Analysis of Drilling Fluid Base Oil Recovered from
Drilling Waste by Thermal Desorption
Paper and Presentation Prepared for 13th International Petroleum Environmental
Conference, San Antonio, Texas, October 16th – 19th 2006.
Simon Seaton, Halliburton, Fluid Systems Division
Ron Morris, Halliburton, Fluid Systems Division
Jack Blonquist, DuraTherm Inc.
Barry Hogan, DuraTherm Inc.
Abstract
In 2005 Halliburton began preparations for a major drilling waste management program.
Instead of discharging drilling waste to the environment, the operator decided that oilbased mud cuttings would be brought to a central waste treatment facility and treated
using thermal desorption technology. This technology reduces the residual oil on cuttings
to a more acceptable level prior to disposal. In addition, the operator planned to use the
thermally recovered base oil to build new drilling fluid.
Thermal desorption technology has been used widely in drilling cuttings processing;
however there has been some concern expressed over the quality of oil recovered and its
suitability for re-use. This has been a particular concern when using highly refined, ultra
low aromatic, highly saturated, mineral- or synthetic- based oils. The issue is that the
thermal energy required to distill enough hydrocarbons from the cuttings to render them
suitable for disposal may result in some cracking or other thermal degradation of the base
oil. It also may create aromatics and other undesirable unsaturated hydrocarbons that will
adversely affect the toxicity and possibly even the performance of the drilling fluid.
As a result of these concerns, Halliburton and DuraTherm began a series of tests using
the actual drilling fluid formulations and products that would be used in the field. We
also used a pilot scale mini thermal desorption unit to recreate as closely as possible
actual field conditions. The recovered base fluids then were analyzed for aromatic and
unsaturated hydrocarbon content and suitability for reuse as drilling fluid. This paper
will describe the results of the tests and operating conditions chosen for the project based
on this testing.
Introduction
A major operator awarded a drilling waste management services contract to Halliburton
in November 2005. The contract covered multiple drilling rigs, that combined would
generate at least 50,000-75,000 MT per annum of cuttings contaminated with oil-based
drilling fluid. In 2005, the cuttings were being discharged to the environment along with
an estimated 12,500-18,000 m3 (77,000-113,000 bbl) of drilling fluid base oil. While the
environmental impact of this discharge was mitigated by the use of compliant oil-based
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fluid, the economic impact in terms of loss of base oil was significant. Therefore, the
operator elected to tender for thermal desorption services. Upon award of the contract,
the operator requested that Halliburton define operating specifications for the DuraTherm
thermal desorption technology that would optimize throughput and capacity and yet
ensure that the oil recovered would be suitable for re-use in the drilling fluid. In response
to that request, Halliburton and DuraTherm began the testing and analysis required to
meet these objectives.
Thermal Desorption Technology
The use of thermal desorption technology or thermal desorption units (TDUs) to recover
oil from drill cuttings has been well documented in the industry1,2 and a detailed study of
all available technology and processes was published by Halliburton in 2004.3 In
summary, thermal desorption of oil from drilling cuttings for environmentally acceptable
disposal of the cuttings was identified as an option in the early 1990s. The technology
used for this purpose evolved significantly in the intervening years. In Europe and South
America, the processed cuttings typically measure less than 1% of Total Petroleum
Hydrocarbons (TPH) before disposal in landfills and this was the target selected for the
subject project.
Regulatory agencies in other areas have also set standards for the levels of TPH in
cuttings prior to disposal or discharge to the environment. Some processes do not require
thermal desorption technologies. For example, in the Gulf of Mexico the discharge of
cuttings with TPH levels of either 6.9% or 9.4% by weight, depending on the synthetic
oil selected, is allowed if other toxicity and biodegradation standards are met or
exceeded. These levels of oil on cuttings can be attained with mechanical systems.
However, the trend in environmental regulations is toward greater stringency and
therefore an increased demand for minimal TPH levels in treated cuttings will drive the
development of more oil-removal technologies.4
All thermal desorption processes evaporate the oil and water from the cuttings. The heat
required to evaporate the oil and water provides enough energy to remove and separate
emulsified oil as well. Free and emulsified oil and water are removed by distillation, and
in the process, water evaporates first to produce steam. Oil has a higher boiling point and
evaporates after the water. The production of steam can also assist in lowering the boiling
point of oil.
