Patent Abstract:
A drilling fluid for use in high oil viscosity formations containing tar, sand and oil entrained therein. The drilling fluid can be comprised of a polymer in an amount from between 0.05% and 5% by volume, a solvent in an amount from between 1% and 20% by volume and de-emulsifier in an amount from between 0.05% and 10% by volume.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]    This application claims the benefit of U.S. Provisional Application No. 60/460,878, filed Apr. 8, 2003. 
     
    
     
       FIELD OF THE INVENTION  
         [0002]    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.  
         BACKGROUND OF THE INVENTION  
         [0003]    In the existing technology, there is a wide variety of documents relating to drilling fluids and related materials.  
           [0004]    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.  
           [0005]    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.  
           [0006]    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.  
           [0007]    Various amines have also been used to augment drilling fluid and provide a variety of advantages in different operating conditions.  
           [0008]    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.  
         SUMMARY OF THE INVENTION  
         [0009]    One object of the present invention is to provide an improved drilling fluid which is not limited as the prior art compositions.  
           [0010]    A further object 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:  
           [0011]    a water base viscosifying polymer in an amount from between 0.05% and 5% by volume;  
           [0012]    a solvent in an amount from between 1% and 20% by volume; and  
           [0013]    a de-emulsifier in an amount from between 0.05% and 10% by volume.  
           [0014]    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.  
           [0015]    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 wide temperature range. In fact, the emulsion is broken in the absence of energy input, a significant feature.  
           [0016]    A still further object of one embodiment of the present invention is to provide a method of recovering oil from tar sands containing tar, oil and sand, comprising:  
           [0017]    providing a composition containing a polymer, solvent for solving oil and tar from said tar sands and an emulsifier;  
           [0018]    mixing compounds of said composition;  
           [0019]    treating the tar sands with the composition to remove sand from the tar sands;  
           [0020]    forming an emulsion with oil contained in treated tar sands where the emulsion is oil in water emulsion; and  
           [0021]    de-emulsifying, under either energized or static conditions, the emulsion to release the oil as a separate phase from the water.  
           [0022]    The composition in use has easily maintainable rheology and filtration control over a broad range of downhole operations. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0023]    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.  
         [0024]    Experiment 1  
         [0025]    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/m 3  in Kim Mud improves the clumping of tar sand oil and prevents the stickiness of the oil to the testing container.  
         [0026]    Experiment 2  
         [0027]    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.  
         [0028]    Experiment 3  
         [0029]    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.  
         [0030]    Experiment 4  
         [0031]    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/M 3 .  
         [0032]    EZ Drill and EZ Drill II appeared to soften the tar sand, although no obvious sign of dissolvability of tar sand was noticed.  
         [0033]    Tork-trol II and EZ Slide produced no change in the tar sand appearance.  
         [0034]    Experiment 5  
         [0035]    Stable K mud, Gel Chem mud, Stable K/K 2 SO 4  mud and Polymer mud were evaluated for their ability to prevent blinding/sticking of bitumen from tar sands to screens. The testing temperature 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.  
         [0036]    No blinding/sticking of bitumen to any screen occurred with any of the muds. The bitumen behaved the same in each mud.  
         [0037]    Experiment 6  
         [0038]    Various additives were tested in Polymer mud, Stable K mud and K 2 SO 4 /Gel mud to select the best combination that water wets the shaker screen and prevents sticking of tar sands to screen.  
         [0039]    Drilltreat at 5L/m 3  was the best additive improving the water wetting ability of all muds. K 2 SO 4  worked similar in a Gel mud and less in Polymer mud. Q&#39;Flow (Glycol) produced a softening of tar sands and dissolved some of the tar.  
         [0040]    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.  
         [0041]    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 equipment and shaker screen blinding was prevented with the new drilling fluid by removing the tar from the sand.  
         [0042]    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.  
         [0043]    Experiment 7  
         [0044]    The experiment relates to tests performed to select the organic solvent.  
         [0045]    In order to find the best tar remover, over 50 products were tested at various concentrations. Q&#39;Clean™ was selected as the best tar remover. Generally speaking, the product comprises hydrogenated heavy petroleum naphtha together with an organic solvent.  
         [0046]    While Q&#39;Clean™ 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.  
