Energy & Fuels 2008, 22, 2405–2410
2405
Feasibility Study for the Use of Kinetic Hydrate Inhibitors in Deep-Water Drilling Fluids Malcolm A. Kelland,*,† Kirsten Mønig,‡ Jan Erik Iversen,‡ and Knut Lekvam‡ Department of Mathematics and Natural Sciences, Faculty of Science and Technology, UniVersity of StaVanger, 4036 StaVanger, Norway, and International Research Institute of StaVanger (IRIS), Post Office Box 8046, 4068 StaVanger, Norway ReceiVed February 13, 2008. ReVised Manuscript ReceiVed April 24, 2008
The feasibility of using kinetic hydrate inhibitors (KHIs) in deep-water water-based drilling fluids to give added subcooling protection has been investigated. A range of neutral, anionic, or cationic commercial and noncommercial KHIs were first tested for their compatibility with highly saline drilling fluids. Thereafter, the most suitable products were tested as KHIs in a sapphire cell arrangement at pressures up to 300 bar and temperatures down to 0.9 °C. Experiments with the best inhibitors were also carried out in the presence of two types of clay to represent drilling cuttings with different activity and in simulated shut-in conditions. The conclusion was that some KHIs, particularly neutral or anionic polymers, could be used in drilling fluids if the activity of the clay/cuttings is low, probably because of negligible adsorption of the KHI polymer onto the clay/cuttings. It was also shown that pressure and not just subcooling is an important factor in determining the performance of a KHI.
Introduction In deep-water drilling, the low temperature and high pressure favors hydrate formation in the drilling fluid if gas is present. The problem that needs to be solved is to prevent hydrates from forming during well control situations or to minimize the impact of hydrate formation, such as eliminate potential hydrate blockages.1–5 Oil-based muds (OBMs) are generally thought to be more effective at preventing hydrate problems than water-based muds (WBMs). This may be due to the lack of reported problems in the field when drilling in deep water with OBMs, although some laboratories have unpublished claims to having obtained hydrate plugs in autoclaves using OBMs, including our own laboratory. The best WBMs today are not adequate to prevent hydrate formation in all deep-water drilling situations, where the pressure can be several hundred bars at the sea bed and temperatures range from -2 to +4 °C depending upon the location (e.g., Gulf of Mexico, Norwegian North Sea, West Africa, offshore Brazil, etc.).6,7 Figure 1 illustrates typical temperature changes in the annulus and tubing for drilling in a water depth of * To whom correspondence should be addressed. Telephone: +4751831823. Fax: +47-51831750. E-mail:
[email protected]. † University of Stavanger. ‡ International Research Institute of Stavanger (IRIS). (1) Zamora, M.; Broussard, P.; Stephens, M. In Proceedings of the SPE International Petroleum Conference and Exhibition, Villahermosa, Tabasco, Mexico, Feb 1-3, 2000; SPE 59019. (2) Sloan, E. D., Jr.; Koh, C. A. Clathrate Hydrates of Natural Gases, 3rd ed.; CRC Press, Taylor and Francis Group: Boca Raton, FL, 2008. (3) Reyna, E. M.; Stewart, S.R. In Proceedings of the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, Feb 27-March 1, 2001; SPE/ IADC 67746. (4) Barker, J. W.; Gomez, R. K. J. Pet. Technol. 1989, March, 297. (5) Castro, G. T.; Terry, A. P.; Ferreira, L. V.; Ribeiro, G. S. In Proceedings of the Offshore Technology Conference, Houston TX, 1998; OTC008777. (6) Ebeltoft, E.; Yousif, M.; Sørga˚rd, E. SPE Drilling and Completion, 16 (1), March 2001; p 19, SPE 68207.
