almost completely sand.
-20 C 20.713
Tar Solvent @ 10% v/v As above
- 25 C 20.532
- 3% of tar sand left on the 30 mesh screen as small and soft pieces. Dark
fluid phase
Tar Solvent @ 10% v/v 30 C 20.342 containing almost completely sand.
In connection with the fluid testing, the following procedure
was involved.
200 mL of drilling fluid, discussed herein previously,
was placed in a beaker to which 20 g of Tar Sands was
added. This was mixed on a Barnant mixer for 30 minutes
at room temperature. The mixture was passed through a 30
mesh screen.
The test was repeated in a temperature range of between 5 and
30 C.
Table 2
Tar sands from 397.4m depth - Drilling fluid testing
Solvent concentration in WTS; Visual Observations
drilling fluid g
and test teWemture
15% v/v 3olvent & 5 C - 20.450 - 15-20% of tar sand left on the 30 mesh screen
(small and large pieces)
and a significant amount of clean large sand grains ( 3mm diameter).
Dark fluid phase containing com letel clean sand
20% v/v Solvent & 5 C 19.781 - 10% of tar sand left on the 30 mesh screen
(small and large pieces) and
a significant amount of clean large sand grains (-3mm diameter). Dark
fluid phase containing com letel clean sand
10% v/v Solvent & 10 C 19.968 - 20% of tar sand left on the 30 mesh screen as
various size pieces. The
rest is as above.
15% v/v Solvent & 10 C 20.261 - 15% of tar sand left on the 30 mesh screen as
various size pieces. The
rest is as above. .
20% v/v Solvent & 10 C 20.371 ,- 7-10% of tar sand left on the 30 mesh screen
as small and soft pieces.
The rest is as above.
10% v/v Solvent & 15 C 20.482 - 15% of tar sand left on the 30 mesh screen as
various size pieces. The
rest is as above.
15% v/v Solvent & 15 C 20.037 - 15% of tar sand left on the 30 mesh screen as
various size pieces. The
rest is as above.
20% v/v Solvent & 20 C 20.389 - 3% of tar sand left on the 30 mesh screen as
small size pieces. The rest
is as above.
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Table 2 cont'd
0% v/v Solvent & 20 C 20.253 - 80% of tar sand left on the 30 mesh screen as
small size pieces. The
solids that passed through the screen are suspended in the fluid and
consist of tar sands and heavy oil particles,
10% v/v Solvent & 20 C 20.135 - 7-10% of tar sand left on the 30 mesh screen
(small and large pieces)
and a significant amount of clean large sand grains (-3mm diameter).
Dark fluid phase containing completely clean sand
10% v/v Solvent & 25 C 20.185 - 5% of tar sand left on the 30 mesh screen as
various size pieces. The
rest is as above.
10% v/v Solvent & 30 C 20.019 No tar sand left on the 30 mesh screen. The
only solids left on screen are
the clean large sand grains (-3mm diameter). Dark fluid phase containing
completely clean sand.
Note: WTS - weight of tar sands.
In all the above tests where the new drilling f luid was used
(all except sample with 0% v/v Solvent), the fluid phase was
an oil in water emulsion. The oil drops had a good size (not
too small, not too big) and were dark colored due to the tar
having been stripped off the sand.
The core sample of tar sands used to perform the above
testing showed very small pieces of completely clean solids
(shale like). These clean solids were avoided when tar sand
samples were removed from the core during testing.
Tables 3 through 22 tabulate data for different polymer
systems together with specific listing for each.
