Collaboration is key for downstream E&C efficiency

April 8, 2002
The world's, refiners are faced with environmental regulatory initiatives, including clean fuels requirements and reductions in air pollution emissions from hydrocarbon processing.

The world's, refiners are faced with environmental regulatory initiatives, including clean fuels requirements and reductions in air pollution emissions from hydrocarbon processing.

In the US alone, present and future compliance is expected to cost between $15 billion and $20 billion, most of which will be spent on new units. Refiners must concentrate capital on air pollution reduction systems, desulfurization, and octane upgrading processes, among others. Although increased refining capacity will result, dramatically increased income to refiners is not expected.

Collaboration via recent mergers enhances engineering and construction economics through shared resources, integrated data management, and increased purchasing power. These mergers include the Phillips Petroleum Co., Bartlesville, Okla., acquisition of Tosco Corp., and the anticipated future marriage of that organization with its equal, Conoco Corp., Houston, the Valero Energy Corp., San Antonio, acquisition of Ultramar Diamond Shamrock, and the newly formed ChevronTexaco Corp., San Francisco.

The desulfurization module is set on its foundation at the $75 million, 400-b/d GTL demonstration plant under construction in Ponca City, Okla. Photo courtesy of Conoco Inc.
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Independent refiners may also find relief from prohibitively large capital requirements needed to meet increasingly stringent fuel specifications and environmental restrictions by collaborating to share noncompetitive cost information or by building centrally located, shared resources such as cracking or hydrotreating facilities.

For example, business-to-business e-commerce creates an integral collaboration link in a supply chain matrix that can lower transaction costs. Software companies, such as SAP, enable shared knowledge and thereby eliminate the need for dual administrative systems, such as MSDS documentation, and still protect proprietary information where appropriate.

Refineries with less than 30,000 b/d of hydrotreating capacity may find themselves at a disadvantage when complying with ultra low sulfur diesel (ULSD) regulations, says Premcor Refining Group Inc., St. Louis, Mo., in terms of capex and operating costs. Such refiners are placed in a less competitive position relative to major refiners.

However, by partnering with local area refiners, a hydrotreating alliance would generate cost savings, provide increased dependability, and capture feedstock synergies by allocating operating costs based on delivered feedstock quality.

Premcor suggests a Midwest ULSD alliance of area refiners to build a shared 50,000 b/d hydrotreating facility to meet the low sulfur diesel specification of 50 ppm in 2004 and the USDL 8 ppm spec in 2006.

Refining

While 16 refinery projects are planned or under construction, none is in the US, despite high utilization rates.

Many refining companies are planning expansions, revamps, or new processing units to take advantage of less expensive crudes. Of the new refining projects listed in the following report, 31% are hydrotreating or desulfurization projects and 17% are hydrogen units.

Petroleo Brasileiro SA plans to revamp 8 of its 11 refineries in Brazil at a cost of $8.9 billion to take advantage of its heavy, low-sulfur crudes. Specific projects are currently in the engineering or construction phase for 6 of those 8 and most will be commissioned in 2004.

ExxonMobil Corp., Irving, Tex., plans to take advantage of low-cost Mexican Maya crude at its Baytown, Tex., refinery. A 40,000-b/d delayed coker was recently brought on stream to process a stable supply of the heavy crude from Petroleos Mexicanos. The project implemented emissions modeling to decrease both nitrogen oxide and volatile organic compounds.

Here at Williams's station 125, Walton County, Ga., foundation formwork is readied for a compressor installation. The 15,000 hp combustion turbine-driven centrifugal compression train is part of the Sundance expansion project. Photo courtesy of Paragon Engineering Services Inc., Houston.
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Also, Valero plans a 45,000-b/d delayed coker in its Texas City refinery to facilitate processing of Maya crude.

Hydrogen production or recovery projects are planned to support hydrotreating and hydrodesulfurization projects.

For example, OMV AG's Schwechat refinery in Vienna, Austria, contracted the newly merged Technip-Coflexip to build a turnkey $30 million, 30,000 cu m/hr hydrogen production unit. This projects supports OMV's future motor fuels specifications strategy with a reformer, high-temperature shift conversion, and high-recovery PSA process. Expected completion is June 2003.

India's government claims it plans total deregulation of its oil industry by April 2002. Engineering studies are under way for numerous refineries, catalytic cracking facilities, crude, and resid units ranging from $500 million to $1.7 billion per location.

The shutdown Mobil refinery in Woerth, Germany, will be moved to new facilities in Cuddalor, India, for Nagarjuna Oil Corp. The $800 million project, managed by ABB Lummus Global, Bloomfield, NJ, is expected to be completed mid-2002.

Pemex plans to spend $19 billion to expand oil refining capacity by 14% over the next 10 years. In addition to the modernization of a majority of its refineries, Pemex must expand pipeline capacity to meet this goal.