         [0047]    No emulsifiers were required. Testing showed that emulsifiers had an adverse reaction by creating too small a drop of Q&#39;Clean™ in the drilling fluid reducing its ability for cleaning the sand.  
         [0048]    The new drilling fluid, Polymer/Stable K/Q&#39;Clean™ was effective in removing the tar from the sand over a large range of temperatures, namely 5-30° C.  
         [0049]    Experiment 8  
         [0050]    This experiment sets forth work done to evaluate the performance of drilling fluid on a different sample of tar sands.  
         [0051]    The Polymer/Stable K/Q&#39;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&#39;Clean™ fluid worked very well; the tar sand was cleaned at the temperature range indicated.  
         [0052]    Experiment 9  
         [0053]    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.  
         [0054]    The project had 3 parts:  
         [0055]    designing and testing for the optimum formulation of drilling fluid with regards to tar removing ability;  
         [0056]    testing the likely contaminants on the fluid to see if any fluid formulation adjustment is required; and  
         [0057]    testing for emulsion breaking and oil phase separation for fluid disposal at the end of the well.  
         [0058]    A new drilling fluid formulation containing Polymers/sized Calcium Carbonate/Q&#39;Clean™ was designed and tested. Various viscosifiers were tested at different concentrations with regards to mud rheology, cleaning ability and effect on emulsion breaking.  
         [0059]    The following fluid formulation was selected for its good rheology, fluid loss and tar sand cleaning ability:  
                                             PolyTar ™ System                                    Kelzan XCD   0.75 kg/m 3             Staflo R     2 kg/m 3             Starpak DP     6 kg/m 3             Calcarb 325     10 kg/m 3             Calcarb 0     10 kg/m 3             Caustic Soda   pH 10           Q&#39;Clean ™   5% v/v                      
 
         [0060]    Date illustrating the effectiveness will be presented herein after.  
         [0061]    Contaminants testing on the drilling fluid showed minimal effects on its rheology and cleaning ability. Thus, gypsum and salt (NaCl) 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 off of the extra 6% v/v tar sand added.  
         [0062]    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&#39;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.  
         [0063]    Breaking the emulsion of PolyTar™ System was attempted in three ways:  
         [0064]    1. By making use of chemical demulsifiers. Eight demulsifiers were tested with no good results;  
         [0065]    2. Making use of non-emulsifiers (two products) in the mud formulation to prevent the forming of a stable emulsion; and  
         [0066]    3. Using a polymer breaker (four products, enzymes and bleach) to reduce the fluid viscosity and speed up the oil separation.  
         [0067]    Q&#39;Break™ (enzyme) at concentration of 2 kg/mr 3  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&#39;Clean™+Tar) separates on top of fluid. After the treatment with Q&#39;Break™ 2 kg/m 3  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&#39;Clean™ and dissolved Tar) was separated from the mud as a top layer and could be skimmed off.  
         [0068]    Q&#39;Break” is an enzyme that works well at low temperatures, however, higher concentrations are recommended. Also, the product is safe and environmentally friendly.  
         [0069]    A new approach to tar sand drilling resulted in development of a new drilling fluid addressing specific problems encountered in SAGD drilling projects.  
         [0070]    The new drilling fluid was designed to solve the problem of 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.  
         [0071]    Tables 1 and 2 set forth data and observations noted.  
         [0072]    In respect of the drilling fluid composition, the following procedure was observed.  
         [0073]    Various additives at various concentrations were added to water to examine the capacity to remove tar and clean the sand.  
         [0074]    200 ml of the testing fluid received 20 g of tar sands.  
         [0075]    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.  