As set forth herein previously, having listed the necessary
components for the polymer system, ranges for effectiveness
were required for determination. The following two polymer
systems were tested
CA 02481543 2004-09-14
16 9-15652-2CA
Polymer System A Polymer System B
Additive Concentration Additive Concentration
Kelzan 1.5 kg/m Kelzan 2 kg/m
XCD XCD
Staflo R 2 kg/m 3 Staflo R 2 kg/m
Starpak 6 kg/m Starpak 6 kg/m
DP DP
Calcarb 10 kg/m Calcarb 10 kg/m
325 325
Calcarb 0 10 kg/m Calcarb 0 10 kg/m
Caustic pH 10 Caustic pH 10
Soda Soda
Q/C = Q'Clean
Table 3
Mud Fonnulation Testin - Rhoology and API Nuid loss at 23 C
Foarnulation 600 300 200 100 60 30 6 3 Geis, PV, lfP, FL,
m m rpm rpm rpm m Pa cP Pa mL
A 65 47 40 30 23 17 8 7 3.5/4.0 18 14.5 13.8
A+ 2,5%0'C 66 49' 41 30 24 18 8 7 3.5/4.0 18 16.0 12.0
A+ 3 /.Q'C 70 52 43 32 25 18 9 8 4.0/4.5 18 17.0 9.8
A+ 10%Q'C 71 52 43 32 25 19 9 8 4.5(4.5 19 16.5 8.3
B 101 78 67 48 40 30 12 10 4.515.0 23 27.5 11.2
B + 2.5%Q'C 105 81 69 52 41 30 13 11 5.0/5.5 24 28.5 11.0
8 + 596Q'C 110 84 72 54 43 31 14 11 5.5/5.5 26 29.0 12.4
B + 10%Q'C 115 89 75 57 46 33 15 12 6.0/5.0 26 31.5 9.0
Table 4
Tar Sand Cieanin at 23 C
Fluid Wei ht, 11 Tar sand
Formulation Tar Dish Residue Residue cleaned,
sand & Dish > 30 mesh % wt.
A 27.131 1.060 23.013 21.953 19.1
A+ 2.5%Q'C 27.122 1.000 7.890 6.890 74.6
A+ 5%Q'C 27.300 1.033 2.112 1.079 96.0
A+ 10%Q'C 27.644 1.004 1.671 0.667 97.6
B 27.233 1.039 23.474 22.435 17.6
B+ 2.5%Q'C 27.473 1.038 8.375 7.337 73.3
8+ 596Q'C 27.457 1.031 2.718 1.687 93.9
8 + 10%Q'C 27.295 1.038 2.273 1.235 95.5
CA 02481543 2004-09-14
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17
Table 5
Contaminants Tesdny on the PotyTer System (PTS = A+ 5'Y.Q'C ). Rheokny at 23=C
Sample 600 300 200 100 60 30 6 3 Gels, PV, YP,
m m m rpm m m Pa oP Pa
PTS 64 47 39 28 23 16 8 6 3.0/3.5 17 15
PTS + 5 kg/m 48 35 29 20 16 12 5 4 2.5/2.5 13 11
Gypsum
PTS + I k m Lime 64 47 39 28 23 16 8 6 3.0/3.5 17 15
PTS + NaOH for H12 62 46 38 28 22 15 7 5 3.0/3.0 16 15
PTS + 5 k m NaCI 56 41 34 24 19 13 6 5 2.5/3.0 15 13
PTS + 10 k m NaCI 54 39 32 23 18 13 6 5 2.5/3.0 15 12
PTS + 20 k m NaCI 49 35 29 21 16 11 5 4 2.0/2.5 14 10.5
PTS + 6% vol. Tar 72 52 42 31 24 18 9 6 3.0/3.5 20 16
Sauid
Table 6
Contaminants Testing on the PolyTar System (PTS). API fluid loss
Sample FL,
mL
PTS 10
PTS + 5 kg/M3 Gypsum 9.5
PTS + 1 kg/m3 Lime 10 PTS + 5 kg/m NaCI 9.5
PTS + 10 kg/m NaC1 9
PTS + 20 kg/M3 NaCI 8
PTS + 6% vol. Tar Sand 6
Table 7
Tar Sand Cleaning In contaminated fluid at 23 C - 5% vot. Tar Sand In the
Fluid Sample
Wei ht, Tar sand
Fluid Sample Tar Dish Residu Residue cleaned,
sand & Dish > 30 mesh % wt.
PolyTar System PTS 27.300 1.033 2.112 1.079 96.0
PTS + 5 kg/M3 Gypsum 27.611 1.002 2.882 1.880 93.2
PTS + I k/m Lime 27.273 1.027 2.527 1.500 94.5
PTS + 5 k m NaCi 27.458 0.998 5.720 4.722 82.8
PTS + 10 k/m NaCi 27.397 1.004 6.278 5.274 80.7
PTS + 20 k m NaCi 27.315 1.004 6.425 5.421 80.2
PTS + 6% vol. Tar Sand 27.289 1.020 21.099 20.079 26.4
CA 02481543 2004-09-14
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18
Table 8
ar issolved Tar Emulslon EM!LMM at 23'C - Rsnwvwl of dissolved tar.
