CATIONIC POLYMER DRILLING FLUID CAN SOMETIMES REPLACE OIL-BASED MUD

March 16, 1992
Thomas W. Beihoffer, David S. Dorrough, Calvin K. Deem, Donald D. Schmidt, Ronald P. Bray Amoco Production Research Tulsa A recently developed cationic polymer/brine drilling fluid (CBF) system, tested in a number of wells drilled in the U.S. and the North Sea, can replace oil-based fluids in certain applications. The field tests have shown CBF to be more inhibitive than other water-based muds used in the same areas. To date, the primary applications have been in large diameter hole sections
Thomas W. Beihoffer, David S. Dorrough, Calvin K. Deem, Donald D. Schmidt, Ronald P. Bray
Amoco Production Research
Tulsa

A recently developed cationic polymer/brine drilling fluid (CBF) system, tested in a number of wells drilled in the U.S. and the North Sea, can replace oil-based fluids in certain applications.

The field tests have shown CBF to be more inhibitive than other water-based muds used in the same areas. To date, the primary applications have been in large diameter hole sections drilled through Tertiary shales with high smectite clay content.

The CBF system uses a cationic polymer and potassium chloride for shale inhibition, starch for fluid loss control, and a biopolymer for rheology. Tests have been developed to quantitatively measure the concentrations of the inhibitive additives in the fluid, allowing the fluid to be run with a high degree of control.

Amoco Production Co. first used cationic drilling fluids in 1987 on a series of slim-hole core wells near Catoosa, Okla. Amoco Production Research developed the cationic drilling fluid for the special requirements of high-speed, slim-hole continuous coring.1 The success of the cationic drilling fluid on core wells led to the tailoring of the fluid to suit conventional drilling applications.

Most conventional drilling fluid systems are complicated and poorly understood. 2 3 Typical mud systems are often run "by the seat of the pants" without clearly established maintenance guidelines. The drilling industry needs simple, understandable drilling fluid systems. The CBF system has advantages over conventional drilling fluids in simplicity and can allow a level of control not found in conventional systems.

Oil-based drilling fluids offer the best performance for drilling reactive shale formations. However, environmental legislation now limits the use of oil-based fluids in many areas worldwide. There are a number of applications for inhibitive water-based fluids in areas where oil-based fluids may be environmentally restricted.

Many operators are willing to pay a premium for inhibitive water-based fluids because of the costs associated with disposal of oil-contaminated drill cuttings. Amoco's experience on a number of wells suggests that cationic drilling fluids may be able to replace oil-based drilling fluids in many applications.

FLUID DESIGN

Shales can become unstable when they react with water in the drilling fluid. These reactive shales contain clays that have been dehydrated over geologic time by overburden pressure. When the formation is exposed, the clays osmotically imbibe water from the drilling fluid. This leads to swelling of the shale, induced stresses, loss of mechanical strength, and shale failure.

Two possible methods of shale inhibition include the prevention of water from entering shale and the use of chemical additives to reduce the dispersion of clays in shale.

Oil-based muds prevent the transfer of water into shales because of a high salt concentration in the water phase of the fluid (25-35% calcium chloride).

The high salt concentration (low water activity) balances the effective salinity (water activity) of the shale and prevents the osmotic transport of water into the shale. This allows oil-based fluids to inhibit nearly all reactive shales.

In water-based muds, salts reduce the dispersion of clays and promote shale inhibition by shielding the negative charges on clays. This reduces the ability of the clay particles to repel each other and to disperse into water (e.g., bentonite is difficult to disperse into seawater). Potassium ions reduce clay hydration by binding clay plates together. High molecular weight anionic polymers are often used to encapsulate shales and reduce dispersion.

Conventional water-based drilling fluids are usually unable to contain enough salt to balance the activity of shale formations. The salt solubility, fluid density, and cost are limiting factors. This suggests that water-based fluids will always be less inhibitive than oil-based fluids.