         [0076]    Table 1 tabulates the data and observations noted  
                                                                     TABLE 1                           Fluid Additive selection            Additive &amp; concentration               in water   WTS, g   Visual observations               Blank (water)   19.580   Tar sands appeared unchanged. Fluid phase 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   Similar 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               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 3     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 3     21.940   No significant improvement.       Beta Cyclod. @ 20 kg/m 3     20.600   No significant improvement. Noticeable is the fact that 20 kg/m 3  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 oily film and a ring 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 agitation. The fluid phase is similar to the one above.       Mudd Lite @ 2% v/v   20.885   Tar sands appeared unchanged. Fluid phase is tan in colour and has a layer of foam on top.       Mudd Lite @ 6% v/v   19.962   Similar to Mudd Lite @ 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 unchanged. Fluid phase is clear.       E X1501 @ 3% v/v   20.670   There is a very small amount of clean sand. The tar sand left seems to remain in same size               pieces. In water, this additive coagulated in a cream-yellow layer that separates on top of the               fluid phase when at rest.       E 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 small 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 liquid 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. There is a               thin film of oil on top of fluid phase.       E X1557 @ 1% v/v   20.557   Similar to above test, just that on the sand grains are not quite as clean.       E X1557@ 5% v/v       Same 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 light tan in colour and contains few tar particles suspended.       E X 109 @ 3% v/v   19.282    ˜75% of tar sand is completely clean. The rest of tar sand is in pieces looking unchanged.               Under the microscope 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% v/v   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 emulsion.       S DN120 @ 3% v/v   20.322   There is less than 1% of clean sand. The tar sand left seems to remain in same size pieces.               The fluid phase is clean and clear.       S DN114 @ 3% v/v   19.820   As above       S DN121 @ 3% v/v   20.026   ˜15-20% of sand is clean. The rest appears unchanged. The fluid phase is milky-gray in               colour.       S DN87 @ 3% v/v   20.735    ˜75% of sand is completely clean. The rest of tar sand is in fairly small pieces. Under the               microscope 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.       S DN76 @ 3% v/v   21.028   Most of tar sand (˜75%) is a flowing sludge on the bottom of beaker. There are a few pieces               of tar sand       DT78 @ 3% v/v   20.782   ˜80-90% of sand is fairly clean but the oil is not emulsioned and just lays and sticks to the               sand layer.       DG56 @ 3% v/v   20.980   There is less than 1% of clean sand. The tar sand left seems to remain in same size pieces.               The fluid phase is clean and clear.       M38 @ 3% v/v   20.853    ˜50% of sand is fairly clean and the other 50% is left small tar sand pieces. The fluid phase               is oil in water emulsion.       M150 @ 3% v/v   19.320    ˜50% of loose sand, dark, still coated with oil. The rest of tar sand seems to remain in same               size pieces. The fluid phase is dark       M192 @ 3% v/v   20.962    ˜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               film of oil on top.       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 appears 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       P2-181-9 @ 1% v/v   20.386    ˜50% of sand is fairly clean and the other 50% is left small tar sand pieces. The fluid phase               is an emulsion.       P2-181-11B @ 1% v/v   20.408   ˜15-20% of sand is clean. The rest appears unchanged.       P2-181-15B @ 1% v/v   20.560    ˜50% of sand is fairly clean and the other 50% is left small tar sand pieces. The fluid phase               is an emulsion.       P2-181-19B @ 1% v/v   21.300   Complete balling of tar sands that became soft (it incorporated water) and sticky.       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 appears unchanged.       Travis 2704 @ 1% v/v   20.982   Tar sands appeared unchanged. Fluid phase is clear.                    Drilling Fluid selection - Polymer/Stable K system            Additive &amp; concentration               In drilling fluid   WTS, g   Visual Observations               Blank (Poly./Stable K)       E XZ1557 @ 1% v/v   20.634   Tar sands appeared unchanged. Fluid phase contains small tar particles suspended.       E XZ1557 @ 3% v/v   20.049    ˜40% of tar sand remained on the 30 mesh screen as small and large pieces. Dark fluid               phase of oil in water emulsion.       Xylene/Isopropanol   20.250   Tar sands appeared unchanged. Fluid phase contains small tar particles suspended.       @ 3% v/v       Diesel @ 3% v/v   20.975   There is a small amount of loose sand. Tar sand left remained in same size pieces. Fluid               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 + XZ1557   20.078   Tar sands appeared unchanged. The oil is emulsioned as extremely small drops that could       @ 3% v/v       not contact the tar sands and is fairly clean.       