Global LNG Report

Process selection is critical to onshore LNG economics

Despite evolving and diversifying, no one liquefaction process is substantially better than others, mandating that project-specific variables and economics be studied.

Saeid Mokhatab, University of Wyoming, Laramie, Wyoming, and Michael J. Economides, University of Houston, Houston

International LNG trade continues to expand rapidly, with a trend toward ever larger capacity plants. Future LNG plants will have nominal capacities up to 8 million t/annum (MTPA).¹ As LNG trade increases, operators continue to look for ways to lower costs via economies of scale. The effort has concentrated, as plant capacity grows, on building larger, single LNG train plants.

Achieving the desired results requires discussion of available LNG technologies and important criteria for selection. Technology selection starts at an early stage in the life of a baseload LNG project and is typically addressed at the feasibility study and pre-FEED definition stages. Process routes must be chosen for the process itself, utilities and plant offsite units. These include proprietary and non-proprietary technologies. This also applies to the upstream part of the chain, which supplies gas to the plant. Potential options must be identified and evaluation criteria established. Selection could be decided between alternative processing technologies for operating units, the type of major equipment, or utility schemes.²

A number of large-scale plants for producing LNG are under construction or in planning stages. Most LNG contracts specify a range of acceptable heating values for the LNG sold into a particular market. In most cases, this requires that a certain fraction of the heavier hydrocarbon components found in natural gas be removed prior to liquefaction, so that the LNG does not exceed the upper heating value limit. Some natural gases also require removal of the heavy ends to prevent operating problems in the liquefaction cycle, such as freezing of aromatic hydrocarbons at low temperatures.

THE LNG PROCESS

An example of an LNG plant’s overall flow scheme, and the main process units, is shown in Fig. 1. In a typical scheme, the feed gas is delivered at high pressure (for example, up to 1,300 psi and 90 bar) from upstream gas fields via trunk lines and any associated condensate is removed. The gas is metered and pressure-controlled to the plant’s design operating pressure.

Fig. 1. Typical LNG plant’s block flow diagram.

The gas is first pre-treated to remove impurities that interfere with processing or are undesirable in final products. These include acid gases and sulfur compounds (e.g., CO₂, H₂S and mercaptans), water and mercury. Heavier hydrocarbons are also removed from dry, sweet natural gas, using high-level refrigerant to provide the cooling needed to condense the liquids. Residual gas is then liquefied using high-level and low-level refrigerant.

The remaining gas is made up mainly of methane and contains less than 0.1 mol% of pentane and heavier hydrocarbons. It is further cooled in the cryogenic section to about – 160°C and completely liquefied. The pressurized LNG is further sub-cooled in one or more stages to facilitate storage at slightly above atmospheric pressure. Flashed vapors and boil-off gas are recycled within the process.³

LNG is returned to a gaseous state in a re-gasification facility at the customer’s receiving terminal. Table 1 shows typical LNG compositions. If an LNG terminal requires C₂ or C₃ for fuel, it will need to process LNG with a component extraction unit. Although these extra facilities increase capital costs, they can create a chance for competitive pricing, because the plant can meet export specifications while feeding LNG from different suppliers.

TABLE 1. Typical LNG compositions at different terminal locations4

LNG buyers have different requirements. Therefore, reducing C₂ and C₃ at the baseload LNG plant is not desirable because: 1) less LNG is produced; 2) additional compression equipment is required; and 3) there is a desire to operate all LNG trains at the same conditions.⁴

The composition of the co-product liquid stream from the liquids recovery section can be matched to the circumstances of a particular LNG project by selecting the appropriate processing scheme. In locations that have a market for ethane, an ethane product can be produced from the liquids recovery section to feed ethylene plants, etc. If there is no market for ethane, an LPG product can be produced, instead.

Or, if the only need is to control the LNG’s heating value, a condensate product for the local liquid fuels market can be produced. And, for locations where future development may create a market for lighter liquids, or where demand for products fluctuates, processes suitable for variable liquid co-product production can be selected. In all cases, the liquid co-product is controlled to meet the appropriate specification for hydrocarbon liquid streams.