POTASSIUM CHLORIDE

The development of the cationic polymer/brine fluid (CBF) began with the use of potassium chloride as the base of the system followed by other additives to improve shale inhibition and to provide the other properties (fluid loss control, rheology, etc.) for a successful drilling fluid.

The shale rolling test was used to measure the ability of drilling fluid formulations to inhibit shale.4 The test measures the ability of a fluid to prevent the dispersion of 50 g of shale granules that can pass through a 4-mesh screen and be retained by a 10-mesh screen. The test reports the weight percent of shale granules recovered on a 30-mesh screen after 16 hr of exposure in the fluid. The greater the shale recovery, the more inhibitive the fluid. The rolling tests were conducted on unviscosified drilling fluid formulations using shales (primarily Pierre and Catoosa shales) containing their natural moisture contents.4

The shale rolling test recovery profile indicates that increasing the concentration of KCl increases the amount of shale recovered (Fig. 1). This indicates that the potassium stabilizes shales by ion-exchanging into clay interlayers. The potassium ions are more effective than sodium ions at binding clays together because of their ability to fit more tightly into the negatively, charged "holes" in the interlayers (Fig. 2).4

Based on shale recovery test results, the inhibitive drilling fluid contains a base of 5-10% KCl. This range ensures that the potassium concentration is maintained on the plateau region of the recovery curve, giving the maximum benefit at a minimum KCl concentration.

CATIONIC AGENTS

The interactions of positive charged organic compounds with clays are well known; for example, cationic surfactants are adsorbed onto smectite clays to allow the clay to be dispersed in organic media, as in the manufacture of organophilic clays used in oil muds.5-7 This treatment prevents the clay from dispersing in water.

If such cationic additives were present in a water-based drilling fluid, the cationic additives could adsorb on the clay surfaces on the well bore and cuttings as they become exposed by the bit. The well bore and cuttings would then be resistant to dispersion in water.

This hypothesis was tested by evaluating cationic surfactants (similar to those used in oil-based muds) in the shale rolling test. The cationic surfactants were very effective in reducing the dispersion of shales but created severe foaming problems. The cationic polymers were then evaluated as shale inhibitors. The polymers have a cationic functionality similar to that of the surfactants, but they do not cause foaming problems (Fig. 3). The shale rolling test recovery profile for a cationic copolymer of epichlorohydrin and dimethyl amine in distilled water is shown in Fig. 4. Very low concentrations of the polymer (0.4%) give very high shale recoveries.

The positively charged amine polymer ion exchanges into the clay interlayers and displaces sodium ions in a manner similar to that observed with potassium. Unlike potassium ions, the cationic polymer possesses multiple active cationic sites that are connected together. This allows the polymer to bind the clays together more effectively than potassium ions.

Evidence for this mechanism is shown in X-ray diffraction data of sodium montmorillonite clay. The curve for dry clay has a d-spacing (12.59 A) that corresponds to one layer of water in the clay interlayers. When the clay sample is exposed to water, the clay disperses and loses its interlayer spacing. When the clay is exposed to a solution of cationic polymer in water, the clay does not disperse and a slight increase in d-spacing is noted (14.57 A). This increase is a result of the incorporation of cationic polymer into the clay interlopers.

Based on these tests, 0.4% of the cationic polymer was chosen as the cationic inhibitive agent for the drilling fluid. This level maintains the polymer concentration on the plateau of the recovery curve and provides a safety margin to help prevent sudden loss of inhibition in case of polymer depletion (Fig. 4).

The cationic polymer is a commercially available low molecular weight polymer used in waste water and drinking water clarification and treatment. A low molecular weight polymer was used so it would not contribute to fluid viscosity.

The combination of 10% KCl with 0.4% cationic polymer has a greater increase in shale recovery than either additive used alone (Fig. 5). Additionally, the shale granules obtained in the recovery tests had greater physical strength when exposed to the cationic polymer/KCl mixture than when exposed to either additive alone.