approximately 1200 m. Blends of thermodynamic inhibitors, such as salts and glycols, have a strong but limited ability to prevent hydrate formation. The addition of more salts (e.g., sodium chloride) is often impossible because the solutions are either saturated already or become extremely high density, which causes operational problems. Ethylene and propylene glycols and glycerols are more expensive and need to be added in large amounts to have significant effects.8,9 These low-salinity, lowdensity fluids with organic thermodynamic inhibitors are especially suited for use when low-fracture gradients are encountered while drilling intervals where gas hydrate formation in the drilling fluid is possible. In addition, salts become less soluble as the percentage of glycol or other organic solvents in the aqueous phase increases; thus, there is a tradeoff between these two classes of thermodynamic inhibitor. Consequently, there is a need to find other economical and environmentally friendly methods to prevent hydrate formation in deep-water drilling. Low-dosage hydrate inhibitors (LDHIs) are a more recent technology for preventing hydrate plugging.10 LDHIs are divided into two main product classes: (i) kinetic hydrate inhibitors (KHIs) and (ii) anti-agglomerants (AAs). KHIs are water-soluble polymers, often with added synergists that improve their performance. KHIs delay the nucleation and usually also the crystal growth of gas hydrates. The nucleation delay time (induction time), which is the most critical factor for field operations, is dependent upon the subcooling (∆T) in the system: the higher the subcooling, the lower the induction time. (7) Sørga˚rd, E.; Altera˚s, E.; Fimreite, G.; Dzialowksi, A.; Svanes, G. S. In Proceedings of the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, Feb 27-March 1, 2001; SPE/IADC 67834. (8) Halliday, W.; Clapper, D. K.; Smalling, M. In Proceedings of the IADC/SPE Drilling Conference, Dallas, TX, March 3-6, 1998; SPE 39316. (9) Halliday, W.; Clapper, D. K.; Smalling, M. U.S. Patent 6,080,704, 2000. (10) Kelland, M. A. Energy Fuels 2006, 20, 825.
10.1021/ef800109e CCC: $40.75 2008 American Chemical Society Published on Web 06/11/2008
2406 Energy & Fuels, Vol. 22, No. 4, 2008
AAs for production pipelines are surfactants that prevent hydrates from accumulating into large masses or depositing in conduits. Instead, a slurry of fine transportable hydrate particles is formed. The mechanism is dependent upon the presence of a liquid hydrocarbon phase in which to slurry the hydrate crystals. Therefore, they do not appear to be applicable to water-based drilling fluids. KHIs available today have been designed primarily for multiphase transportation in production lines. Several products are commercially available and have been used in field applications since about 1995.11–17 However, KHIs could also be a costeffective alternative for hydrate control in deep-water drilling.18 They could give the extra protection needed where the deepwater drilling mud, containing thermodynamic inhibitors, is under-inhibited because of density and/or cost considerations. It was the objective of this work to investigate the possibility of using KHIs in deep-water WBMs. Some promising work has already been carried out by other groups on this subject, but no work with added drilling cuttings or clay has been published in the open literature.19–21 The work was divided into compatibility studies (of the KHI with the WBM) and KHI performance testing in simulated WBMs with and without clays present to simulate drilling cuttings. Compatibility Studies It is important that the KHI polymer is soluble in the aqueous phase of the drilling fluid at the temperatures needed to delay hydrate formation. Although all KHI polymers are water-soluble in fresh water at room temperature, they may exhibit cloud points (Tcl) when heated. Thus, above the cloud point, a phase change occurs in which the clear solution becomes turbid. This is due to the break down of hydrogen-bonding between the polymer and water molecules. The polymer does not usually precipitate from the aqueous solution at the cloud point but at a slightly higher temperature called the deposition point (Tdp). Further, if