Ind. Eng. Chem. Res. 1996, 35, 1901-1905
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Oil Contaminant Removal from Drill Cuttings by Supercritical Extraction R. Bruce Eldridge* Phillips Petroleum Company, 176 PDC, PRC, Bartlesville, Oklahoma 74004
Experimental results indicate that supercritical extraction will reduce the oil-based mud contamination of drill cuttings to a level that will allow offshore disposal. Pilot plant experiments were conducted using HFC 134a and propane as the extractive solvents. A commercial process design and cost estimate was prepared. The estimate indicates that the supercritical extraction technology is very competitive with current cuttings’ disposal technologies. The process offers the advantage of allowing the continued use of oil-based mud in environmentally sensitive areas: a major benefit for drilling operations. Introduction A wide range of supercritical extraction processes have been studied over the past decade. Unfortunately, a limited number of processes have been brought to commercialization. The notable exceptions include coffee bean decaffination (Zosel, 1974), supercritical water-based oxidation of pollutants (Shanableh and Gloyna, 1991), and the deasphalting of heavy oils (Leonard, 1981). In order to be competitive, the supercritical extraction process must have a significant advantage over traditional separation processes. This advantage must offset the capital cost of high-pressure equipment and, in the case of a volatile solvent (such as carbon dioxide), the cost of feed compression. For the extraction of FDA-regulated material, carbon dioxide provides the advantage of a nontoxic solvent. For petrochemical applications, the advantages are primarily the ease of solvent recovery. Liquid solvent processes which require a complex distillation system to recover the solvent can be replaced with a supercritical process which reclaims the solvent by a simple pressure reduction. Supercritical processes which develop the contactor pressure with a pump are obviously preferred over processes which use a compressor. Solvents which have good selectivity and capacity for contaminants and have relatively low critical pressures and temperatures are the most efficient. For the removal of hydrocarbonbased contaminants, light hydrocarbons (ethane, propane, butane) readily meet this criteria. Unfortunately, these materials carry significant safety concerns due to their high volatility and explosion potential. The new generation of environmentally friendly HFCs offer some of the benefits of light hydrocarbons while eliminating these safety concerns. The experiments outlined below utilize both propane and HFC 134A to extract oil-based drilling mud contamination from drill cuttings. The proposed processing scheme takes advantage of the solvents low critical pressures and temperatures. Both solvents’ vapor pressures allow the feed to be pressurized with a centrifugal pump, thus significantly reducing the equipment cost and complexity. Cuttings Disposal As wells are drilled large amounts of rock cuttings are produced (detailed properties of the rock cuttings used in the test program are given in Table 1). These cuttings come to the surface in a slurry with the drilling * Current address: Department of Chemical Engineering, The University of Texas, Austin, TX 78712.
S0888-5885(95)00765-2 CCC: $12.00
Figure 1. Typical drilling rig configuration. Table 1. Properties of Rock Cuttings Used in HFC 134a Experiments average particle size (µm) surface area by multipoint BET (m2/g) pore volume (cm3/g)
6.9 (std dev ) 8.3) 6.7 6.7 × 10-4
mud (Figure 1). The slurry is physically separated through a mesh screen (a shaker table) which reduces the oil content of the slurry to around 15%. If an offshore well is being drilled with oil-based mud, environmental regulations severely restrict cuttings disposal options. Current disposal approaches involve reinjecting the cuttings into the producing formation (see Figure 2) or transporting the cuttings to shore for incineration or burial. Transporting cuttings to shore from a remote platform is very costly, and onshore disposal regulations are becoming more restrictive. Reinjection requires that a well slot that could be used for production be allocated to waste disposal. In some locations, the platform operator must demonstrate that the reinjection of oil-contaminated cuttings will not lead © 1996 American Chemical Society
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Ind. Eng. Chem. Res., Vol. 35, No. 6, 1996
Figure 2. Cuttings reinjection process.