BDD100 @ 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.       E X1577 @ 3% v/v   20.490   Tar sands appeared unchanged. Fluid phase contains small tar particles suspended.       E X1421 @ 3% 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.       Solvent @ 3% v/v + XZ1557   20.942   Some clean sand grains seen under microscope. Most tar sand is left uncleaned as small       @ 1% v/v       pieces.       Solvent @ 10% v/v   20.631   Cleaned most of sand. Mixture is poured on a 30 mesh screen. ˜10% of tar sand remained               on the screen. Can see the clear - clean sand grains suspended in the fluid and the dark oil               drops. Fluid phase is very dark due to the dissolved oil.       Solvent @ 10% v/v + Rev   20.17    &lt;5% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase       Dust 4% v/v       containing almost completely clean sand.       Solvent @ 7% v/v + Rev   20.353    ˜5-7% of tar sand left on the 30 mesh screen. The rest as above.       Dust 4% v/v       M192 @ 5% v/v   20.824    ˜70% of tar sand remained on the 30 mesh screen as small and large pieces. Dark fluid               phase.       Amodrill 1400 @ 10% v/v   20.560    ˜30% of tar sand remained on the 30 mesh screen as small and large pieces. Dark fluid               phase.       Emulam D30 @ 5% v/v   20.106   ˜100% of tar sand remained on the 30 mesh screen as unchanged small and large pieces.       Cut Clean @ 5% v/v   20.929    ˜30% of tar sand remained on the 30 mesh screen as small and large pieces. Dark fluid               phase.                    Drilling Fluid selection - Gel Chem system            Additive &amp; concentration               in drilling fluid   WTS, g   Visual Observations               Blank (Gel Chem sys.)   20.651   Tar sands appeared unchanged. Fluid phase contains small tar particles suspended.       Tar Solvent @ 10% v/v   20.920    ˜20% of tar sand remained on the 30 mesh screen as small and large pieces. Dark fluid               phase with fairly clean sand suspended.       Tar Solvent @ 10% v/v + Rev   20.700   As above.       Dust @ 4% v/v               Additive concentration and       mixture temperature   WTS, g   Visual Observations               Tar Solvent @ 20% v/v-   20.878    ˜10% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase       5° C.       containing almost completely sand.       Tar Solvent @ 10% v/v-   19.968    ˜50% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase.       10° C.       Tar Solvent @ 15% v/v-   20.261    ˜20% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase.       10° C.       Tar Solvent @ 20% v/v-   20.325    ˜10% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase       10° C.       containing almost completely sand.       Tar Solvent @ 15% v/v-   20.380    ˜20% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase.       15° C.       Tar Solvent @ 20% v/v-   20.375    ˜10% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase       15° C.       containing almost completely sand.       Tar Solvent @ 10% v/v-   20.713    ˜5% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase       20° C.       containing almost completely sand.       Tar Solvent @ 10% v/v-   20.532   As above       25° C.       Tar Solvent @ 10% v/v-   20.342    ˜3% of tar sand left on the 30 mesh screen as small and soft pieces. Dark fluid phase       30° C.       containing almost completely sand.                  
 
         [0077]    In connection with the fluid testing, the following procedure was involved.  
         [0078]    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.  
         [0079]    The test was repeated in a temperature range of between 5 and 30° C.  
                             TABLE 2                           Tar sands from 397.4 m depth - Drilling fluid testing            Solvent concentration in               drilling fluid       and test temperature   WTS, g   Visual Observations               15% v/v Solvent &amp; 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 (˜3 mm diameter).               Dark fluid phase containing completely clean sand       20% v/v Solvent &amp; 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 (˜3 mm diameter). Dark               fluid phase containing completely clean sand       10% v/v Solvent &amp; 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 &amp; 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 &amp; 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 &amp; 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 &amp; 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 &amp; 20° C.   20.389    ˜3% of tar sand left on the 30 mesh screen as small size pieces. The rest               is as above.        0% v/v Solvent &amp; 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 &amp; 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 (˜3 mm diameter).               Dark fluid phase containing completely clean sand       10% v/v Solvent &amp; 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 &amp; 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 (˜3 mm diameter). Dark fluid phase containing               completely clean sand.                                  
 
         [0080]    In all the above tests where the new drilling fluid 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.  
         [0081]    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.  
         [0082]    Tables 3 through 22 tabulate data for different polymer systems together with specific listing for each.  