a solution of the KHI polymer is heated above the cloud point but below the deposition point, the polymer will (11) Argori, C. B.; Blaine, R. A.; Osborne, C. G.; Priestly, I. C. In Proceedings of the SPE International Symposium on Oilfield Chemistry, Houston, TX, Feb 1997; SPE 37255. (12) Talley, L. D.; Mitchell, G. F. In Proceedings of the 30th Annual Offshore Technology Conference, Houston TX, May 3-6, 1998; OTC 11036. (13) Fu, S. B.; Cenegy, L. M.; Neff, C. In Proceedings of the SPE International Symposium on Oilfield Chemistry, Houston, TX, Feb 1316, 2001; SPE 65022. (14) Phillips, N. J.; Grainger, M. In Proceedings of the Annual Gas Technology Symposium, Calgary, Alberta, Canada, March 15-18, 1998; SPE 40030. (15) Leporcher, E. M.; Fourest, J. P.; Labes-Carrier, C.; Lompre, M. In Proceedings of the SPE European Petroleum Conference, The Hague, The Netherlands, Oct 20-22, 1998; SPE 50683. (16) MacDonald, A. W. R.; Petrie, M.; Wylde, J. J.; Chalmers, A. J.; Arjmandi, M. In Proceedings of the SPE Gas Technology Symposium, Calgary, Alberta, Canada, May 15-17, 2006; SPE 99388. (17) Gle´nat, P.; Peytavy, J. L.; Holland-Jones, N., Grainger, M. In Proceedings of the 11th Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, United Arab Emirates, Oct 10-13, 2004; SPE 88751. (18) J. Pet. Technol. 1997, Sept, 966. (19) Power, D.; Slater, K.; Aldea, C.; Lattanzi, S. In AADE National Technology Conference, Houston, TX, April 1-3, 2003; AADE-03-NTCE48. (20) Dzialowski, A.; Patel, A.; Nordbo, K. In Proceedings of the Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 28-30, 2001. (21) Trenery, J.; Fleyfel, F.; Shukla, K.; Hakimuddin, M. Gas hydrate control for deep water drilling operations. JIP at Intertek Westport Technology Center, 1999-2000.
Kelland et al.
easily redissolve and the turbid solution will go clear when cooled below the cloud point. Above the deposition point, the precipitated polymer will only slowly redissolve when cooled below the cloud point. The cloud point and deposition point usually decrease with an increasing salinity (salting-out effect). In deep-water drilling operations, the mud temperature will circulate between a maximum and a minimum. Thus, if the cloud point of the KHI polymer in the mud is above the maximum circulation temperature, it will never go turbid and undergo a phase change but remain always soluble in the aqueous phase of the mud. For practical purposes, it may be possible to allow the mud temperature to rise as high as the deposition point of the KHI polymer in the mud, because during the cooling part of the cycle, the polymer will easily redissolve. Whereever the mud temperature rises above the deposition point, the polymer will be expected to deposit and accumulate and therefore not be available to inhibit hydrate formation in the next mud cycle. The maximum mud circulation temperature was assumed to be approximately 50 °C, although in some drilling operations, it can be significantly higher. Thus, we sought to find KHI polymers that had deposition points in high salinity muds or brines of at least 50 °C. The following is a list of muds used with weight percentages of salts and monoethylene glycol (MEG): (i) mud I, 7.3 wt % NaCl and 5 wt % MEG; (ii) mud II, 15.5 wt % NaCl and 5 wt % MEG; (iii) mud III, 20.0 wt % NaCl; (iv) mud IV, 15.5 wt % HCOOK; (v) mud V, 15.5 wt % CaCl2; (vi) mud VI, 23 wt % CaCl2; and (vii) mud VII, 14.8 wt % NaCl and 10 wt % MEG. The following is a list of KHIs investigated with average molecular weights (Mw), where known, and their suppliers: (i) KHI-1, 1:1 amidated maleic anhydride/vinyl acetate copolymer, 20 000 (IRIS); (ii) KHI-2, polyacryloylpyrrolidine, 5000 (Nippon Shokubai); (iii) KHI-3, 4:1 isopropylacrylamide/AMPS copolymer, 1100 (Nippon Shokubai); (iv) KHI-4, 9:1 isopropylacrylamide/AMPS copolymer, 1700 (Nippon Shokubai); (v) KHI-5, 1:1 VIMA/VCap copolymer, 20 000 (IRIS); (vi) KHI6, 3:1 VCap/VP copolymer, 11 000 (BASF); (vii) KHI-7, 1:1 VCap/VP copolymer, 6000 (1393-070, BASF); (viii) KHI-8, 9:9:2 VCap/VP/sodium vinyl sulfonate terpolymer (Danchem); (ix) KHI-9, VCap/sodium acrylate copolymer (10407-83, ISP); (x) KHI-10, 1:1 VP/VCap copolymer (Inhibex 501, ISP); (xi) KHI-11, polyesteramide (RE5323HW, Baker