LNG LIQUEFACTION TECHNOLOGY

The liquefaction section is the key LNG plant element. Liquefaction technology is based on a refrigeration cycle, where a refrigerant by means of successive expansion and compression transports heat from a lower to a higher temperature. LNG plants consist of parallel units, called trains, which treat and liquefy natural gas and send the LNG to several storage tanks. Liquefaction train capacity is primarily determined by the liquefaction process, refrigerant used, and largest available size of the compressor/ driver combination that drives the cycle and the heat exchangers that cool the natural gas.⁵

Basic principles for cooling and liquefying gas using refrigerants involve matching, as closely as possible, the cooling/ heating curves of the process gas and the refrigerant. This results in a more efficient thermodynamic process requiring less power per unit of LNG produced, and it applies to all liquefaction processes. Typical cooling curves are shown in Fig. 2.

Fig. 2. Typical natural gas/ refrigerant cooling curves.

Observing the cooling curve of a typical gas liquefaction process, three zones can be noted in the process of the gas being liquefied. These include a pre-cooling zone, followed by a liquefaction zone, and completed by a sub-cooling zone. All of these zones are characterized by having different curve slopes, or specific heats, along the process. All of the LNG processes are designed to closely approach the cooling curve of the gas being liquefied. This is done by using specially mixed multi-component refrigerants that will match the cooling curve at the different zones/ stages of the liquefaction process to achieve high refrigeration efficiency and reduce energy consumption.

The liquefaction cooling curve performance is another benchmark that is reviewed in LNG technology comparisons and is often misunderstood or incorrectly applied when considering energy performance relative to lifecycle cost. Caution should be used with this type of comparison. Detailed knowledge of each liquefaction process design, the options they can achieve at different performance levels along this curve, and these options’ cost impact, is required for a valid comparison.

The liquefaction section typically accounts for 30% to 40% of the capital cost of the overall liquefaction plant, which in turns accounts for 25% to 35% of total project costs. Key equipment items include compressors used to circulate the refrigerants, compressor drivers, and heat exchangers used to cool and liquefy the gas and exchange heat between refrigerants. For recent baseload LNG plants, this equipment is among the largest of its type and at the leading edge of technology.²

Because LNG liquefaction requires a significant amount of refrigeration energy, the refrigeration system represents a large portion of an LNG facility. A number of liquefaction processes have been developed, with the differences mainly confined to the type of refrigeration cycles employed. The most commonly utilized LNG technologies are described below. These processes are used in current plants or are applied in projects in progress. However, there are other processes developed, or in development, for baseload LNG applications, which can be, or are being considered, in feasibility studies or for future projects but are not discussed here.

PROPANE PRE-COOLED MIXED REFRIGERANT PROCESS

The Propane Pre-cooled Mixed Refrigerant (PPMR) process, developed by Air Products & Chemicals Int. (APCI), began to dominate the industry from the late 1970s on. This process accounts for a very significant proportion of the world’s baseload LNG production capacity. Train capacities of up to 4.7 MTPA have been built or are under construction.² BP is partnered in plants using this process at Das Island, Abu Dhabi; Bontang, Indonesia; and North West Shelf, Australia.

The PPMR process, Fig. 3, utilizes a mixed refrigerant (MR) that has a lower molecular weight and is composed of nitrogen, methane, ethane and propane. The natural gas feed is initially cooled by a separate propane chiller package to an intermediate temperature, about – 35°C ( – 31°F), at which the heavier components in the feed gas condense out and are sent to fractionation. The natural gas is then sent to the main heat exchanger, which is composed of a large number of small-diameter, spiral-wound tube bundles. These permit very close temperature approaches between the condensing and boiling streams. The MR refrigerant is partially condensed by the propane chiller before entering the cold box. The separate liquid and vapor streams are then chilled further before being flashed across Joule-Thompson valves that provide the cooling for the final gas liquefaction.

Fig. 3. Typical APCI propane pre-cooled mixed refrigerant process.

In earlier plants, all stages of MR compression were normally centrifugal. However, in some recent plants, axial compressors have been used for the low-pressure stage and centrifugal for the high-pressure stage. Recent plants have used Frame 6 and/or Frame 7 gas turbine drivers. Earlier plants used steam turbine drivers.