Oemutsiflsr Conc., Notes on emuision t+ehavkour
Um'
None ON drops are small but vWble wtth naked eye. The ofl In water emulsion is
stable. It does not
break in over 8 hours. After 24 hours there Is a v small amount of free ofl on
top of fluid.
72001 1 Oil drops are not visibie with naked eye. Under the microscope they
look 2- 3 times smaller than
2 they were initiaily. The oA In water emulsion became more stable. tt does
not break in over 24
hours. There Is no free oil on t of fluid.
T2005 I Oil drops are not visible with naked eye. Under the microscope they
look 2- 3 tbnes smaller than
2 they were initiaily. The oil In water emufsion became rnore stable. It does
not break in over 24
hours. There Is no free oii on to of fluid.
12007 1 OA drops are not vis e with naked eye. Under the microscope they look
2- 3 times smaNer than
2 they were initially. The oU In water emulsion became more stable. It does
not break In over 24
hours. There is no free oil on to of fluid.
T2508 I Oil drops are not visible with naked eye. Under the microscope they
iook 2- 3 dmes smaller than
2 they were inHtally. The oN In water emulsion became more stable. It does not
break In over 24
hours. There is no free oH on of fluid.
NE 125 0.5 Oq drops are small but visible with naked eye. The oil In water
emulsion is stable. It does not
1 break In over 8 hours. After 24 hours there is a very small amount of free
oil on top of fluid.
2
NE 723 0.5 ON drops are smaA but vislble with naked eye. The op in water
emuislon k stabN. U does not
I break in over 8 hours. AIW 24 hours there is a vafy smal amount of free op
on top of tdd.
2
Table 9
Po Tar 8 tsmlOissolvsd Tar Emulslon = Preventing forming a stabls amuhion
using non-emulstMrs 25'C .
Non-emuis Caic., Notes on emulsion behevbur
t./my
None 01 drops are sma4 but vbible wilh nakad eye. The 91 In water emulsion Is
s e. R does not
break In over 8 hours. Aftx 24 hours there a a sma8 amourri of free o8 on or
filua.
125 1 ON drops are not visible wph naked eye. Under the mWoscope they Wk 2-
tknes sma r than
2 they were initiatty. The ofl In water emulsion became more stable. it does
not break In over 24
hours. There is no free ofl on top of fluid.
NE 723 1 Oil drops are not visible with naked eye. Under the microscope they
look 2- 3 times smaAer than
2 they were inttiaNy. The oN In water emutsion became more stable. lt does not
break In over 24
hours. There Is no free oN on Le2 of Auid.
Table 10
Tar Sand Cieanin at 23 C - PTS cleaning abili when usin non-emu{sifiers at 1
Llms.
Non-emulsifi We ht, Tar sand
Tar Dish Residue Residue cleaned,
sand & Dish > 30 mesh % wt.
NE 125 27.655 1.036 13.601 12.565 54.6
NE 723 27.504 1.000 8.898 8.898 67.6
CA 02481543 2008-08-28
19
Table 11
Vbcosltier sNection to provent forming a stabk PolyTar SystemlDlssolvsd Tar
Emulsion - Polymer (Viscoslfter)
Testf In Pol ar bm - Rheol at 23 C C.
Viscosmer kg/m 600 300 200 100 60 30 6 3 Gels, PV, YP,
m m m m m m m m Pa oP Pa
Kelzan XCD 1.5 70 52 43 32 25. 18 9 8 4l4.5 18 17
Biovis 1.5 54 37 29 18 13 8 3 2 11.5 27 5
Biovis 3 73 53 44 33 27 20 10 8 4.616.5 20 16.5
Geovis XT 1.5 71 51 42 32 25 19 10 9 5I7 20 15.5
HEC 1.5 92 70 68 43 33 23 9 7 3, .5 22 24
Xanvis 1.5 60 43 38 26 20 15 7 B 313.5 17 13
Table 12
Tar $and Cleanln at 23=C = PTS clesnin ability wMn usi vbcosfMn and
concentratlons above mentioned.
vwcosvw W e t Tar "nd
Tar Dish Residue Residue cleaned,
sand & Dish > 30 mesh 9b wt. .