The goal is to produce oil-free (or ultra-low TPH) solids for disposal by distilling off oils
from the cuttings and recovering oil to be re-used for drilling fluid.
Base Oil Selection
The base oil for this project was selected in advance of the decision to use thermal
technology and had been proven very effective in the drilling operation; therefore there
was no option or consideration to change the fluid. The base oil is a highly refined
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alkane (paraffin), 87% branched or cyclic, and contains no aromatic or unsaturated
hydrocarbons. The physical properties of the fluid are summarized in Table 1.
Minimum molecule size
Maximum molecule size
Saturation*
Aromatic content
C12
C24
100%
0%
*100% saturation is stated on product MSDS, however testing of laboratory samples of base oil showed very small levels of
unsaturated compounds (0.069%) – see Table 3.
Table 1. Physical properties of alkane base oil
Some cracking of base oils has been reported during thermal desorption operations, and
some shift in analyses and the creation of new molecules such as aromatics has been
shown to occur during thermal desorption. This shift and the creation of aromatics and
other unsaturated compounds may negatively affect the toxicity of the fluid, making
exposure more hazardous for personnel, and even negatively affect the performance of
the drilling fluid.
Thermal cracking temperature is a function of molecule size. Larger molecules crack at
lower temperatures. Hydrocarbons that are used as the base oil for drilling fluids contain
relatively short-chain, small molecules that do not crack at the temperatures normally
reached in thermal desorption units. Carbon compounds in the C20 to C30 range, of
which some existed in this fluid, can crack at temperatures as low as 650°F (343°C).
Further, some long-chain and large-molecule drilling fluid additives may also be present
and could crack. It is also possible some drilling fluids additives may act as catalysts and
lower the temperature at which cracking may occur. Therefore, the documented shift to
lower-weight molecules may be the result of the cracking of crude in the cuttings, the
cracking of additives or the cracking of the base oil itself.
When this shift is small, the oil is still reusable as a medium for makeup of drilling fluids
and some loss of the volatiles created can be expected. This loss probably occurs on the
shale shaker screens and other areas where the cuttings are exposed to the atmosphere.
The loss of volatiles in turn raises the flash point of the recovered oil, which is often
higher than that of the virgin base oil.
Laboratory Testing and Results
The first step of testing was to establish the baseline Gas Chromatogram (GC) analysis
for the base oil. This was done by DuraTherm and Halliburton independently and also
supplied by the operator as part of the tender documents. An example of the GC analysis
of the base oil is shown as Figure 1.
The next step was to determine the boiling point of the oil and therefore the operating
temperature of the thermal unit. The material safety data sheet (MSDS) provided
indicated that the dry boiling point of the oil was 620° F (327° C) and this was verified in
laboratory testing (Table 2). As the testing indicated that only 90-93% of the oil would
be recovered at the originally proposed operating temperature of 600° F, it was decided to
run the tests at 650° F. If these were unsuccessful the tests would be repeated at 625° F.
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However, operating the unit at a lower temperature so close to the actual boiling point of
the oil would increase the required cuttings residency time in the TDU and therefore
could negatively impact treatment rates. From a process perspective, the best scenario
was to operate at highest possible temperature without cracking the oil.
IPB
492° F
5%
498° F
10%
502° F
20%
512° F
30%
520° F
40%
528° F
50%
538° F
60%
546° F
70%
560° F
80%
572° F
90%
594° F
93%
608° F
Table 2. ASTM D-86 Method for Distillation of Petroleum Products
Once the initial operating temperature for the TDU process was set at 650° F, the next
stage was to determine the optimal sweep inside the TDU. The options included 1) using
nitrogen (removing oxygen from process) or 2) using the steam sweep that DuraTherm
recommended and had used in their drill cuttings operations to date. The decision was
made to use a lab-scale TDU to test both scenarios measure their effect on the recovered
oil.