Oil-based muds result in shale recoveries of 95-100% in the rolling test. This suggests that the cationic polymer/KCl mixtures are inhibitive but not as inhibitive as oil-based muds.

RHEOLOGY

With the desired combination of KCl and cationic polymer determined, fluid loss control and viscosity additives were analyzed for compatibility with the cationic system.

Most conventional viscosity additives and fluid loss additives, such as bentonite, xanthan gum, and carboxymethyl cellulose, are incompatible with the cationic polymer in the system because of the anionic charges associated with most drilling fluid additives. The cationic polymer can react with a negatively charged additive, with both precipitating out of solution.

The precipitation reaction can be reduced or eliminated in some cases with the use of salts to screen the cation/anion interactions. For example, xanthan gum, with a relatively low anionic charge, will develop rheology in solution with the cationic polymer as the salt (KCl) concentration is increased (Fig. 6). A KCl concentration of 6% or greater is required to formulate a cationic drilling fluid with xanthan gum for viscosity.

Welan gum is a biopolymer similar to xanthan gum, but has less negative charge. Welan gum is compatible in the cationic system, provided the fluid contained a minimum of 3% KCl (Fig. 6). The welan gum and xanthan gum develop true gel strengths that allow the suspension of barite and drill cuttings.

Pregelatinized starches are nonionic and commonly used as fluid loss control agents in drilling fluids. Starch was found to be compatible with the cationic system and gave excellent fluid loss control.

The recommended cationic polymer/brine drilling fluid (CBF) formulation and typical properties are given in Table 1. The KCl concentration should be as close to 10% as cost and environmental considerations allow.

FLUID MAINTENANCE

Testing procedures were developed to maintain the properties of the fluid during field use.

These tests quantitatively measure the concentrations of the shale inhibiting agents in the drilling fluid and help establish guidelines for maintaining the CBF system (Table 2).

Standard American Petroleum Institute (API) procedures are used to measure rheology and fluid loss. The rheology and fluid loss are controlled independently using welan or xanthan gum and starch, respectively. The potassium chloride concentration is measured using a potassium ion-selective electrode. 8

A field test (Amoco bead test) was developed to measure the concentration of active (not adsorbed on solids) cationic polymer in the drilling fluid. 1 This simple dye test is a critical factor in the successful application of the CBF system.

The Amoco bead test uses small yellow plastic ion-exchanged beads with negative charges on their surfaces. When exposed to methylene blue dye (positive charge), the beads absorb the dye and appear dark blue. If the yellow beads are soaked in a drilling fluid that contains active cationic polymer, the polymer will react with the negative charges on the beads and adsorb on the surface, blocking the negative charges on the beads. The beads are then exposed to methylene blue dye. Since the surface of the beads has been blocked by the cationic polymer, the beads absorb only a small amount of the blue dye and appear green.

The bead test can quickly (6 min or less) identify the presence of excess cationic polymer in the drilling fluid. The green-to-blue color change can be used as the end point of a titration procedure to quantitatively determine the amount of active cationic polymer present in the drilling fluid. The Amoco bead test is accurate to within 0.25 lb/bbl of cationic polymer.

The test procedures and maintenance guidelines allow the CBF system to be run like a chemical process-without overtreatment, undertreatment, or guesswork. The simplicity of the CBF system, test procedures, and maintenance guidelines allow field personnel to have a high degree of control of the drilling fluid.

FIELD TESTING

The cationic polymer/brine drilling fluid (CBF) system has been field tested on more than 20 wells with hole diameters ranging from 4.375 in. to 17.5 in. Ten of the wells were drilled at the Amoco field testing facility in Catoosa, Okla., using the Amoco Research Drilling Mechanics drilling rig and the Amoco Stratigraphic High-speed Advanced Drilling System (Shads) slim-hole coring rig.

Test wells have also been drilled in northern Michigan, western Kansas, Colorado, west Texas, and the Texas Gulf Coast. Five wells have been drilled in the North Sea, and two wells are in progress.