Petrolite), where AMPS is acrylamidopropylsulfonic acid sodium salt, VIMA is N-vinyl-N-methyl acetamide, VCap is N-vinyl caprolactam, and VP is N-vinyl pyrrolidone. Cloud point (Tcl) and deposition points (Tdp) were determined experimentally as follows: 10 mL of a 0.5 wt % solution of the polymer was placed in a test tube, which was placed in a stirred oil bath on a heat regulator. The oil bath was heated, with heating being at ca. 1 °C/min near the cloud point. The cloud point was determined as the temperature at which the first sign of appreciable turbidity was detected. The solution was immediately cooled below the cloud point; the solution was reheated; and the cloud point was determined again. The repeated cloud point values were all within (1.0 °C of the first values. Deposition points were found by heating above the cloud point until the first sign of polymer precipitation on the test tube walls was visible. Tables 1 and 2 summarize the cloud point and deposition point data for the KHI polymers in these muds at a typical WBM pH value of 11. Polyvinylcaprolactam, possibly the most studied KHI polymer, was not chosen because it was known to have a
KHIs in Deep-Water Drilling Fluids
Energy & Fuels, Vol. 22, No. 4, 2008 2407
Figure 1. Typical temperature profile for deep-water drilling operations calculated by Drillbench Presmod (mud circulation rate of 800 L/min). Table 1. Selected Cloud Points (Tcl) and Deposition Points (Tdp) of KHI Polymers in Various NaCl Muds at pH 11a Tcl/Tdp (°C)
a
polymer
mud I
mud II
mud III
KHI-1 KHI-2 KHI-3 KHI-4 KHI-5 KHI-6 KHI-7 KHI-8 KHI-9 KHI-10 KHI-11
>80 >80 >80
45/80 48/55 45/75 1200 >1100 450 200 >1200 >1000 600 >1100 >1200 2500 80 100 >1100 >1100 >1100 240
St-1 (min) 0 100 40 10
400 750 3600 1500 50 200
>750
a
Both induction times (ti) and slow growth times (St-1) are given. Bent. ) Wyoming bentonite, and X ) additional 0.5 wt % xanthan.
effect of pressure are to be taken as tentative. However, in many cases, the difference in induction times between two sets of conditions is well outside the (30-40% scattering observed for one set of conditions, allowing for more definite conclusions to be drawn. KHI Performance Tests at 150 bar. Results of KHI performance tests at 150 bar and 0.9 °C with 6000 ppm of the most compatible KHIs are given in Table 5. We used mud II, which gave a subcooling of 12.5 at 0.9 °C and 150 bar. The pH was varied in some experiments between that of the KHI solution and a typical mud pH of 11-12. In some experiments, we added 5 wt % clay particles (5% OCMA or Wyoming bentonite supplied by Halliburton, Norway) to simulate the presence of drilling cuttings. Wyoming bentonite is composed essentially of montmorillonite clay, with a very high surface area (high activity). This material is always electrically unbalanced by substitutions, such as magnesium, iron, or calcium, replacing aluminum. This results in a charge deficiency that must be balanced externally by cations, which in turn are exchangeable. The quantity of cations required to create a net charge balance is called “the exchangeable cation capacity”. The internal charge deficiency inside it results in a net negative charge of the particle, which in turn is compensated for by exchangeable cations positioned but weakly held near the tetrahedral layers. The most prominent cations are sodium, calcium, magnesium, and potassium, respectively. In OCMA clay, there is less internal charge deficiency because there are more Ca2+ ions in this clay than in bentonite. Consequently, it has a lower surface area. OCMA clay is most often used by drilling companies to simulate drilling cuttings. We considered an induction time of over 1000 min as a “pass”, being a suitably long time to allow the drilling operator to circulate out any drilling fluids before hydrate formation ensues. As Table 5 shows, the performance of KHI-1 at low pH without the presence of clay is good but is drastically reduced by either raising the pH to 11 or adding 5 wt % clays. This is probably because the polymer is cationic and adsorbs
Figure 4. Gas consumption versus time for no inhibitor and 6000 ppm KHI-7 with the addition of two types of clay at 150 bar, 0.9 °C, and ∆T ) 12.5 °C using mud II.