Figure 4. Experimental unit. Table 2. Solvent Properties Figure 3. Distillation curve for oil used in oil-based mud (obtained from solvent flash tank, run No. F1).
to contamination of ground water near the reinjection well. These factors have led a high percentage of drilling contractors to the use of water-based, environmentally acceptable, muds. Unfortunately, water-based muds do not perform as well as oil-based muds. The reduced lubrication between the formation and the drill string increases the probability that the string will become stuck in the hole. Drill bit penetration rates are also reduced. Both problems can significantly increase drilling costs. Ideally, an economically feasible system which allows the use of oil-based mud and the offshore disposal of cuttings would be preferred. The goal of the project outlined below is to develop such a system. Oil Removal Oil-based muds are paraffinic in nature with a relatively high boiling range (a typical distillation curve is given in Figure 3). This high boiling range makes oil removal from contaminated cuttings difficult. Various approaches have been attempted to remove the oil from the rock: such as the use of high-temperature (Heilhecher et al., 1982), liquid solvent extraction (Heilhecker et al., 1989) and soap and water washing (George et al., 1984). All these techniques suffer from safety, complexity, or high-energy use problems. A process based on supercritical solvent extraction is a favorable alternative. The patent literature contains some initial work in the area (Eppig et al., 1984). The current project involved pilot plant testing, commercial design development, and a feasibility level cost estimate. The results indicate that the process is technically sound and economically superior to existing technologies. Pilot Plant Test Program In order to prove the process’s technical feasibility, a series of pilot plant tests were conducted. The pilot
properties
Freon 134aa
propane
molecular weight (lb/lb mol) critical temperature (Tc) (°F) critical pressure (Pc) (psia) normal boiling point (°F) liquid density (60 F) (lb/ft3)
102.0 214.1 589.4 -14.8 77.4
44.1 206.0 616.0 -43.8 31.6
a
1,1,1,2-Tetrafluoroethane.
plant system and typical HFC 134a test conditions are shown in Figure 4. The oil-containing cuttings were loaded into a 1-L heated stainless steel autoclave. The autoclave was pressurized to supercritical conditions using a positive displacement pump. Once at pressure, the solvent flowed through the agitated contactor, through a pressure reduction regulator, and into a heated flash vessel. Pressure in the flash pot was maintained at a sufficient level to allow the overhead gas to be condensed with cooling water before returning to the pump feed tank. Two solvents, with similar critical properties, were tested: HFC 134a and propane (properties given in Table 2). Propane was an effective solvent, exhibiting satisfactory levels of oil removal. However, concerns about flammability hazards eliminated its consideration for an offshore platform process. Extraction results for propane and HFC 134a are shown in Figures 5 and 6 with test conditions given in Table 3. The pyrolysis GC output (details of analytical procedure are given below) indicates a very high (>98%) removal of the oil contamination. The photograph shown in Figure 7 dramatically illustrates the level of removal for the initial propane extraction experiments. The plot of autoclave content weight loss, for the HFC 134a experiments, given in Figure 8 indicates that for (WHSV × residence time) values greater than 20, similar hydrocarbon removal was obtained. (Note: weight hourly space velocity (WHSV) is the mass flowrate of the solvent divided by the mass of cuttings and oil initially in the contactor.) Variations in the absolute weight loss above 20 are attributed to the nonhomogenous nature of the contactor feed which was
Ind. Eng. Chem. Res., Vol. 35, No. 6, 1996 1903 Table 3. Pilot Plant Test Conditions for HFC 134A run No.
HFC flowa (SCFH)
cuttings charge (g)
residence time (h)
cuttings weight loss (%)
WHSVb (h-1)
F1 F2 F3 F4 F5 F6
5.3 3.0 5.0 22.6 22.6 36.0
260 256 279 264 251 252
3 1 2 2.5 1 0.5
21.5 16.8 19.7 20.8 21.1 7.1
2.5 1.4 2.2 10.4 11.0 17.4
a HFC flow is measured in standard cubic feet per hour (SCFH) at 60 °F and 1 atm. b Weight hourly space velocity (WHSV) ) mass flowrate of the solvent/mass of cuttings charged to the contactor.
