Johann P. Plank
SKW Trostberg AG
Trostberg, Germany
The development of novel synthetic fluid-loss polymers and polymeric deflocculants has helped make water-based mud systems stable for high temperature, high pressure (HTHP) drilling.
The basic design criteria for water-based muds used in HTHP wells include the use of Wyoming bentonite at low concentrations and the use of mud additives with only one primary function. A variety of the newly developed synthetic fluid-loss polymers with disparate molecular weights and electrolyte and temperature stability now allows tailor-made mud formulations for deep, hot wells.
Oil-based muds have been the fluid of choice in hostile drilling environments for many years because of thermal stability up to 500 F., high rate of penetration (ROP), and easy mud maintenance. Since the 1980s, environmental legislation has increased restrictions on the use of oil-based fluids.
In some countries, such as Germany, the use of oil-based mud in offshore operations is generally prohibited. Industry has responded by developing enhanced water-based mud systems stable under high temperature, high pressure conditions and composed of environmentally acceptable products. In some applications, these muds perform as well as oil-based muds.
Some of the common mud additives for high temperature applications are presented in this article along with the typical limitations of these materials. A variety of the recently developed synthetic polymers can be added to water-based systems to overcome the problems with conventional HTHP water-based muds.
These polymers have found applications as clay deflocculants, thinners, fluid loss additives, and extenders for conventional polymers and additives.
MUD ADDITIVES
HTHP stable drilling fluids must function at temperatures from 300 F. to at least 400 F. Some water-based muds have been formulated to tolerate temperatures exceeding 500 F.
The pressure encountered in deep, hot wells may exceed 10,000 psi. This requires high fluid densities to counteract the formation pressure. Typical mud densities in high pressure wells are 15-20 ppg.
CLAYS
In freshwater or low salt muds, bentonite is used to provide the viscosity to suspend barite and cuttings. At higher salinities, bentonite no longer hydrates. A saltwater drilling clay, such as attapulgite or sepiolite, must be used to give viscosity in electrolyte-containing drilling fluids,
In HTHP drilling, the clays in the drilling fluid require special attention because of a gelation process occurring at temperatures greater than 300 F. The gelation process may cause excessive mud viscosity, especially in high density mud systems.
The fluid loses its shear-thinning characteristic, resulting in high gel strengths, especially under static aging conditions. Drilled formation clays, particularly low gravity solids (LGS), undergo a similar gelation process.
Because of this gelation phenomenon, the bentonite content in high-temperature, stable water-based muds must be kept to a minimum. A concentration of 3 lb/bbl bentonite should not be exceeded when building these muds. For HTHP wells, only Wyoming bentonite (high quality, pure sodium montmorillonite) should be used. The use of polymer treated (peptized) or soda ash activated calcium bentonite should be avoided-complex reactions taking place under hostile conditions will make performance unpredictable.
The same principle concerning bentonite applies to clayish drill solids in the mud, especially the LGS. Field experience suggests that LGS should be kept below 6% by weight. Effective solids control equipment is required to achieve a mud with workable (i.e., not too high) rheology in the deeper hole sections.
If the concentration of bentonite or clay materials exceeds acceptable levels and results in viscosity problems, polymeric deflocculants, such as maleic anhydride copolymers, can be used as a la;t resort to control rheology.
THINNERS, DEFLOCCULANTS
Proper control of the drilling fluid rheology is a key to drilling HTHP wells successfully. Table 1 lists a number of natural and synthetic materials for rheology control in HTHP wells.
Some 20 years ago, high-solids dispersed muds were the only water-based alternative to oil-based muds in HTHP drilling. These systems contained lignites and lignosulfonates for rheology as well as filtration control.
Conventional high-solids dispersed muds require a minimum alkalinity (pH 9) to function. Above 360 F., heavy lignite/lignosulfonate treatments are necessary because both products start to decompose. Particularly under conditions of static downhole aging, high-solids dispersed muds have had mud gelation and related drilling problems.
In addition, because of their low tolerance to electrolytes, these muds and water-based muds in general were considered technically inferior to oil-based mud systems.