Once the operating parameters were agreed, Halliburton prepared a relatively simple, lab
standard, 80/20 oil water ratio drilling fluid using the selected base oil and sent this to
DuraTherm’ facilities in San Leon, Texas. DuraTherm then mixed the fluid with sand to
simulate cuttings. They ran the samples under the different conditions through their
unique mini desorber at 650° F and collected and analyzed the oil samples. These
samples were also sent back to Halliburton’s Houston laboratories where the analysis was
repeated.
DuraTherm’s mini desorber is an electrically heated, insulating heat jacket surrounding a
quartz tube that allows DuraTherm to recreate field TDU conditions in the laboratory
(Figure 2). Ten years experience with the mini desorber indicates minimal difference
between the laboratory and field results. In some cases the field results may be better
because the field unit works under a slight negative pressure, which slightly reduces the
boiling point of the oil.
In a process closely resembling that used with TDU units in the field, DuraTherm was
able to split the recovered oil from the mini desorber into two phases: V1 and V2,
representing two collection points within the TDU. Usually V1 and V2 oils are
combined and re-used. However, as it was felt that V1 oil would have the least thermal
degradation a sample of V1 oil was also provided to Halliburton for additional testing and
analysis.
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The data provided by DuraTherm is presented in Table 3. The base oil tested was the
combined V1 and V2 recovered oil.
Compound
Unsaturated
Hydrocarbon
Lab Standard
692 ppm
0.069%
0 ppm
Aromatic
0%
Table 3. DuraTherm results of mini desorber tests
Nitrogen Sweep
4664 ppm
0.466%
2733 ppm
0.273%
Steam Sweep
1484 ppm
0.148%
612 ppm
0.061%
Further analysis of the oil by Halliburton focused on V1 fluid. As much as 85% of the
fluid was in the V1 cut. It was possible that an even cleaner product could be recovered
and re-used as drilling fluid, while the V2 fluid, if not needed or desired, could be
blended with diesel and burnt as fuel for the TDU. Table 4 shows the results for aromatic
content of the recovered oils when analyzed by Halliburton and Figure 3 shows the nalkane distribution pattern.
Lab Standard
Compound
Aromatics
0.0%
Oxygenated
0.0%
hydrocarbons (<=C8)
C8 Olefins
0.0%
Table 4. Analysis of recovered oil
V1 Only
0.01%
V1 and V2
0.04%
0.02%
0.10%
0.0%
0.05%
Following discussion of this data with the operator, the formulation of the selected
drilling fluid was raised as a point of concern as particular additives used in the
operations could crack or act as catalysts. If this were the case, then it was necessary to
rerun tests using the same products.
A “typical” formulation was agreed with the operator and the fluid mixed at Halliburton’s
Houston laboratory. The tests were re-run by DuraTherm with the steam sweep. Table 5
shows the formulation that was submitted to DuraTherm and Table 6 shows the primary
fluid properties.
Product
Base Oil
Primary Emulsifier
Secondary Emulsifier
Lime
Wetting Agent
Water
Viscosifier
Suspension Agent
Filtration Control Agent I
Filtration Control Agent II
Mud Conditioner
LCM I
LCM II
Sweep Material
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Concentration
m3 or kg/m3
0.625
7.1
15
28.5
7.5
0.122
28.5
15
17.5
17.5
2.5
25
10
0.12
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Bridging Agent
Barite
Calcium Chloride (97%)
Table 5. Formulation submitted to DuraTherm
Plastic Viscosity at 120° F, cP
Yield Point at 120° F, lb/100 ft2
10 Second Gel. lb/100 ft2
10 Minute Gel. lb/100 ft2
Electrical Stability, Volts
Oil / Water Ratio
Water Phase Salinity, mg/L
Mud Density, lb/gal
Calcium Chloride (97%)
Table 6. Fluid properties
10
480
26.6
34
18
11
20
494
85/15
200,000
10.9
26.6
This fluid was then mixed with sand to recreate cuttings tested in the mini desorber by
DuraTherm. The results are presented in Table 7.