easily to anionic sites on the clays, making it unavailable for kinetic inhibition in the bulk aqueous phase. Therefore, this polymer KHI is unsuitable for field use. For the neutral and anionic polymers KHI-3, KHI-7, and KHI8, we obtained long induction times at high pH without the presence of clays. When 5 wt % OCMA clay was added at high pH, the performance was still good for all three polymers. The same applied when we added 5 wt % calcium carbonate powder. However, when Wyoming bentonite clay was added, the induction times dropped significantly for all three polymers, both neutral and anionic. Figure 4 illustrates this for KHI-7. This is probably due to this clay being more active and more able to adsorb KHI polymers onto the larger surface area, making them unavailable for kinetic hydrate inhibition in the aqueous phase. We surmise that anionic polymers can still adsorb onto clay with a net negative charge if countercations, such as Ca2+, are present at the polymer-clay interface (Alternatively, Wyoming bentonite may be catalyzing heteronucleation of gas hydrate more than the OCMA clay). However, when we added 0.5 wt % xanthan (used in some water-based drilling fluids), we found that induction times with bentonite were much higher for KHI-3 and KHI-7.22 This may be due to the xanthan adsorbing preferentially to the clay surface preventing the KHI polymer from being adsorbed or that the xanthan acts synergistically, improving the performance of the KHI polymer. KHI-3 and KHI-7 also gave induction times of over 1200 min in a high pH 19 wt % CaCl2 brine at 12.1 °C subcooling and 150 bar in the presence of OCMA clay. We also noticed that high-salinity brines, such as mud II, had fewer tendencies to form hydrate deposits and plugs until high water conversion compared to low-salinity brines. Especially in the presence of KHIs, the slow growth phase could be very long and no plug tendencies were visible until fast hydrate formation occurs. In a highly saline fluid, once some hydrate has formed, the remaining aqueous phase becomes even more saline and inhibited and can thus act as a lubricant for minor amounts of hydrate particles. KHI Performance Tests at 300 bar. We also carried out some tests at 300 bar on KHI-3 and KHI-7 in the presence of 5 wt % OCMA clay to ascertain the effect of pressure. KHI-3 and KHI-7 were chosen to represent the two classes of KHI polymers, vinyl caprolactam and isopropylacrylamide poly(22) Jurek, M. J. International Patent Application WO/2007/143489.
2410 Energy & Fuels, Vol. 22, No. 4, 2008
Kelland et al.
Table 6. KHI Performance Tests on Muds with 6000 ppm KHI, 3.0 °C, 300 bar, and pH 11 with 5 wt % OCMA Clay
a
Table 7. Shut-in Tests for 6000 ppm KHI on Muds II and VII at pH 11 with 5 wt % OCMA Clay
KHI
mud
∆T (min)
ti (min)
KHI
mud
P (bar)
T (°C)
∆T (°C)
none KHI-3 KHI-3 KHI-7 KHI-7
VII VII II VII II
10.6 10.6 12.5 10.6 12.5
0 100 50a 600 200
KHI-3 KHI-3 KHI-3 KHI-7 KHI-7 KHI-7 KHI-7
II IIa VII II IIa VII VIIa
150 150 300 150 150 300 300
0.9 0.9 3.0 0.9 0.9 3.0 3.0
12.5 12.5 10.6 12.5 12.5 10.6 10.6
Average of two tests with ti ) 41 and 59 min.