Kelzan XCD 27.300 1.033 2.112 1.079 96.0
Biovis - 1.5 27.345 1.009 5.078 4.067 85.1
Biovis - 3 27.474 1.033 3.398 2.365 91.4
Geovis XT 27.343 1.020 4.354 3.334 87.8
HEC 27.456 1.031 9.140 8.109 70.5
Xanvis 27.333 1.002 4.838 3.636 86.7
Tstble 13
Vlscoslfler selectlon to prevent fortnl ^ stable P ar S Tar Emulsion -Testl at
23'C .
vwoositiw ' Notes on emubion behevlour wphln 8 hours
Keizan XCD 1.5 The oil In water emulsion is less stable. Emutskm Is slowly
breaking,There Is e bit of free oil on
of Aukf afler 6 hours. This sam looks the best .
-top Biovis 3 The ol In water emulsion Is stable. No sign of emulsion breakMg
ln hours. re Is no free oll on
t of fluid.
1=5 The o~~water emulsion is stable. No sign of emulsion breaking in 6
hours.There is no free oN on
Geovis
HEC 1.5 The oil water emulsion is steble. No sign of emulsion breaking in 6
hours.There is no free ol on
top of 11ukf.
Xanvis 1.5 %, ol in water emuls appsara less stable. F-mulsion is slowly
breaking.There are treoes of
free oa on of Iwid after 6 hours. This samp4e Is fie nazt best
CA 02481543 2004-09-14
20 9-15652-2CA
Table 14
Polymer Breaker Testi on PTS containi Kelaan XCD 1.5 k/m' - oology after 24
hours 23=C
Breaker & conc., 600 300 200 100 60 30 6 3 Gels, PV, YP,
k m3 m rpm rpm m m m m rpm Pa cP Pa
None 66 48 41 30 24 17 8 6 313.5 18 15
Q'Break, 2 41 28 22 15 11 8 4 3 1.5/1.5 13 7.5
Chembreak HC, 3 41 27 22 15 11 8 3 2 1/1.5 14 6.5
Chembreak EBS, 3 52 38 31 22 17 12 6 5 2.5/3 14 12
Chembreak EBS 3" 48 34 28 20 16 11 5 4 2/2 14 10
81each, 5 Um 26 17 13 9 7 5 2 2 1(1 9 4
Note: - sample contains 5,000 ppm Cr as NaC1.
An adjusted polymer system was then reviewed.
Adjusted PolyTar System formulation (less viscosifier)
Additive Concentration Additive Concentration
3 3
Kelzan .75 kg/m
- Xanvis 1 kg/m
XCD
Staf lo R 2 kg/m Staf lo R 2 kg/m
Starpak 6 kg/m Starpak 6 kg/m
DP DI?
Calcarb 10 kg/m Calcarb 10 kg/m
325 325
Calcarb 0 10 kg/m Calcarb 0 10 kg/m3
Caustic pH 10 Caustic pH 10
Soda Soda
Q'Clean 5% vol. Q'Clean 5% vol.
Table 15
PolyTar S tom/Dissolvsd Tar Emulsbn (5% vol. Tar Sand In the mud - Rheo at 23
C .
Viscosifier kg/rn 600 300 200 100 60 30 6 3 Gels, PV, YP,
m rDm m r m m Pa cP Pa
Keizax~ XCD 0.75 58 42 34 24 18 12 5 4 2/2 16 13
Xanvis 1 62 46 38 27 21 15 6 5 2.5/3 16 15
CA 02481543 2004-09-14
21 9-15652-2CA
Table 16
Tar Sand Cieanin at 23 C - PTS cleaning abil when usl viscoslfisrs and
concentrations above mentioned.
ViscosiFier We t, Tar sand
Tar Dish Residue Residue cleaned,
sand & Dish > 30 mesh % wt.