Chrome lignite, for example, has been used extensively as a thinner and fluid loss additive in deep, hot wells. However, maintenance rates were high: At 400 F., doses of 3-4% and at 500 F., doses of more than 6% have been reported.3
Chrome lignite decomposes at temperatures above 360- F., necessitating the high doses. CO2 is a major degradation product and can be detected easily with the Garrett Gas Train. Another way to monitor lignite decomposition is to monitor the pH: A significant drop is an indication of lignite degradation. The decomposition products of lignites have a negative effect on the drilling fluid. CO2 flocculates bentonite, resulting in significantly increased yield point and gel strengths of the mud.
The accumulation of degradation by-products and their detrimental effect on the mud is the major reason for the decreased use of chrome lignite in recent years. A secondary concern is the environmental damage caused by the heavy metal content.
Lignosulfonates, even when reacted with chrome, are temperature stable only up to 350 F. and hence inferior to lignites. They have limited use in high temperature drilling.
To combat these problems, a number of monomer reacted (grafted) lignite and lignosulfonate products have been developed as alternatives.4-6 Acrylic acid and 2-acrylamide-2-methyl-propane sulfonic acid (Lubrizol Corp.'s AMPS) are the most common monomers grafted onto the inexpensive lignite or lignin backbone. The grafting enhances the thermal stability and electrolyte (especially calcium) tolerance of the products. Field experience with an acrylate grafted, polyanionic lignin is described by Abdon, et al.7
POLYMERIC DEFLOCCULANTS
Other recent developments for rheology, control under hostile conditions include synthetic, short-chain polymeric thinners. Compared with lignite and lignosulfonates, polymeric thinners achieve the same dispersing effect at about one tenth the dose. They are stable beyond 400 F. and do not depend on a certain pH interval for optimum performance. Average molecular weights of polymeric thinners range between 1,000 and 15,000 Daltons, typically around 2,000-6,000 Daltons.
Acrylate or acrylamide-based thinners have been common additives in calcium-free systems. Besides their limitation with hardness tolerance, they do not always respond satisfactorily in muds with a high content of active solids.
If polyacrylates are used in such systems, rather frequent treatment of the mud is sometimes required to prevent the 10-min gel strength from continually rising. Polyacrylates do not effectively, inhibit the high temperature gelation of clays.
Maleic anhydride copolymers developed by Milchem Inc. and National Starch & Chemical Co. have solved this problem. At small doses (0.2-1 lb/bbl), these have a lasting effect on plastic viscosity and gel strengths, indicating that they effectively inhibit the high temperature gelation of bentonite and clay.
This unique property and their improved hardness tolerance distinguish them from conventional acrylate-based thinners. Fig. 1 shows the chemical formula of commercially available maleic anhydride deflocculants.
In environments of high active solids and hardness content, water-based muds with maleic anhydride copolymers have been successful in deep drilling.
The polymeric deflocculants not only reduce viscosity, but assist high molecular weight fluid loss polymers in lowering filtrates. The dispersion of clays seems to result in a less permeable filter-cake, improving fluid loss. In a recent study by SKW Trostberg AG, a combination of high to medium molecular weight, sulfonated fluid loss polymers together with a low molecular weight, acrylate/acrylamide thinner provided a fresh water mud system with thermal stability to 580 F."
FLUID LOSS POLYMERS
Adequate filtration control of a drilling fluid is essential to prevent drilling problems such as excessive torque and drag, differential pressure sticking, borehole instability, and formation damage."'-12 HTHP filtrates of less than 20 ml are commonly specified for deep, hot wells.
Polyacrylates and polyacrylamides developed by Union Oil Co. were the first synthetic fluid loss polymers used in drilling muds.13 A number of products with average molecular weights of 100,000-3 million Daltons have been used successfully at temperatures exceeding 400 F. The major limitation of typical polyacrylates is their sensitivity to divalent cations. Calcium concentrations, present in any lime, gypsum, or seawater mud, as low as 200 ppm destroy their fluid loss capability. The use of polyacrylates is therefore limited to freshwater and saturated salt systems. Acrylamide polymers could not overcome this disadvantage.