A recent modification of the process, which is being considered for large LNG capacity plants (>6 million t/year), is the APX process, which adds a third refrigerant cycle (nitrogen expander) to conduct LNG sub-cooling duties outside the MCHE.⁶

OPTIMIZED CASCADE LNG PROCESS

Phillips Petroleum Company developed the original Optimized Cascade LNG Process (OCLP) in the 1960s. The objective was to develop a liquefaction technology that permitted easy start-up and smooth operation for a wide range of feed gas conditions. This process was first used in 1969 at Phillips Petroleum’s Kenai, Alaska, LNG facility. The facility was constructed by Bechtel and was the first to ship LNG to Japan. It is the world’s first LNG project to achieve 34 years of uninterrupted supply to its Japanese customers. Fig. 4 provides an overall schematic of a typical POCLP.

Fig. 4. Phillips’ optimized cascade process.

This process uses two pure refrigerants – propane and ethylene circuits, and a methane flash circuit – cascaded to provide maximum LNG production by utilizing the horsepower available from 6 Frame 5D gas turbines. Each circuit uses two 50% compressors with common process equipment.

The compressor and turbine packages are manufactured by Nuovo Pignone of Florence, Italy. Brazed aluminum heat exchangers and core-in-kettle exchangers are used for the feed gas, propane, ethylene and methane circuits. All of these heat exchangers, with the exception of the propane chillers, are housed in two “cold boxes.” All compressor inter-cooling, after-cooling and propane refrigerant condensing is provided by fin-fan heat exchangers. The LNG from the last-stage flash drum is sent to the LNG tanks by the LNG transfer pumps, where it is stored at about 70 mbar and – 161°C.

There are advantages and disadvantages to POCLP.⁷ Advantages include low installation costs, as reported for the Atlantic LNG project in Trinidad, plus a two – train – in – one reliability concept, using one train of liquefaction exchanges served by two parallel compressors on each refrigerant.

Disadvantages include many gas turbines and compressors, thus the maintenance requirement can be high. In addition, there are limited train capacities. The largest POCLP train in operation is 3.0 MTPA, while the largest in construction is 3.3 MTPA. Furthermore, the process requires ethylene import for refrigerant make-up. Exclusivity in the Phillips/ Bechtel alliance limits competition in the EPC phase.

The POCLP can provide designs with high thermal efficiency and achieve designs optimized for project economics. The process utilizes proven technology and equipment, and has a wide range of operational flexibility. Turndown rates to 10% are achievable for long-term operation. Due to the pure component systems, the plant has easy start-up and operation. The plant boasts low utility and reduced flaring requirements, because refrigerants are not flared on typical upset conditions. This leads to reduced requirements for maintenance and operational staffing.⁸

PRICO PROCESS

Black & Veatch has developed a proprietary mixed refrigerant process, PRICO, that has been successfully used in baseload and peak shaving applications. This is a single mixed refrigerant loop and a single refrigeration compression system used on an earlier baseload plant in Algeria.

Train capacity has been up-rated to 1.3 t/year per train, Fig. 5. The mixed refrigerant is made up of nitrogen, methane, ethane, propane and iso-pentane. The component ratio is chosen to closely match its boiling curve with the cooling curve of the gas feed. The closer the curves match, the more efficient the process becomes. The mixed refrigerant is compressed and partially condensed prior to entering the insulated enclosure for the highly efficient plate-fin heat exchangers, collectively known as the “cold box.”

Fig. 5. Black & Veatch’s PRICO process.

The cold box contains a number of plate-fin heat exchanger (PFHE) cores that allow multiple streams to be heated/ cooled to extremely close temperature differentials. The mixed refrigerant (MR) is then fully condensed before it is flashed across an expansion valve, causing a dramatic reduction in temperature. This very cold vapor is used to condense the MR stream, as well as the natural gas feed stream. The warmed low-pressure MR vapor is then sent to the compressor for recompression. The natural gas feed stream enters the cold box and is initially cooled to about – 35°C ( – 31°F). The gas is then sent to a separator to remove heavier components, which are sent to the fractionation plant. The expanded MR then cools the light components, primarily methane, to liquefaction temperature.⁹

PRICO greatly simplifies the piping, controls and equipment for the liquefaction unit, translating into capital cost savings of up to 30%.

MIXED FLUID CASCADE PROCESS

The Statoil/ Linde LNG Technology Alliance was established to develop alternative LNG baseload plants for the North Sea. Besides other innovative procedures and concepts, this work resulted in a new LNG baseload process, the so-called Mixed Fluid Cascade Process (MFCP)

Within this proprietary process, Fig. 6, purified natural gas is pre-cooled, liquefied and sub-cooled by three separate mixed refrigerant cycles. The pre-cooling cycle’s cold is transferred to natural gas via two plate-fin heat exchangers (PFHEs), whereas the cold of the liquefaction and sub-cooling cycle is transferred via two spiral-wound heat exchangers (SWHEs) by the other two refrigerants.¹⁰

Fig. 6. Statoil/ Linde’s mixed fluid cascade (MFC) process.