S fKelzan XCD 27.397 1.059 4.116 3.057 88.8
Xanvis 27.512 1.040 5.076 4.378 84.1
Table 17
Polymer Breaker Testin on PTS containin Kelzan XCD 0.75 k/m' =.. Rheolo after
2 ours 23 C
Breaker & conc., 600 300 200 100 60 30 6 3 Gels, PV, YP,
klm3 rpm rpm rpm rpm rpm rpm rm rm Pa cP Pa
None 58 42 34 24 18 12 5 4 2/2 16 13
Q'Break, 2 41 25 19 12 9 5 2 2 1!1 16 4.5
Chembreak HC, 3 27 17 13 8 5 4 1 1 0,510.5 10 3.5
Bleach, 5 Um 56 36 27 17 13 8 3 2 1/1 20 8
Table 18
Polymer Breaker Testin on PTS containin Xanvis 1 k!m' - Rheol after 2 hours 4
23 C
Breaker & conc., 600 300 200 100 60 30 6 3 Gels, PV, YP,
k m3 rpm rpm rpm r m rpm rpm rpm rpm Pa cP Pa
None 62 46 38 27 21 15 6 5 2.5/3 16 15
Q'Break, 2 44 28 22 14 10 7 3 2 1l1 16 6
Chembreak HC, 3 41 28 22 15 11 7 3 2 1/1 13 7.5
B$os&, 5 Um 69 771 47 38 25 19 13 5 4 2/2.5 22 12.5
Table 19
Retort Test on Pol Tar System/Dissolved Tar Emulsion (5% vol. Tar Sand In the
mud)
Sarnple from 1/2 height of emulsion in 250 mL Retort content, % v/v Total
Hydrocarbons Content (Core Labs),
graduated cylinder after 24 hours Oil Water Solids % v/v
Biank (no ECA) 5 94 1
Q'Break 2 kg/m3 2 97 1 0.473
Q'Break 4 k m3 1 99 0 0.492
CA 02481543 2004-09-14
22 9-15652-2CA
Table 2 0
Q'Break Testin at 23 C room on PTS containin Kelzan XCD 0.7S k!m3 - Rheolo 23
C
Q'Break 600 300 200 100 60 30 6 3 Gels, PV, YP,
k/m' rpm rpm m rpm rpm rpm m rpm Pa cP Pa
None 58 42 34 24 18 12 5 4 2/2 16 13
2 k/m , after 2 hours 40 26 20 13 9 6 2 2 1/1 14 6
k m, after 6 hours 36 23 18 11 8 5 2 1 0.5/0.5 13 5
2 kg/m , after 24 hours 31 20 15 10 7 4 1 1 0.510.5 11 4.5
4 k m, after 2 hours 39 25 20 13 9 6 2 2 1/1 14 5.5
k m, after 6 hours 25 16 12 7 5 3 1 1 0.5/0.5 9 3.5
4 k m , after 24 hours 20 12 9 6 4 3 1 1 0.5/0.5 8 2
Table 21
Q'Break Testing at 3 C frid e on PTS containing Ketzan XCD 0.75 lm3-RheoIog o
3 C
Q'Break, kg/m 600 300 200 100 60 30 6 3 Gels, PV, YP,
rpm r m rpm rpm rpm rpm r m rpm Pa cP Pa
None 74 52 43 30 23 16 7 5 2.5/3 22 15
2 k m, after 3 hours 54 35 27 17 12 8 3 2 1/1 19 8
2 kg/m , after 6 hours 40 25 19 12 9 5 2 1 0.5/0.5 15 5
4 k/m, after 2 hours 47 31 23 15 11 7 2 2 1/1 16 7.5
4 k , atter 6 hours 38 24 17 11 8 5 2 1 0.5/0.5 14 5
Table 22
Emutsion Breakin using both Q'Break 2 k/m3, let sit 3 hours then add
demuisifier. Testin at 23 C.
Demutsifler Conc., Notes on emulsion behaviour - 250 mL sample in a graduated
glass cylinder.
um'
None Emulsion is siowty breaking. There is a a layer of -12 mL of very dark
fluid on top after 3 hours.
Large oil drops form and accumulate towards top of fluid.
(Blank) After 48. hours the sample shows a very good oil separation. After 1
week there is the oil layer on
top, clear water phase in the middle and solids layer on bottom.
RD2069 I Uppon mixing the RD2069 demuisifier, there was a stringy, gummy
precipitate formed. Otherwise,
the sample looks similar to the blank but having smaller oil drops
accumulating towards the top.
Demulsifier cannot be used due to chemical incom atibiti with mud components
reci itation .
T2005 1 Emulsion seems to very slowly break. There is a a layer of -9 mL of
very dark fluid on top with a
definite separation from the lighter layer beneath after 3 hours, However, the
rest of the fluid
shows no sign of forming visible oil drops.