The need for more calcium and magnesium-tolerant fluid loss polymers prompted the development of a new generation of co and terpolymers (Fig. 2). Sulfonated monomers were recognized as better building blocks than acrylic acid. Sulfonic acid is not chelated by divalent cations as easily as the carboxyl group in acrylic acid. The AMPS monomer was used as the main building block to achieve high hardness tolerant fluid loss polymers. 14 A calcium and magnesium tolerance of 15,000-75,000 ppm has been achieved with some co and terpolymers.
Most AMPS fluid loss polymers are available at average molecular weights of from 400,000 to several million Daltons. Because of the high molecular weight, the polymers add viscosity, especially in freshwater or low salt systems. In high density muds, the addition of a polymeric thinner may be required to offset this viscosity increase.
SKW Trostberg developed a synthetic fluid-loss polymer, a sulfonated hydroxylated polymer with an average molecular weight of only 200,000 Daltons, that does not have the disadvantage of secondary viscosity. It has a neutral behavior on mud rheology making the polymer more desirable for high density systems.
Thermal stability and hardness tolerance of this product are comparable to or exceed those of high molecular weight, AMPS-based copolymers.15 16
POLYMER EXTENDERS
Typical synthetic fluid loss and deflocculating polymers are stable up to 420-450 F. The thermal stability depends on the molecule chemistry and on the drilling fluid environment. 17
Some of the new polymer extenders enhance the thermal stability of polymers by approximately 40-50 F. This allows the use of products in HTHP drilling which are by themselves not suitable for high temperature wells. Polyanionic cellulose (PAC), for example, is temperature stable up to 300 F. In combination with a polymer extender, its thermal limit can reach 340-350 F. Likewise, synthetic fluid loss and defocculating polymers can be used at temperatures near 500 F.
The use of polymer extenders should be considered if a polymer reaches its temperature limit shortly before a certain well interval is completed. In this situation, it is more economical to add the extender instead of treating the mud with a more stable and usually more expensive polymer.
Organic polymers should not be considered for any well with a bottom hole static temperature (BHST) of 500 F. Mud systems based on inorganic products stable in excess of 500 F. are available for such environments.
SHEAR THINNING
Another new development in high temperature stable, water-based mud technology, is an inorganic, synthetic poly(metal hydroxy chloride) compound, also referred to as mixed metal hydroxide.18 A commercial product has the following chemistry:
[SEE FORMULA]
The poly(magnesium aluminum hydroxide) cation of this compound interacts with bentonite resulting in an extremely shear-thinning and fragile gel. It has excellent carrying capacity (yield point of 80-100 lb/100 sq ft) at low plastic viscosity (5-10 cp). The addition of mono or divalent salts (NaC1, KC1, or CaC12) does not destroy the shear-thinning characteristic of the fluid. Because of the cationic interaction with bentonite, nonionic fluid loss polymers are best suited for this mud system. It has a thermal stability, in excess of 500 F. The poly(magnesium aluminum hydroxy chloride) offers an alternative drilling fluid system for deviated HTHP wells or geothermal drilling. Field tests have shown effective cuttings removal, borehole stabilize, inhibition of sloughing and disintegrating shales, and high ROP."
CASE HISTORIES
The key products in building an HTHP stable water-based mud system are shown in Table 2. One should avoid the use of "chemical cocktails" by keeping the number of products to a minimum. 2 7 Products with more than one primary function should be disregarded; otherwise, multiple interactions between mud additives may render a system unmanageable during troubleshooting or treating of the mud.
Lignite/lignosulfonate-dispersed muds or nondispersed polymer fluids conditioned with polymers of limited temperature stability, such as PAC, are commonly used to drill the interval preceding the HTHP section. As the BHST approaches 350 F., these muds are typically treated with high temperature stable fluid-loss polymers and deflocculants to condition them for HTHP environments, or they are dumped and exchanged for a low solids polymer mud. Although costly, the latter practice is preferred in areas with low permeability reservoirs because high solids dispersed lignite/lignosulfonate muds can damage the formation.