         [0083]    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  
                                                             Polymer System A       Polymer System B                Additive   Concentration   Additive   Concentration               Kelzan   1.5 kg/m 3     Kelzan   2 kg/m 3         XCD ®       XCD ®       Staflo ® R    2 kg/m 3     Staflo ® R   2 kg/m 3         Starpak ®    6 kg/m 3     Starpak ®   6 kg/m 3         DP       DP       Calcarb   10 kg/m 3     Calcarb   10 kg/m 3         325       325       Calcarb 0   10 kg/m 3     Calcarb 0   10 kg/m 3         Caustic   pH 10   Caustic   pH 10       Soda       Soda                          
 
         [0084]    [0084]                                                                     TABLE 3                           Mud Formulation Testing - Rheology and API fluid loss at 23° C.                                                Gels,   PV,   YP,   FL,       Formulation   600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   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% Q&#39;C    66   49   41   30   24   18    8    7   3.5/4.0   18   16.0   12.0       A + 5% Q&#39;C    70   52   43   32   25   18    9    8   4.0/4.5   18   17.0    9.8       A + 10% Q&#39;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   4.5/5.0   23   27.5   11.2       B + 2.5% Q&#39;C   105   81   69   52   41   30   13   11   5.0/5.5   24   28.5   11.0       B + 5% Q&#39;C   110   84   72   54   43   31   14   11   5.5/5.5   26   29.0   12.4       B + 10% Q&#39;C   115   89   75   57   46   33   15   12   6.0/6.0   26   31.5    9.0                    
         [0085]    [0085]                                                                                 TABLE 4                           Tar Sand Cleaning at 23° C.                Weight, g   Tar sand            Fluid   Tar       Residue   Residue   cleaned,       Formulation   sand   Dish   &amp; Dish   &gt;30 mesh   % wt.                    A   27.131   1.060   23.013   21.953   19.1       A + 2.5% Q&#39;C   27.122   1.000   7.890   6.890   74.6       A + 5% Q&#39;C   27.300   1.033   2.112   1.079   96.0       A + 10% Q&#39;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&#39;C   27.473   1.038   8.375   7.337   73.3       B + 5% Q&#39;C   27.457   1.031   2.718   1.687   93.9       B + 10% Q&#39;C   27.295   1.038   2.273   1.235   95.5                    
         [0086]    [0086]                                                                                                                   TABLE 5                           Contaminants Testing on the PolyTar System (PTS = A + 5% Q&#39;C).       Rheology at 23° C.                                                Gels,   PV,   YP,       Sample   600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    PTS   64   47   39   28   23   16   8   6   3.0/3.5   17   15       PTS + 5 kg/m 3     48   35   29   20   16   12   5   4   2.5/2.5   13   11       Gypsum       PTS + 1 kg/m 3  Lime   64   47   39   28   23   16   8   6   3.0/3.5   17   15       PTS + NaOH for pH12   62   46   38   28   22   15   7   5   3.0/3.0   16   15       PTS + 5 kg/m 3  NaCl   56   41   34   24   19   13   6   5   2.5/3.0   15   13       PTS + 10 kg/m 3  NaCl   54   39   32   23   18   13   6   5   2.5/3.0   15   12       PTS + 20 kg/m 3  NaCl   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       Sand                    
         [0087]    [0087]                                           TABLE 6                           Contaminants Testing on the PolyTar System       (PTS). API fluid loss                    FL,           Sample   mL                            PTS   10           PTS + 5 kg/m 3  Gypsum   9.5           PTS + 1 kg/m 3  Lime   10           PTS + 5 kg/m 3  NaCl   9.5           PTS + 10 kg/m 3  NaCl   9           PTS + 20 kg/m 3  NaCl   8           PTS + 6% vol. Tar Sand   6                        
         [0088]    [0088]                                                                                 TABLE 7                           Tar Sand Cleaning in contaminated fluid at       23° C. - 5% vol. Tar Sand in the Fluid Sample                    Tar           Weight, g   sand                Tar       Residue   Residue   cleaned,       Fluid Sample   sand   Dish   &amp; Dish   &gt;30 mesh   % wt.                    PolyTar System (PTS)   27.300   1.033   2.112   1.079   96.0       PTS + 5 kg/m 3  Gypsum   27.611   1.002   2.882   1.880   93.2       PTS + 1 kg/m 3  Lime   27.273   1.027   2.527   1.500   94.5       PTS + 5 kg/m 3  NaCl   27.458   0.998   5.720   4.722   82.8       PTS + 10 kg/m 3  NaCl   27.397   1.004   6.278   5.274   80.7       PTS + 20 kg/m 3  NaCl   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                    