The SWHE is a proprietary exchanger made by Linde. It may also be used for pre-cooling. Refrigerants are made up of components selected from methane, ethane, propane and nitrogen. The three refrigerant compression systems can have separate drivers or be integrated to have two strings of compression. Frame 6 and Frame 7 gas turbine drivers have been proposed for large LNG trains (> 4 MTPA).

The MFCP is a classic cascade process with one important difference – mixed component refrigerant cycles replace single component refrigerant cycles, and thereby improve thermodynamic efficiency and operational flexibility. Several characteristics apply to the MFC process.¹¹ First, MFC is new, and, as a whole, without any industrial references. However, the concept is built up by well-known elements. Additionally, the size and complexity of the separate spiral-wound heat exchangers (SWHE) applied in the MFCP are considerably less when compared with today’s single unit used in dual-flow LNG plants. Furthermore, SWHE technology has been tested extensively as an industrial scale prototype, since 1998, for thermal, hydraulic and mechanical duties, in an LNG facility in South Africa. Last, but not least, MFC allows larger, single compressors to handle refrigerant over a larger temperature scale.

LIQUEFIN PROCESS

IFP and Axens have developed the Liquefin process that aims to produce LNG cheaper than with any other process. Via Liquefin, very high capacities can be reached with a simple scheme and standard compressors.¹² This makes it the choice to be considered for an LNG project today.¹³

This is a two-mixed refrigerant process that is proposed for some new LNG baseload projects of train sizes up to 6 MTPA. The Liquefin process operates according to the basic flow scheme presented in Fig. 7. All cooling and liquefaction is conducted in a plate-fin heat exchanger (PFHE), arranged in cold boxes. PFHE arrangement is at the heart of the liquefaction technology. Significant effort has been expended to assure optimal, fool-proof operation of such an assembly.

Fig. 7. IFP/Axens’ Liquefin process.

The refrigerants are made up of components from methane, ethane, propane, butane and nitrogen. The first mixed refrigerant is used at three different pressure levels to pre-cool the process gas and pre-cool and liquefy the second mixed refrigerant. The second mixed refrigerant is used to liquefy and sub-cool the process gas. Using a mixed refrigerant for the pre-cooling stage, the temperature is decreased down to a range of – 50°C to – 80°C depending on refrigerant composition. At these temperatures, the cryogenic mixed refrigerant can be completely condensed, no phase separation is necessary and, moreover, the quantity of cryogenic refrigerant is substantially reduced. The weight ratio between the cryogenic mixed refrigerant and LNG can be lower than unity.

Overall necessary power is decreased, as the quantity of cryogenic mixed refrigerant is lower, and a good part of the energy necessary to condense it is shifted from the cryogenic cycle to the pre-refrigeration cycle. Moreover, this shifting of energy allows a better repartition of exchange loads. The same number of cores in parallel can be used all along between the ambient and the cryogenic temperature, allowing a very compact design for the heat exchange line. A very significant advantage of this new scheme is the possibility to adjust the power balance between the two cycles, making it possible to use the full power provided by two identical gas drivers.¹³

The Liquefin process is very flexible. It offers more than one possibility to reach large, highly competitive capacities, either by using very large gas turbines (combined cycle) to produce electricity, and large electrical motors (up to 70 MW) in parallel on each cycle, or by using larger gas turbines. Frame 7 gas turbines are proposed for large LNG trains. The Frame 9 has very recently been qualified for mechanical drive. With Liquefin, this would allow capacities of 7 to 8 MTPA with only two main drivers. Although volumetric flowrates are seriously increased, a choice compressor can be found for this case, because the speed of the Frame 9 is lower than the Frame 7 speed.²

The process represents a real breakthrough – the plant capacity can be chosen by considering the economics and marketing possibilities without being bothered by technical hindrances. A total cost reduction per ton of LNG is reported to be 20% when compared to the APCI/MR process. The cost reductions arrive from: 1) increasing the plant capacity; 2) reducing the heat exchanger costs; 3) all-over plate-fin heat exchangers; 4) a compact plot area; and 5) multi-sourcing of all equipment, including heat exchangers.⁷