TREATED LIGNITE MUDS
Standard, lignite/lignosulfonate muds with limited temperature and electrolyte tolerance can be converted to an HTHP stable mud system by treating the mud with a polymeric deflocculant for rheology control and a synthetic fluid loss polymer for improved filtration control. This approach is the least expensive and hence most preferable way to formulate an HTHP stable mud system.
A 23,550-ft well in Mississippi Sound Block 57 encountered high temperature and high salt contamination. A standard lignite mud was used to drill the 12 1/4-in. interval (19,600-21,400 ft).
During drilling of the subsequent 8 1/2-in. hole section anhydrite and salt contaminations were encountered. BHST at this point exceeded 410 F. The mud was then salt saturated to achieve a fluid density of 17.3 ppg and supplemented with a high temperature stable polymeric deflocculant and a synthetic fluid loss polymer (Table 3). This mud showed good stability to 23,550 ft total depth (TD). No problems other than tight hole associated with drilling the mobile salt section were experienced.
On a well drilled in the North Sea, a conventional lignite/lignosulfonate mud system required conditioning to achieve HTHP stability. At 14,500 ft, thermal degradation of mud products was indicated by a drop in mud pH and the occurrence of CO,. To stabilize the system, 3 lb/bbl of a sulfonated hydroxylated fluid loss polymer were added.
From 16,000 ft, increased bottom hole temperature required a total concentration of 6 lb/bbl of the fluid loss polymer and 1.5 lb/bbl of a maleic anhydride-based polymeric deflocculant to control the bentonite gelation.
Because this fluid loss polymer does not add viscosity, plastic viscosities (1518 lb/100 sq ft) staved low, resulting in a high ROP (1620 ft/hr). The 17.4-ppg freshwater mud gave HTHP filtrates of 7-9 ml and was used to 18,700 ft TD. The recorded BHST at TD was 360 F. After 5 days of static aging in the hole, the mud still had an HTHP fluid loss of 12 ml and a plastic viscosity of 18 lb/100 sq ft. This stability was considered excellent.
A similar, polymer-treated lignite/lignosulfonate mud was used on another HTHP well drilled in Norway. At 15,530 ft, this well entered an unexpected high pressure zone and took a gas kick with more than 10,000 psi." Fortunately, rig personnel managed to prevent a blowout. It is believed that had this well used an oil-based mud, the higher solubility of gas in oil would have delayed the detection of the kick, and the safety risk would have increased. The well was eventually killed through a relief well using the same polymer-treated, water-based mud.
POLYMER MUDS
The use of polymer-treated lignite/lignosulfonate muds is limited by their dispersive action on certain formation clays which may result in borehole instability and by their potential of formation damage, Hence, low solids polymer muds are used to drill HTHP wells with low permeability reservoirs and clays present in the deeper section of the hole.
Zechstein wells in Germany are commonly drilled with a saturated salt mud treated either with starch or cellulose polymers, such as PAC or carboxymethyl hydroxyethyl cellulose. During drilling of the deepest section of the hole, the mud system is routinely displaced by a low solids, saltwater-polymer fluid. This fluid is low in bentonite or attapulgite to minimize formation damage, and it contains a high molecular weight, AMPS-type copolymer for HTHP fluid loss control.
The composition and properties of a field mud taken at 21,670 ft are given in Table 4. This type of mud has been standardized by a committee of German oil companies. An oil company can purchase the standard mud from a service company's mud plant and return it after use for reconditioning, thereby minimizing disposal. The saltwater-polymer mud has been used in Germany to drill Zechstein wells with depths to 22,000 ft and temperatures of up to 400 F.
Field experience with a polymer mud containing a high molecular weight, AMPS-type fluid loss polymer and a modified polyacrylate deflocculant are described by Bethlen.21 This fluid was used to drill 17,000-ft wells with temperatures in excess of 360 F.