         [0089]    [0089]                                           TABLE 8                           PolyTar System/Dissolved Tar Emulsion Breaking at       23° C. - Removal of dissolved tar.                Conc.,           Demulsifier   L/m 3     Notes on emulsion behaviour                    None       Oil drops are small but visible with naked eye. The oil in water emulsion is stable. it does not               break in over 8 hours. After 24 hours there is a very small amount of free oil on top of fluid.       T2001   1   Oil drops are not visible with naked eye. Under the microscope they look 2-3 times smaller than           2   they were initially. The oil in water emulsion became more stable. It does not break in over 24               hours. There is no free oil on top of fluid.       T2005   1   Oil drops are not visible with naked eye. Under the microscope they look 2-3 times smaller than           2   they were initially. The oil in water emulsion became more stable. It does not break in over 24               hours. There is no free oil on top of fluid.       T2007   1   Oil drops are not visible with naked eye. Under the microscope they look 2-3 times smaller than           2   they were initially. The oil in water emulsion became more stable. It does not break in over 24               hours. There is no free oil on top of fluid.       T2508   1   Oil drops are not visible with naked eye. Under the microscope they look 2-3 times smaller than           2   they were initially. The oil in water emulsion became more stable. It does not break in over 24               hours. There is no free oil on top of fluid.       NE 125   0.5   Oil 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   Oil 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                    
         [0090]    [0090]                             TABLE 9                           PolyTar System/Dissolved Tar Emulsion - Preventing forming       a stable emulsion using non-emulsifiers (23° C.).                Conc.,           Non-emulsifier   L/m 3     Notes on emulsion behaviour               None       Oil drops are small but visible with naked eye. The oil in water emulsion is stable. It does not               break in over 8 hours. After 24 hours there is a very small amount of free oil on top of fluid.       NE 125   1   Oil drops are not visible with naked eye. Under the microscope they look 2-3 times smaller than           2   they were initially. The oil in water emulsion became more stable. It does not break in over 24               hours. There is no free oil on top of fluid.       NE 723   1   Oil drops are not visible with naked eye. Under the microscope they look 2-3 times smaller than           2   they were initially. The oil in water emulsion became more stable. It does not break in over 24               hours. There is no free oil on top of fluid.                    
         [0091]    [0091]                                                                                 TABLE 10                           Tar Sand Cleaning at 23° C. - PTS cleaning ability       when using non-emulsifiers at 1 L/m 3 .                Weight, g   Tar sand                Tar       Residue   Residue   cleaned,       Non-emulsifier   sand   Dish   &amp; Dish   &gt;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                    
         [0092]    [0092]                                                                                                                           TABLE 11                           Viscosifier selection to prevent forming a stable PolyTar System/       Dissolved Tar Emulsion - Polymer (Viscosifier)       Testing in PolyTar System - Rheology at 23° C.                                                    Gels,   PV,   YP,       Viscosifier   kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    Kelzan XCD   1.5   70   52   43   32   25   18   9   8     4/4.5   18   17       Biovis   1.5   54   37   29   18   13    8   3   2     1/1.5   27   5       Biovis   3   73   53   44   33   27   20   10    8   4.5/6.5   20   16.5       Geovis XT   1.5   71   51   42   32   25   19   10    9   5/7   20   15.5       HEC   1.5   92   70   58   43   33   23   9   7   3.5/3.5   22   24       Xanvis   1.5   60   43   36   26   20   15   7   6     3/3.5   17   13                    
         [0093]    [0093]                                                                                 TABLE 12                           Tar Sand Cleaning at 23° C. - PTS cleaning ability       when using viscosifiers and concentrations above mentioned.                Weight, g   Tar sand                Tar       Residue   Residue   cleaned,       Viscosifier   sand   Dish   &amp; Dish   &gt;30 mesh   % wt.                    Kelzan XCD   27.300   1.033   2.112   1.079   96.0       Biovis - 1.5   27.345   1.009   5.076   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   4.638   3.636   86.7                    
         [0094]    [0094]                                           TABLE 13                           Viscosifier selection to prevent forming a       stable PolyTar System/Dissolved Tar       Emulsion - Testing at 23° C.                Conc.,           Viscosifier   kg/m 3     Notes on emulsion behaviour within 6 hours                    Kelzan XCD   1.5   The oil in water emulsion is less stable.               Emulsion is slowly breaking. There is a bit               of free oil on top of fluid after 6 hours. This               sample looks the best.       Biovis   3   The oil in water emulsion is stable. No sign of               emulsion breaking in 6 hours.               There is no free oil on top of fluid.       Geovis XT   1.5   The oil in water emulsion is stable. No sign of               emulsion breaking in 6 hours.               There is no free oil on top of fluid.       HEC   1.5   The oil in water emulsion is stable. No sign of               emulsion breaking in 6 hours.               There is no free oil on top of fluid.       Xanvis   1.5   The oil in water emulsion appears less stable.               Emulsion is slowly breaking. There are traces               of free oil on top of fluid after 6 hours.               This sample is the next best.                    