The Liquefin process has all the positive features of MFCP, with much better efficiency and a smaller amount of rotating equipment. It is particularly well-adapted to the range of 4 to 8 MTPA, per train, with many open options for designing and erecting a plant fully responding to the client’s needs.¹²

DOUBLE MIXED REFRIGERANT PROCESS

Shell developed a Dual Mixed Refrigerant (DMR) process for liquefaction, Fig. 8, with two separate mixed refrigerant cooling cycles. One is for pre-cooling gas to about – 50°C (PMR cycle), and the other is for final cooling and liquefaction (MR cycle). This concept allows the designer to choose the load on each cycle. It also uses proven equipment, e.g. spiral-wound heat exchangers (SWHEs), throughout the process. DMR is the basis of the Sakhalin LNG plant, with a capacity of 4.8 million t/annum, per train.⁵

Fig. 8. Schematic overview of the DMR refrigeration cycles.

Process configuration is similar to the propane pre-cooled mixed refrigerant (PMR) process, with the pre-cooling conducted by a mixed refrigerant (made up mainly of ethane and propane) rather than pure propane. PMR vapor from the pre-cool exchangers is routed via knock-out vessels to a two-stage centrifugal PMR compressor. De-superheating, condensation and sub-cooling of the PMR is achieved by using induced-draft air coolers.

The PMR compressor is driven by a single gas turbine, equipped with an electric starter motor/ generator. Another main difference is that the pre-cooling is carried out in SWHEs, rather than kettles. The pre-cooling and liquefaction SWHEs will be supplied by Linde. The refrigerant compressors are driven by two Frame 7 gas turbines, equipped with a separate variable speed starter/ helper motor. An axial compressor is also used as part of the cold refrigerant compression stages.

The cooling for liquefaction of the natural gas is provided by a second mixed refrigerant cooling cycle (MR cycle). This cycle’s refrigerant consists of a mixture of nitrogen, methane, ethane and propane. Mixed refrigerant vapor from the shell side of the main cryogenic heat exchanger is compressed in an axial compressor, followed by a two-stage centrifugal compressor. Inter-cooling and initial de-superheating is achieved by air cooling. Further de-superheating and partial condensation is achieved by the PMR pre-cooling cycle. The mixed refrigerant vapor and liquid are separated, and further cooled in the main cryogenic heat exchanger, except for a small slipstream of vapor MR, which is routed to the end flash exchanger.¹⁴

Shell has also developed technology to further push the propane cycle capacity, by employing double casing instead of single casing equipment. This reliable method brings the propane-MR process closer to a capacity of 5 MTPA. Another possibility for the propane-MR process is to transfer power from the propane cycle to the mixed refrigerant cycle. The closer coupling between the two cycles by mechanical interlinking of compressors is an operational challenge.

CONCLUSIONS

Continued development of traditional LNG plant designs can be seen by comparing recently commissioned plants to current and planned facilities. While the PPMR process dominates the industry, there has been considerable diversification of liquefaction processes in the last five to seven years.^15,16 Increased competition has led to increased train capacity, improved driver integration and decreased capital costs.

The PPMR process, which is applied in all Shell-advised LNG plants around the world, was originally selected as the basis for the liquefaction design. This process is generally accepted to be the most cost-effective, reliable baseload LNG process available. It covers nearly 90% of the total baseload LNG capacity installed worldwide since 1972. OCLP has been applied at the Atlantic LNG project in Trinidad, and it is the only process being used in an arctic climate. The DMR process is selected on the basis of highest plant efficiency and, accordingly, the highest production capacity for given mechanical driver power, and the lowest specific cost.¹⁴

Studies of the different liquefaction processes suggest there is not one of them, on its own, that is substantially more efficient than the others. Rather, each technology can be competitive within a certain range of train sizes. The ultimate choice of which process to select will remain dependent on project-specific variables and the potential development state of novel processes. 