The tests at the Catoosa facility indicated that the fluid is inhibitive. Caliper log data comparing CBF to a gel/water/polyanionic cellulose (PAC) conventional fluid are shown in Fig. 7. The well drilled with the conventional drilling fluid had extensive enlargement in the reactive shale intervals. A nearby well (3 m offset) drilled with the CBF fluid showed no enlargement over the entire hole.

NORTH SEA WELLS

Amoco Norway Oil Co. field tested the CBF system to determine if the fluid could replace oil-based mud in the upper hole sections of wells drilled in the reactive shales in the Norwegian sector of the North Sea. The CBF system was used on the Valhall 2/SA-27 well to drill the 17.5-in. hole section (368-1,379 m, 20 deviation) and 600 m of the 12.25-in. hole section (45 deviation).

Both hole sections were drilled without the gumbo problems experienced with other water-based drilling fluids used in the area. No bottom hole assembly balling was observed on trips, no mud rings were observed, and no rig time was spent cleaning gumbo from the flow line or shakers. The cuttings indicated that the fluid provided adequate hole cleaning and well bore shale inhibition. The rheology and fluid loss properties of the fluid remained stable despite increases in fluid density (14.8 ppg maximum mud weight) and low gravity solids.

The fluid was found to be resistant to cement contamination. It was used to drill out of the 13.373-in. casing and showed only minimal changes in rheology and fluid loss control.

The success of the fluid in the test suggests that CBF systems can be substituted for oil-based muds on the 17.5-in. and 12.25-in. hole sections on the Valhall platform.

Amoco (U.K.) Exploration Co. field tested the CBF system on exploration well 210/20-3A in block 210 of the U.K. sector of the North Sea. The cationic fluid was used to drill the 17.5-in. hole section (575-1,625 m) and the 12.25-in. hole section (1,6252,663 m). Some minor well bore instability was found in the 17.5-in. hole section as fill in the hole following wiper trips. The problem was reduced by an increase in fluid density.

The hole section was successfully logged and cased. Caliper log data from the 17.5-in. hole section indicated that average hole size was 17.9 in. and that most of the hole enlargement occurred through unconsolidated sand formations and several claystone formations thought to be overpressured.

The 12.25-in. hole section was drilled without problems and successfully logged. Caliper log data from the section indicated that average hole size was 12.7 in. with no major enlarged zones.

The fluid proved to be extremely tolerant to solids. Unlike conventional water-based fluids that require a "dump and dilute" program to deal with solids contamination, there was no need to discard solids-contaminated CBF during the well.

After the well was drilled, the remaining fluid was transported to another platform and used to drill another well.

RESULTS

Cationic polymer consumption is dependent on the formation drilled. The Catoosa shales are low cation exchange capacity (CEC) illitic shales that do not consume large amounts of cationic polymer. The Texas Gulf Coast gumbo formations are high CEC shales that require higher levels of cationic polymer treatment. In very low CEC formations, i.e., sandstone, limestone, etc., very little cationic polymer treatment is necessary.

Hole size also influences cationic polymer consumption. The volume of cuttings removed from a 17.5-in. hole is about 20 times the volume from a 4.375-in. hole. Cationic polymer consumption on the North Sea 17.5-in. hole section was approximately 11 times greater than that observed in the 4.375-in. hole drilled in gumbo shale in the Texas Gulf Coast.

The relatively high consumption rate in the 17.5-in. hole required a drilling fluid formulation with a higher polymer concentration to maintain an excess of the polymer in the fluid at all times.

  • The fluid is easy to run. The tests and maintenance guidelines developed for the fluid allow successful running of the system by someone with little drilling fluid experience.

  • The fluid is inhibitive. Although it is difficult to quantitatively prove shale inhibition, laboratory field tests suggest that CBF is more inhibitive than conventional water-based drilling fluids. The cationic fluid is not as inhibitive as oil-based drilling fluids but has been inhibitive enough to replace oil-based muds in two areas of the North Sea.