         [0095]    [0095]                                                                                                                   TABLE 14                           Polymer Breaker Testing on PTS containing Kelzan       XCD @ 1.5 kg/m 3  - Rheology       after 24 hours @ 23 ° C.            Breaker &amp; conc.,                                   Gels,   PV,   YP,       kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    None   66   48   41   30   24   17   8   6     3/3.5   18   15       Q&#39;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       Bleach, 5 L/m 3     26   17   13    9    7    5   2   2   1/1    9   4                                    
         [0096]    An adjusted polymer system was then reviewed.  
                                                 Adjusted PolyTar System formulation (less viscosifier)            Additive   Concentration   Additive   Concentration               Kelzan   .75 kg/m 3     Xanvis ®   1 kg/m 3         XCD ®       Staflo ® R    2 kg/m 3     Staflo ® R   2 kg/m 3         Starpak ®    6 kg/m 3     Starpak ®   6 kg/m 3         DP       DP       Calcarb   10 kg/m 3     Calcarb   10 kg/m 3         325       325       Calcarb 0   10 kg/m 3     Calcarb 0   10 kg/m 3         Caustic   pH 10   Caustic   pH 10       Soda       Soda       Q&#39; Clean   5% vol.   Q&#39; Clean   5% vol.                  
 
         [0097]    [0097]                                                                                                                           TABLE 15                           PolyTar System/Dissolved Tar Emulsion (5% vol. Tar Sand       in the mud) - Rheology at 23° C.                                                    Gels,   PV,   YP,       Viscosifier   kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    Kelzan 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                    
         [0098]    [0098]                                                       TABLE 16                           Tar Sand Cleaning at 23° C. - PTS cleaning ability when       using viscosifiers and concentrations above mentioned.                Weight, g   Tar sand                Tar       Residue   Residue   cleaned,       Viscosifier   sand   Dish   &amp; Dish   &gt;30 mesh   % wt.               Kelzan XCD   27.397   1.059   4.116   3.057   88.8       Xanvis   27.512   1.040   5.076   4.378   84.1                    
         [0099]    [0099]                                                                                                                   TABLE 17                           Polymer Breaker Testing on PTS containing Kelzan       XCD @ 0.75 kg/m 3  - Rheology       after 2 hours @ 23° C.            Breaker &amp; conc.,                                   Gels,   PV,   YP,       kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    None   58   42   34   24   18    12    5   4   2/2   16   13       Q&#39;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   0.5/0.5   10   3.5       Bleach, 5 L/m 3     56   36   27   17   13    8   3   2   1/1   20   8                    
         [0100]    [0100]                                                                                                                   TABLE 18                           Polymer Breaker Testing on PTS containing       Xanvis @ 1 kg/m 3  - Rheology       after 2 hours @ 23° C.            Breaker &amp; conc.,                                   Gels,   PV,   YP,       kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    None   62   46   38   27   21   15   6   5   2.5/3     16   15       Q&#39;Break, 2   44   28   22   14   10    7   3   2   1/1   16   6       Chembreak HC, 3   41   28   22   15   11    7   3   2   1/1   13   7.5       Bleach, 5 L/m 3     69   47   38   25   19   13   5   4     2/2.5   22   12.5                    
         [0101]    [0101]                                                   TABLE 19                           Retort Test on PolyTar System/Dissolved Tar       Emulsion (5% vol. Tar Sand in the mud)            Sample from               ½ height of emulsion       Total       in 250 mL graduated   Retort content, % v/v   Hydrocarbons Content            cylinder after 24 hours   Oil   Water   Solids   (Core Labs), % v/v               Blank (no ECA)   5   94   1           Q&#39;Break 2 kg/m3   2   97   1   0.473       Q&#39;Break 4 kg/m3   1   99   0   0.492                    