LITERATURE CITED

¹   Eaton, A., R. Hernandez, A. Risley, P. Hunter, A. Avidan and J. Duty, “Lowering LNG unit costs through large and efficient LNG liquefaction trains–What is the optimal train size,” paper presented at the 2004 AIChE Spring Meeting, New Orleans, Louisiana, April 25-29, 2004.
²   Shukri, T., “LNG technology selection,” Hydrocarbon Engineering, 9, 2, Feb. 2004.
³   Qualls, W.R., et al., “Benefits of integrating NGL extraction and LNG liquefaction technology,” paper presented at 2005 AIChE Spring National Meeting, 5th Topical Conference on Natural Gas, Atlanta, Georgia, April 10-14, 2005.
⁴   Yang, C.C., A. Kaplan and Z. Huang, “Cost-effective design reduces C₂ and C₃ at LNG receiving terminals,” paper presented at the 2003 AIChE Spring National Meeting, New Orleans, Louisiana, March 30-April 3, 2003.
⁵   Smaal, A., “Liquefaction plants: Development of technology and innovation,” paper presented at the 22nd World Gas Conference, Tokyo, Japan, 2003.
⁶   Rentler, R.J., P. Macungie and D. D. Sproul, “Combined cascade and multi-component refrigeration method with refrigerant intercooling,” US Patent 4,404,008, Sept. 13, 1983.
⁷   Mølnvik, M.J., “LNG technologies–State of the art,” Statoil, NTNU Global Watch Seminar: Gas Technology, Norway, Aug. 29, 2003.
⁸   Houser, C. G., J. Yao, D. L. Andress and W. R. Low, “Efficiency improvement of open-cycle cascaded refrigeration process,” US Patent 5,669,234, Sept.23, 1997.
⁹   Swenson, L.K., “Single mixed refrigerant closed loop process for liquefying natural gas,” US Patent 4,033,735, July 5, 1977.
¹⁰   Bach, W.A., “Developments in the mixed fluid cascade process (MFCP) for LNG baseload plants,” paper presented at the World LNG Conference, London, England, September 2000.
¹¹   Heiersted, R. S., R. E. Jensen, R. H. Pettersen and S. Lillesund, “Capacity and technology for the Snøhvit LNG plant,” paper presented at the LNG 13 Conference, Seoul, South Korea, 2001.
¹²   Martin, P-Y., J. Pigourier and P. Boutelant, “Liquefin: An innovative process to reduce LNG costs,” paper presented at the 22nd World Gas Conference, Tokyo, Japan, 2003.
¹³   Fisher, B. and P. Boutelant, “A new LNG process is now available,” paper presented at the GPA Europe Technical Meeting, London, England, February 2002.
¹⁴   Dam, W., and S-M. Ho, “Engineering design challenges for the Sakhalin LNG project,” paper presented at the GPSA Conference, San Antonio, Texas, March 2001.
¹⁵   DOE/EIA, “The global liquefied natural gas market: status and outlook,” Energy Information Administration, US Department of Energy, DOE/EIA-0637, Dec.2003.
¹⁶   Meyer, M., “LNG liquefaction process–Why the big fuss about selection,” paper presented at the IChemE London SONG Meeting, London, England, Nov. 9, 2004.

THE AUTHORS
	Saeid Mokhatab is a senior gas-engineering consultant specializing in hydraulic design and engineering of multiphase flow transmission lines, as well as an advisor on natural gas engineering research projects in the Chemical and Petroleum Engineering Department of the University of Wyoming. Previously, Mr. Mokhatab worked as a researcher at Cranfield University, England, working on TMF3 Sub-Project VII: Flexible Risers. He has participated as a flow assurance consultant and engineering manager in various domestic and international gas-engineering projects. He has published more than 40 academic and industrial oriented papers and reports. Mr. Mokhatab served on the Board of SPE London Section during 2003 – 2005, and is currently a member of ASME/PSD Offshore Technical Committee, ASCE Pipeline Research Committee, GPA Europe, SPE and Sigma Xi.
	Michael J. Economides is a professor at the Cullen College of Engineering, University of Houston, and managing partner of a petroleum engineering and petroleum strategy consulting firm. Previously he was the Samuel R. Noble professor of petroleum engineering at Texas A&M University, where he served as chief scientist of the Global Petroleum Research Institute. Prior to that, Dr. Economides was director of the Institute of Drilling and Production at Leoben Mining University, Austria. Before that, he worked in various senior technical and managerial positions with a major petroleum services company. Publications include authoring or co-authoring of 11 professional textbooks and books, including The Color Of Oil and 200 journal papers and articles. He has had professional activities in over 70 countries.