Figure 5. Pyrolysis GC results for HFC 134a run No. F1.
Figure 7. Photograph of treated (BM-36380-81-1) and untreated (B-36380-81-2) cuttings for propane tests.
The distillation curve presented in Figure 3 was obtained from oil collected in the solvent flash tank during the initial HFC 134a experiment. The simulated distillation test (GC based) used to generate the curve detected no residual solvent in the oil. Also, no appreciable loss of solvent was detected during the course of the experimental program. However, the ultimate quanitation of HFC losses must be determined during larger scale “proof of concept” testing. HFC 134a is an expensive solvent, and losses through either absorption into the oil or adsorption onto the cuttings must be minimized in order to obtain favorable economics. Analytical Procedure
Figure 6. Pyrolysis GC results for propane.
charged from the sample container with a large mortar trowel. For all tests, the feed material was obtained from a North Sea oil-based mud-drilling operation. No significant operating problems were experienced during the pilot plant tests. The cuttings tested were very fine, and precautions had to be taken to eliminate their transport into downstream solvent equipment. A fine screen provided adequate protection at the pilot plant scale. Further investigation will be needed to perfect a screen/filter system for the commercial design. The autoclave stirring system was trouble free at the cuttings loading tested. No contactor wall erosion was observed during the tests.
Pyrolysis gas chromatography was used to determine the level of oil contamination of the drill cuttings. The technique utilizes a two-step procedure. The drillcutting sample is heated to 300 °C, and the vaporized oil is carried into a gas chromatograph by a helium carrier stream. A cryogenic trap is used to optimize the gas chromatograph resolution. For the current test, a 30-m capillary column coated with DB-5 cross-linked methyl silicone phase was used. A temperature ramp program ranging from -20 to 320 °C was run to elute the sample. Commercial Design Preparation The commercial design was based on results from the pilot plant test program. Design premises are given in Table 4. A batch system was selected with circulation of the HFC solvent through a stirred contactor (Figure 9). The design rock/oil slurry rate was based on a typical average drill bit penetration rate (rock-cuttings generation rate). The contactors were designed to
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Figure 8. HFC 134a extraction results. Table 4. Commercial Unit Design Premises cuttings production rate (lb/h) (penetration rate of 300 ft/h) Freon 134a contactor mass hourly space velocity (h-1) contactor pressure (psia) (Pr ) 1.10) contactor temperature (°F) (Tr ) 1.05) contactor residence time (h) solvent flash pressure (psia) (Pr ) 0.42) heat exchange
12 000 solvent 10 650 250 2 250 sea water
contain 50% feed and 50% HFC solvent. The solvent flash vessel conditions were fixed to allow for a seawatercooled HFC condenser. A pump supplied feed to the contactors. Two contactor vessels were used; one vessel will be loaded or unloaded while the other vessel is “online”. Heat will be provided to the process by low-level waste heat available on the platform or by a dedicated low-pressure (40 psig) steam system. An augur system will transfer the cuttings from the primary separating device (the shale shaker) to the extraction system. Solids will be discharged from the contactor at the end of the treatment cycle by air pressure or gravity drain. HFC released during contactor depressurization will be recovered by a small vapor recovery system. The HFC inventory on the platform will be minimized with makeup requirements being maintained at an onshore facility and transported to the platform by supply ship. Cost Estimate Results
Figure 9. Commercial cuttings cleanup process.