mers.10 The results are summarized in Table 6. Earlier studies have shown that the performance of KHIs are dependent upon not only the subcooling but also the pressure.23–25 Two muds were used, mud II as used at 150 bar and a new mud VII containing 14.8 wt % NaCl and 10 wt % MEG (also 1.1 s.g.). Using mud II at the same subcooling (12.5 °C) as for the tests at 150 bar, we obtained much worse induction times for both KHIs, confirming the earlier studies on pressure effects. The results were still worse than at 150 bar when we lowered the subcooling to 10.6 °C (experimentally determined) using mud VII. However, although gas uptake occurred, we did not obtain a hydrate plug in any of the experiments, most of which were stopped after running overnight. This was confirmed visually and by no change in the torque measurements on the stirrer. Thus, rapid hydrate formation had not ensued after stirring for approximately 16 h in any of the tests with added KHIs. KHI Shut-in Tests. The final set of tests that were carried out were to determine the effect of a shut-in. Shut-in conditions are particularly vulnerable to hydrate formation in deep-water drilling operations.26 Table 7 summarizes the results of the tests. The experimental procedure was to stir the fluids at a given pressure and temperature inside the hydrate-forming region for approximately 1000 min, then shut-in the cell by switching off the stirrer for 900 min, and then restarting the stirrer and letting the fluids stir for a further 500 min. A “fail” experiment would give some hydrates but not necessarily a plug (because of fast hydrate formation), during the full experimental time of approximately 2400 min. A “pass” would be no hydrate formation detected at all during the whole experiment. In all experiments, we added 5 wt % OCMA clay to simulate low- to mediumactive drilling cuttings. In some experiments, we also added other polymers used in WBMs. These were 0.5 wt % xanthan, (23) Kelland, M.; Svartås, T. M.; Øvsthus, J.; Namba, T. Experiments related to the performance of gas hydrate kinetic inhibitors. In Proceedings of the 3rd International Conference on Gas Hydrates, Annals of the New York Academy of Science, 912, 744, 2000. (24) Arjmandi, M.; Tohidi, B.; Danesh, A.; Todd, A. C. Chem. Eng. Sci. 2005, 60, 1313–1321. (25) Peytavy, J.-P.; Gle´nat, P.; Bourg, P. In Proceedings of the International Petroleum Technology Conference, Dubai, United Arab Emirates, Dec 4-6, 2007; IPTC 11233 (26) Edmonds, B.; Moorwood, R. A. S.; Szczepanski, R. Ultradeep Eng. 2001, March, 7.
pass or fail pass pass fail pass pass fail fail
a A total of 0.5 wt % xanthan, 1.5 wt % starch, 0.15 wt % PHPA, and 0.15 wt % PAC.
1.5 wt % starch, 0.15 wt % partially hydrolyzed polyacrylamide (PHPA), and 0.15 wt % polyacrylamide (PAC). At 150 bar and 12.5 °C subcooling using mud II, KHI-3 and KHI-7 passed the shut-in test with and without the extra WBM polymers. However, at 300 bar and only 10.6 °C subcooling using mud VII, both KHI polymers failed the shut-in test. Of the two KHIs, KHI-3 was closest to passing the test. Hydrate was detected by gas uptake after 10 h into the shut-in period, and there was no plug formed even after restarting the stirrer for several hours, indicating that fast hydrate growth has not yet occurred. In contrast, KHI-7 gave hydrate nucleation almost immediately after the start of stirring in the first period of both experiments at 300 bar. However, no hydrate plug was formed even after the shut-in and restarting the stirring for several hours. Again, it appears that the pressure and not just the subcooling is an important parameter in determining the performance of a KHI. Conclusions We have identified three neutral and anionic KHI polymers, KHI-3, KHI-7, and KHI-8, which can give added subcooling protection to WBMs in the presence of low-active clays (such as OCMA) or drilling cuttings. In the presence of a very active clay, such as Wyoming bentonite, the performance of the KHIs is greatly reduced probably because of the adsorption of the polymer onto the clay. Wyoming bentonite contains a high amount of sodium montmorillonite with a very large surface area available for adsorption, whereas the OCMA clay contains a much more layered structure, with a much lower surface area available for adsorption. However, the addition of xanthan to the bentonite clay/KHI mixture improved the KHI performance. This may be due to preferential adsorption of the xanthan on the clay surface, leaving the KHI polymer free to inhibit gas hydrate in the bulk aqueous phase. It was also shown that pressure and not just subcooling is an important factor in determining the performance of a KHI. Acknowledgment. We thank ENI and Total for financial support of this work. EF800109E