         [0102]    [0102]                                                                                                                   TABLE 20                           Q&#39;Break Testing at 23° C. (room) on PTS containing Kelzan       XCD @ 0.75 kg/m3 - Rheology @ 23° C.            Q&#39;Break                                   Gels,   PV,   YP,       kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    None   58   42   34   24   18    12    5   4   2/2   16   13       2 kg/m 3 , after 2 hours   40   26   20   13   9   6   2   2   1/1   14   6       2 kg/m 3 , after 6 hours   36   23   18   11   8   5   2   1   0.5/0.5   13   5       2 kg/m 3 , after 24 hours   31   20   15   10   7   4   1   1   0.5/0.5   11   4.5       4 kg/m 3 , after 2 hours   39   25   20   13   9   6   2   2   1/1   14   5.5       4 kg/m 3 , after 6 hours   25   16   12    7   5   3   1   1   0.5/0.5    9   3.5       4 kg/m 3 , after 24 hours   20   12    9    6   4   3   1   1   0.5/0.5    8   2                    
         [0103]    [0103]                                                                                                                   TABLE 21                           Q&#39;Break Testing at 3° C. (fridge) on PTS containing Kelzan       XCD @ 0.75 kg/m3 - Rheology @ 3° C.                                                Gels,   PV,   YP,       Q&#39;Break, kg/m 3     600 rpm   300 rpm   200 rpm   100 rpm   60 rpm   30 rpm   6 rpm   3 rpm   Pa   cP   Pa                    None   74   52   43   30   23   16    7   5   2.5/3     22   15       2 kg/m 3 , after 3 hours   54   35   27   17   12   8   3   2   1/1   19   8       2 kg/m 3 , after 6 hours   40   25   19   12    9   5   2   1   0.5/0.5   15   5       4 kg/m 3 , after 2 hours   47   31   23   15   11   7   2   2   1/1   16   7.5       4 kg/m 3 , after 6 hours   38   24   17   11    8   5   2   1   0.5/0.5   14   5                    
         [0104]    [0104]                             TABLE 22                           Emulsion Breaking using both Q&#39;Break 2 kg/m3, let sit       3 hours then add demulsifier. Testing at 23° C.                Conc.,           Demulsifier   L/m 3     Notes on emulsion behaviour - 250 mL sample in a graduated glass cylinder.               None       Emulsion is slowly breaking. There is a a layer of ˜12 mL of very dark fluid on top after 3 hours.       (Blank)       Large oil drops form and accumulate towards top of fluid.               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   1   Uppon mixing the RD2069 demulsifier, 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 incompatibility with mud components (precipitation).       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 1 week the is a layer of oil               separated but the rest of the fluid is muddy and seems to contain traces of oil.       JC91-6B   1   Emulsion is slowly 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 oil separation same as the blank.               After 1 week there is the oil layer, clear water phase and solids layer similar to the blank.                    
         [0105]    Overall the polymer system containing the Kelzan XCD® in a concentration of 0.75 kg/m 3  provided preferred rheology, fluid loss and cleansing of tar sands.  
       FIELD EXAMPLE  
       [0106]    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.  
         [0107]    Typical drilling conditions with Polytar are ˜400 meters of drilled 311 mm intermediate hole with casing set at 90° 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                # of   Average m   Average   Average   Typical shaker       System (year)   wells   drilled   days to TD   mud cost   screen design               K 2 SO 4  polymer   4   1077   4.8   $27,755    38 * 38 * 38       (1998)       K 2 SO 4  polymer   6   1357   4.6   $10,280    38 * 38 * 38       (1998)       KCl 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                  
 
         [0108]    The data shows that the Polytar system has been cost effective. Days to total depth were similar to the 6 well project using K 2 SO 4  polymer and faster than the KCl polymer and K 2 SO 4  polymer (4 wells) groupings. Drilling fluid costs for the Polytar system were also very competitive.  
         [0109]    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.  
         [0110]    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.  
         [0111]    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.  
                                                   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 700 m and 800 m                700 m 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&#39;s   407   513                  
 
         [0112]    The embodiments of the invention described above are intended to be exemplary only. The scope of the invention is therefore intended to be limited solely by the scope of the appended claims.

Technology Classification (CPC): 2