  • The fluid is resistant to contamination. The fluid can tolerate large amounts of solids contamination without adverse changes in rheology. This tolerance, however, does not reduce the need for good solids control equipment and practices. No problems were observed when common contaminants were encountered (anhydrite, gypsum, calcium, magnesium, halite, etc.). Cement contamination can be treated with sodium bicarbonate.

Three aspects of the CBF technology are significant to drilling fluid technology:

  • The simple dye test measures the concentration of cationic polymer in the system. The operator can always know the concentration of cationic polymer, allowing easy and uniform maintenance of the fluid.

  • The ability to independently control fluid properties results from the use of major components (cationic polymer, KCI, welan/xanthan gum, and starch) that work independently. For example, adding starch to reduce fluid loss or cationic polymer to compensate for depletion does not increase fluid rheology. This is significantly different from conventional fluids in which the addition of polymers to control fluid loss or improve inhibition often causes large changes in fluid rheology.

  • The CBF system uses polymers instead of clays to achieve fluid properties. Fluids that use clay (bentonite) for rheology and fluid loss control are very susceptible to contaminants that cause flocculation of the clay (i.e., salt, cement, etc.). The bentonite-free CBF system is more resistant to contamination than clay-based drilling fluids.

FLUID LIMITATIONS

The use of starch for fluid loss control limits the use of CBF fluid to wells that have bottom hole temperatures less than approximately 250 F. Research is in progress to develop synthetic additives that will control fluid loss at higher temperatures. The proper application of this system appears to be in the cooler upper hole sections. More thermally stable systems should be considered for deeper, high temperature hole sections.

The toxicity of the fluid may hinder its use in certain areas. The fluid contains a minimum of 5% KCl. This may limit its use in locations that have a chloride restriction on fluid disposal. Alternative sources of potassium that do not contain chloride (such as potassium carbonate) may be substituted for KCI in most cases.

Free cationic polymer can be toxic to marine organisms. When the cationic polymer is adsorbed on solids, the polymer is no longer toxic.

The Amoco bead test allows the amount of active cationic polymer to be monitored at all times and will identify when the polymer is depleted and rendered nontoxic. Excess polymer can be removed from the fluid by the addition of prehydrated bentonite. Research is in progress to understand the toxicity issues with this system.

ACKNOWLEDGMENT

The authors would like to thank the drilling staffs at Amoco Norway Oil Co. and Amoco (U.K.) Exploration Co. (London and Aberdeen), for field testing the CBF system in the North Sea, and Amoco Production Co. for permission to publish this article.

REFERENCES

  1. Beihoffer, T.W., Dorrough, D.S., and Schmidt, D.D., Paper IADC/SPE 19953, presented at the 1990 IADC/SPE Drilling Conference, Houston.

  2. Kadaster, A.G., Guild, G.J., Hanni, G.L., and Schmidt, D.D., Paper SPE 19531, presented at the 64th Annual Technical Conference of the SPE, San Antonio, 1989.

  3. Gray, G.R., Darley, H.C.H., Composition and Properties of Oil Well Drilling Fluids, Gulf Publishing Co., Houston, 1980.

  4. Beihoffer, T.W., Dorrough, D.S., and Schmidt, D.D., Paper SPE 18032, presented at the 63rd Annual Technical Conference of the Society of Petroleum Engineers, Houston, 1988.

  5. Theng, B.K.G., Formation and Properties of Clay-Polymer Complexes, Elsevier Publishing Co., Amsterdam, 19,-9.

  6. Parazak, D.P., Burkhardt, C.W., McCarthy, K.J., and Stehlin, M.P., Journal of Colloid Interface Science, Vol. 123, No. 59, 1987.

  7. Borchardt, J.K., ACS Symposium Series 396; Oil-Field Chemistry, Enhanced Recovery and Production Stimulation, American Chemical Society, Washington D.C., p. 204, 1989.

  8. API RP 131, Recommended Practice Standard Procedure for Laboratory Testing Drilling Fluids, American Petroleum Institute, Washington D.C., p. 35, 1990.

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