The cost estimate was prepared using costing algorithms available in the Aspen Plus process simulator. The feasibility grade (+35% to -15%) estimate results are given in Table 5. Onshore cost results obtained from Aspen Plus (Aspentech, Cambridge, MA) were scaled by a factor of 3 to reflect offshore construction and installation. It is anticipated that the system could be built in modules thus simplifying offshore installation. Initial calculations indicate that the weight and space requirements of the supercritical extraction system will
Table 5. Cost Estimate Results (US Gulf Coast, 2nd Quarter 1995) capital cost $4.8 million (offshore basis) operating cost $120,000/yr
not exceed those of a traditional cuttings reinjection system. The installed cost of $4.8 million competes very favorably with data available for alternative technologies. For comparison the literature (Minton and Last, 1994) indicates that a reinjection system for a 20-well
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steady state process is extremely complicated. The mass transfer mechanism changes radically as the solvent removes the oil from the contactor. The model must have properties of both a supercritical fluid/liquid absorption process and a supercritical fluid/solute desorption process. Equations to describe the physics of both situations are well known (Seibert et al., 1988; Triday and Smith, 1988; Goto et al., 1993). However, the simultaneous solution of the applicable equations and prediction of mechanism transition points will be a very challenging mathematical and engineering problem. Literature Cited Figure 10. Modeling considerations.
program would cost $9.6 million. Costs for onshore processing, advanced biodegradable oil-based muds, and water-based muds were given as $18, $19.5, and $39 million, respectively. Conclusions and Future Work The experimental results and cost estimate indicate the process has technical and economic potential. Additional experimental work is need to prove the concept and optimize the process design before installation on an offshore rig can be considered. A semiworks scale unit which takes feed from an operating rig shale shaker will be required to validate the process. The solids transport system needs to be thoroughly addressed. Scale-up data is need for the contactor system and the solvent circulation rate per pound of cuttings must be optimized. This scale-up might be best accomplished through a cooperative effort involving several operating companies. Biotoxicity limits are currently being incorporated into offshore environmental regulations. Any oil removal process must produce cuttings which are not toxic to test organisms. Therefore, at some point in the process development, a series of toxicity tests must be conducted on the cuttings yielded from the supercritical extraction unit. The diversity of organisms used in biotoxicity testing worldwide makes this testing step complicated and expensive. The construction of a fundamental model of the extraction process would be of great benefit. Figure 10 gives a overview of the contacting process. The non-
(1) Eppig, C. P.; Putman, B. M.; de Filippi, P. U.S. Patent 4434028, 1984. (2) George, J. M.; Smith, J. D. Method and Apparatus for Washing Drilling Cuttings. U.S. Patent 4462416, July, 1984. (3) Goto, M.; Sato, M.; Hirose, T. Extraction of Peppermint Oil by Supercritical Carbon Dioxide. J. Chem. Eng. Jpn. 1993, 26 (4), 401. (4) Heilhecker, J. K.; Schoeneman, D. D. Dryer System for Drilling Mud Cuttings. U.S. Patent 4319410, March, 1982. (5) Heilhecker, J. K.; Williams, R. E.; Marshall, W. H. Apppartus and method for Removing and Recovering Oil and/or Other Oil based Drilling Mud Additives from Drill Cuttings. International Patent 89/02774, April, 1989. (6) Leonard, R. E. Energy Efficient Process for Separating Hydrocarbonaceous Materials into Various Fractions. U.S. Patent 4305814, December, 1981. (7) Minton, R. C.; Last, N. Downhole injection of OBM cuttings economical in North Sea. Oil Gas J. 1994, 92, 75-79. (8) Seibert, A. F.; Moosberg, D. G.; Bravo, J. L.; Johnston, K. P. Spray, Sieve-Tray, and Packed High-Pressure Extraction Columns- Design and Analysis. Proceedings of the International Symposium on Supercritical Fluids; Societe Francaise de Chemie, 1988. (9) Shanableh, A.; Gloyna, E. F. Supercritical Water Oxidation - Wastewaters and Sludges. Water Sci. Technol. 1991, 23, 389398. (10) Triday, J.; Smith, J. M. Dynamic Behavior of Supercritical Extraction of Kerogen from Shale. AIChE J. 1988, 34 (4), 658. (11) Zosel, K. Process for the Recovery of Caffeine. U.S. Patent 3806619, April, 1974.
Received for review December 19, 1995 Revised manuscript received March 20, 1996 Accepted March 29, 1996X IE950765T X Abstract published in Advance ACS Abstracts, May 15, 1996.