After 48 hours the sample shows the least oil separation of all. After I week
the is a layer of oil
separated but the rest of the fluid is muddy and seems to contain traces of
oil.
JC91-68 1 Emulsion is siowty breaking. There is a a layer of -12 mL of very
dark fluid on top after 3 hours.
Large oil drops form and accumulate towards top of fluid.
After 48 hours the sample shows a very good oN separation same as the blank.
After I week there is the oii layer, clear water phase and solids layer
similar to the blank.
Ozreral2 the polymer system containing the Kelzan XCD in a
concentration of 0.75 kg/m3 provided preferred rheology, fluid
loss and cleansing of tar sands.
CA 02481543 2004-09-14
23 9-15652-2CA
FIELD EXAMPLE
In January/February of 2004, six wells were drilled which
used the PolyTar drilling fluid system in part of the
drilling operation. The wells, located in 84-11 W4 in
Alberta Canada, were horizontal in nature with the
intermediate and main horizontal tar sands drilled with
Polytar. The nature of sand was one of - 23 v/v% bitumen
contained within a - 3 milliDarcy permeable poorly
consolidated matrix.
Typical drilling conditions with Polytar are - 400 meters of
drilled 311 mm intermediate hole with casing set at 900
inclination from vertical. The 222 mm horizontal section was
- 600 meters in length. The following table highlights some
of the Polytar drilling parameters as compared to other
water-based muds used in the same 84-11 W4 area.
Table 23
Drilling Fluid Performance of Bitumen Laden Sands
System(year) # of Average m Average Average Typical shaker
wells drilled days to TD mud cost screen design
K2SO4 polymer 4 1077 4.8 $27,755 38 * 38 * 38
(1998) K2S04 polymer 6 1357 4.6 $10,280 38 * 38 *38
(1998)
KC1 polymer 4 1505 8.8 $43,907 84 * 50 * 38 *20
(2003) 140 * 110 * 84 *50
Polytar 6 1078 3.9 $22,531 210*175*175*145
(2004) 210*210*180*145
The data shows that the Polytar system has been cost
effective. Days to total depth were similar to the 6 well
proj ect using K2S04 polymer and faster than the KC1 polymer
CA 02481543 2004-09-14
24 9-15652-2CA
and K2SO4 polymer (4 wells) groupings. Drilling fluid costs
for the Polytar system were also very competitive.
The average shaker screen sizes used on the Polytar system
were much finer than those used on the other three system
groupings. The potassium based systems, which used the
larger screen sizes, were designed to carry the insoluble
bitumen to surface intact. Typical of these potassium
systems however, the bitumen accretes onto metallic surfaces.
The shaker screens become less effective when accretion
occurs, thus the need for larger screen openings.
The Polytar system solubilizes at least part of the bitumen
into the drilling fluid system, thus eliminating accretion
and increasing the efficiency of the shaker screens. As a
result, cleaning of the drilling fluid system of drilled sand
is improved. The sand collected from the shaker screen from
the bitumen laden drilled solids contained typically less
than 0.5% v/v oil.
The Polytar wells at 84-11 W4 employed centrifuges for
additional drilling fluids cleaning functions. In general,
the sand coming from the centrifuge underflow was clean
enough to meet mix-bury-cover regulations within Alberta.
The following tables set out the analyses received from
centrifuge underflows at 700 m and 800 m measured depths.
CA 02481543 2004-09-14
25 9-15652-2CA
Table 24:
Hydrocarbon content from Centrifuge Underflows with Polytar
Subsoil Density = 1820 kg/m3; soil:waste mix ratio 3:1
Waste Densities = 2020 and 1975 kg/m3 for 700m and 800m
700m Analyses 800 m Analyses Closure Criteria
Benzene 0 0 0.073
Toluene 0 0 0.86
Ethylbenzene 0 0 0.19
Xylenes 0 0 25
Fraction 1 0 0 260
Fraction 2 170 216 900
Fraction 3 169 212 800
Fraction 4 68 - 85 5600
Total HC`s 407 513
Although embodiments of the invention have been
described above, it is limited thereto and it will be
apparent to those skilled in the art that numerous
modifications form part of the present invention insofar as
they do not depart from the spirit, nature and scope of the
claimed and described invention.
30