Formations in the Northern Monagas, Venezuela, area are characterized by abnormal pore pressure, depleted surface sands, reactive shales, and CO2 contamination. Oil-based muds used traditionally in the area have caused formation damage because of emulsion blocking in tight, water-wet, gas-bearing formations. This problem was eliminated by the use of HTHP stable, water-based polymer mud.
A well offshore The Netherlands was drilled with synthetic polymers in a high hardness (30,000 ppm calcium/magnesium), low bentonite mud to achieve very low HTHP filtrates.
A saturated salt, low bentonite mud was used to drill the 8 1/2-in. hole section (12,301-13,780 ft). Zechstein salt with halite and polyhalite was encountered. Several brine influxes resulted in a total hardness of 32,000 ppm (14,000 ppm Ca/18,000 ppm Mg). Fluid loss became erratic and unstable (HTHP filtrate 50 ml). Large additions of starch, PAC, and a high molecular weight copolymer did not help.
For the 6-in. hole section (13,780-15,250 ft), a mud system with stable and very low (
The mud properties of the 13.5-ppg mud treated with HTHP and electrolyte tolerant polymers are shown in Table 5. While drilling ahead, only minor polymer treatments were required to maintain an HTHP filtrate of 10 ml or less. The mud properties remained stable through drilling to TD.
This case history shows that these new synthetic fluid loss polymers are key ingredients to formulate water-based mud systems with stability under extremely hostile conditions. Traditional fluid systems such as lignite, lignosulfonate, starch, or cellulose-based muds would have failed in such environments. oil-based mud would have been the only choice to complete this well if those advanced polymer mud systems were not available.
FIELD PROBLEMS
Solids control and contaminant removal are some of the typical drilling problems caused by high well bore temperatures and drilled solids buildup. 23-25 For example, low gravity solids cause excessive mud viscosity, which requires costly mud treatments and dilution.
A particle size analyzer can monitor the efficiency of the solids control equipment to help keep the LGS below 6%. The use of premium solids control equipment is a key to success in drilling deep, hot wells.22 Good results are reported from the use of a cascading shaker arrangement, a mud cleaner, and two centrifuges. 2 The prevalent contaminants in deep wells are gases (CO2, H2S) and formation brines which may contain large amounts of NaCl.
CaCl2, or MgCl2, CO2 contamination reduces the alkalinities, but increases the mud filtrate alkalinity (mo and the 10-min gel strength. The recommended treatment is to add lime to achieve desired mud alkalinity (pm) and KOH or NaOH for the filtrate alkalinity (pf).
The carbonate solids from the lime treatment may cause excessive viscosity. Excellent solids control equipment, including centrifuges, helps avoid this problem. Particle size distribution of the mud solids should be monitored to ensure that fines do not become excessive. To combat the CO2, one must determine if it is indigenous to the formation or is caused by decomposition of mud chemicals, such as lignite.
H,S can increase mud viscosity. The Garrett Gas Train can determine H,S concentration in the mud.
Upon detection, the typical first action is to raise the alkalinities of the mud by adding lime, KOH, or NAOH. Iron or zinc-based scavengers are then used to neutralize H2S by forming insoluble sulfides. In HTHP drilling, these scavengers must be added carefully. At high temperatures, excessive use and rapid addition of zinc scavengers can result in high viscosities . 2
Brine influxes usually increase all rheologies. If contamination is temporary, the pH should be increased to 11-12 with NAOH or KOH to precipitate the calcium and magnesium. Treatment with fluid loss polymers and deflocculants is required to maintain filtration control and Theology.
If severe contamination with high hardness brine is anticipated, the mud should initially be built around electrolyte-tolerant polymers. If the influx heavily dilutes the mud, circulation of high viscosity (e.g., hydroxyethyl cellulose) pills may permit drilling further. If this fails, the formation brine must be conditioned to provide some filter cake and for fluid loss control.
ACKNOWLEDGMENT
The author would like to thank SKW Trostberg AG for permission to publish this article. Special thanks also go to the many colleagues in the mud industry who shared Valuable experience for writing this article.
REFERENCES
- Braden, S., "Oil muds score high in Anadarko evaluation," OGJ, pp. 25-30, June 1, 1987.