Compound
Unsaturated
Hydrocarbon
Standard
Nitrogen Sweep
Steam Sweep
692 ppm
4664 ppm
1484 ppm
0.069%
0.466%
0.148%
0 ppm
2733 ppm
612 ppm
Aromatic
0%
0.273%
0.061%
Table 7. Results of mini desorber tests including new formulation
Steam Sweep 2
360 ppm
0.036%
821 ppm
0.082%
Results
In summary, the oil recovered by the TDU process was determined to be suitable for reuse in the drilling fluid.
The laboratory standard base oil sample was 99.931% saturated. Nitrogen stripping
resulted in a fluid with 99.533% saturated compounds and steam stripping resulted in a
fluid with 99.85% saturated compounds. The lab standard contained no aromatics, while
fluid recovered with steam stripping had an aromatic content between 600-800 ppm
depending on the fluid formulation used. This represents a very small change in the fluid
(six- to eight-hundredths of one percent).
Conclusions
Testing and analysis showed that the thermal desorption technology selected for this
project and processes recommended by Halliburton and DuraTherm could meet the target
TPH of <1% and that the recovered oil would be suitable for re-use as drilling fluid base
oil. The testing also gave Halliburton operating parameters that could be implemented in
the field to prevent any significant cracking of the oil and ensure suitability for re-use.
Based on this analysis, a maximum TDU operating temperature of 650° F has been
selected and the TDU will operate under the steam sweep recommended by DuraTherm.
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It is expected that the field units will give better results than the mini desorber for a
number of reasons, including the ability to control temperature in the actual TDUs much
more accurately, improved control of the steam sweep and the existence of a slight
negative pressure inside the field TDU.
It should also be noted that multiple treatments of the oil will not degrade the oil any
further. Over time the unstable, volatile compounds will most likely be lost to the
atmosphere during circulation of the drilling fluid or they will crack further to gases and
be consumed within the TDU.
Oil quality in the field will be closely monitored at Halliburton’s laboratory on location.
Adjustments can be made as needed, including the isolation of the V1 oil which, with just
0.01% aromatics, has a slightly better profile than the V1+V2 oil combined. The V2 oil
can then be burned as fuel for the TDU if necessary.
It was observed during the testing that certain characteristics of base oils would make
some fluids more suitable for thermal recovery than others, and that base oils could be
chosen for projects that could actually lower the thermal energy required to reach the
target of <1% TPH. This would reduce operating costs and also the volume of emissions
generated by the thermal processes.
Subsequent to completing this study, Halliburton began an in depth study of many
different base oils used in drilling fluids, details of which will be published in a later
paper including a recommendation for a “thermal desorption fluid” specifically designed
to be recovered via thermal desorption with minimal break down or change in the fluid
properties.
Acknowledgements
The authors would like to acknowledge the people who put in the many laboratory hours
that went into this study. The authors thank Halliburton and DuraTherm for permission to
publish this paper.
References
1. Zupan, T. and Kapila, M.: “Thermal Desorption of Drilling Muds and Cuttings in
Ecuador: The Environmental and Financially Sound Solution,” SPE Paper 61041,
presented at SPE International Conference on Health, Safety, and Environment in
Oil and Gas Exploration and Production, Stavanger, Norway, 26-28 June 2000.
2. Wait, S.T. and Thomas, D.: “The Characterization of Base Oil Recovered from
the Low Temperature Thermal Desorption of Drill Cuttings” SPE Paper 80594,
presented at SPE/EPA/DOE Exploration and Production Environmental
Conference, San Antonio, TX, 10-12 March 2003.
3. Stephenson, R.L., Seaton, S.D., McCharen, R., Hernandez, E., Pair, B., “Thermal
Desorption of Oil from Oil-Based Drilling Fluid Cuttings: Processes and
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Technologies” SPE Paper 88486 presented at SPE Asia Pac Oil and Gas
Conference and Exhibition, Perth, Australia, October 18-20, 2004.
4. Veil, J.A., “Drilling Waste Management: Past, Present and Future” SPE Paper
77388 presented at SPE Annual Technical Conference and Exhibition, San
Antonio, Texas, September 29-October 2, 2002.
Figures
Figure 1. GC/MSD data for base oil
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Figure 2. DuraTherm mini desorber
Figure 3. Distribution of n-alkanes in V1, V1 and V2 combined and the laboratory standard base oil.
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