- Mitchell, R.K., et al., "Design and application of a high-temperature mud system for hostile environments," SPE 20436, presented at the 65th SPE Annual Technical Conference & Exhibition, New Orleans, Sept. 23-26, 1990.
- Krause, H., "Requirements of high temperature water-based drilling fluids from the view of drilling engineers," Oil Gas Europ. Mag., Vol. 1, pp. 43-49, 1983.
- U.S. Patent No. 46,-8591, assigned to Nalco Chemical Co.
- Dorman, J., "Heat and electrolyte stable drilling fluids: results of development and application, " 21st Petroleum Conference and Exhibition, Siofok, Hungary, Sept. 26-30, 1990.
- Clements, W.R., et al., "Electrolyte-tolerant polymers for high-temperature drilling fluids," SPE 13614, presented at the SPE California Regional Meeting, Bakersfield, Calif., Mar. 27-29, 1985.
- Abdon J.C., et al., "The development of a deflocculated polymer mud for HTHP drilling," SPE 17924, presented at the SPE Middle East Oil Technical Conference & Exhibition, Bahrain, Mar. 11-14, 1989.
- U.S. Patent No. 3730900, assigned to Milchem Inc.
- U.S. Patent No. 4518510, assigned to National Starch & Chemical Co.
- Wahner, K. "Combinations improve drilling fluid chemicals performance," paper presented at SKW Trostberg AG's Drilling Fluid Symposium, Trostberg, Germany, Dec. 17-19, 1990.
- Fisk J.Y., et al., "The filterability of drilling fluids," SPE 20439, presented at the 63th SPE Annual Technical Conference & Exhibition, New Orleans, 1990.
- Chesser B.G., et al., "Dynamic and static filtrate loss techniques for monitoring filter cake quality improves drilling performance," SPE 20439, presented at the 65th SPE Annual Technical Conference & Exhibition, Net,, Orleans, Sept. 23-26, 1990.
- U.S. Patent No. 2718497, assigned to Union Oil Co. of California.
- WO 83/02449 assigned to Casella, Hoechst, and Dresser Industries.
- Plank, J.P., and Hamberger, J.Y., "Field experience with a novel calcium-tolerant fluid loss additive for drilling muds," SPE 183,-2, presented at the SPE European Petroleum Conference, London, Oct. 16-19, 1988.
- Halasz, S.P.v., "Aspects of saline and heat stable polymers for enhanced oil recovery," paper presented at the 150th Anniversary Congress of the Royal Society of Chemistry, London, Apr. 8-11, 1991.
- U.S. Patent No. 4900457, assigned to Shell Oil Co.
- Botha, J.L., et al., "Laboratory and field evaluations of novel inorganic drilling fluid additive," IADC/SPE 17198, presented at the IADC/SPE Drilling Conference, Dallas, 1988.
- Burba, J.L., et al., "Field evaluations confirm superior benefits of MMLHC fluid system on hole cleaning, borehole stability, and rate of penetration," IADC/SPE 19956, presented at the IADC/SPE Drilling Conference, Houston, Feb. 27-Mar. 2, 1990.
- Noroil, Vol. 1, pp. 11-13, 1990.
- Bethlen, G.A., "Application of the Therma-Drill system in Eastern Venezuela," 21st Petroleum Conference and Exhibition Siofok, Hungary, Sept. 26-30, 1990.
- Dorman, J., and Gocs, J., "Technological and economical aspects of mechanical solids control in the application of up to date drilling fluids," 21st Petroleum Conference and Exhibition, Siofok, Hungary, Sept. 26-30, 1990.
- Davis, N. II, and Tooman, C.E., "New laboratory tests evaluate the effectiveness of gilsonite as a borehole stabilizer," IADC/SPE 17203, presented at the IADC/SPE Drilling Conference, Dallas, Feb. 28-Mar. 2, 1988.
- U.S. Patent No. 3028333, assigned to Phillips Petroleum Co.
- U.S. Patent No. 4063603, assigned to Sun Drilling Products.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.