Petrochemicals

Engineering studies and site work continue for Ludwigshafen, Germany-based BASF's $2.9 billion grassroots petrochemical complex to be constructed just outside of Nanjing, China. Fluor Daniel, Aliso Viejo, Calif., is the project management consultant and Stone & Webster, A Shaw Group Co., Baton Rouge, La., will perform engineering, procurement, and construction with a 2005 commission date target. The complex will boast a 600,000 tpy ethylene unit, a 400,000 tpy LDPE unit, a 300,000 tpy ethylene glycol unit, a 250,000 tpy ox-alcohol unit, a 160,000 tpy acrylic acid unit, and others.

Another mega project to be completed in 2005 is the Methanex, Vancouver, methanol project on the Burrup Peninsula of Western Australia. Touted as the world's largest integrated methanol production complex, the $1 billion facility will produce up to 5 MMtpy of methanol for export to Asia-Pacific. Natural gas for the project will be provided by the gas fields in the Carnarvon basin.

Two ammonia plants, both claiming to the world's biggest when completed, are in the planning stages.

Oswal Group, India, expects its $700 million, 800,000 tpy liquid ammonia plant for the Burrup Peninsula to take top honors when commission in 2005. Site work should begin by the third quarter of 2002 after the financing is in place. Norsk Hydro, Oslo, Norway has signed a preliminary agreement to purchase the resulting production.

In close competition is the Pequiven, Caracas, plant to be built at Jose, Anzoategui, Venezuela. At a price tag of $1 billion, final capacity will near 1.5 MMtpy.

Gas-to-liquids

Three pilot plant GTL facilities are under way in the US.

Rentech Inc. plans a 2002 start-up for its 800 b/d facility in Commerce City, Colo.

BP PLC has nearly completed the GTL pilot plant at Nikiski, Alas. If all goes well, expansion plans will soon follow in the form of a $500 million, 80,000 b/d commercial facility.

Conoco Inc., Houston, is also completing its GTL pilot plant, this one located at Ponca City, Okla. The 400-b/d demonstration plant carries a $75 million price tag and should be finished next February.

Shell International Gas Ltd. is looking at 7 possible GTL projects worldwide, including locations in Qatar, Argentina, Australia, and Egypt. And Foster Wheeler, Clinton, NJ, won the FEED contract for the 33,000 b/d Chevron Nigeria Ltd. facility in Escravos.

Due to lack of funding, the planned Reema International Corp. 10,000 b/d GTL plant for Port Lisas, Trinidad has been canceled.

Gas processing

Numerous grassroots LNG facilities and regasification import terminals are planned, many of which are currently under construction.

According to CMS Energy Corp., Dearborn, Mich., existing US LNG facilities are projected to increase annual import demand by 440 bcf. This demand is expected to be met by major exporters construction projects such as those in Trinidad, Nigeria, Venezuela, Norway, and Angola.

Among other projects, CMS will expand annual send-out capacity at its Lake Charles, facility to 1.2 bcfd with accompanying storage facilities.

In the US, Cheniere Energy Inc., Houston, continues to plan for increased import demand by acquiring an option for an LNG terminal site at Sabine Pass, Tex. Cheniere also holds options at Freeport and Brownsville, Tex., and expansion engineering work is under way at the Freeport site.

Internationally, BP PLC, Indian Oil Corp., and Petronas have revived tentative plans to invest in a $1 billion LNG import terminal in the eastern Indian state of Andhra Pradesh. Because the power plants driving that demand will not be operational until 2007, expected completion of the 2.5 MMtpy regasification facility is also targeted for 2007.

Nigeria LNG Ltd. continues plans for the expansion of the Bonny Island facility by building processing trains 4 and 5. Planned start-up is 2005 and should bring production up to 17 MMtpy.

Hunt Oil Co., Dallas, has undertaken leadership of a feasibility study to determine the best use for production from the Camisea, Peru gas project. The study should determine the selection of either an LNG facility or a GTL plant, or both. Current estimates show that either project may carry a $1.6 billion cost. Halliburton's Kellogg Brown & Root is to complete the study in the first quarter of 2003.

The 50,000-b/d resid fluid catalytic cracking unit at Chinese Petroleum Corp.'s Tao-Yuan refinery is due to be completed in May. Photo courtesy of LG Engineering & Construction Corp., Seoul, South Korea.
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The US Energy Information Administration predicts that natural gas usage will increase by 50% during the next 20 years. Several natural gas processing plants are on the drawing table to meet that demand.

Enterprise Products Partners LP, Houston, will double inlet capacity of its Neptune plant in St. Mary Parish, La., to 600 MMcfd by 2003. An increase in the local transmission system and the fact that seven power generation plants are now under construction in the area and four more are cautiously planned should ensure optimal capacity utilization.

Louisiana Land & Exploration, a wholly owned subsidiary of Burlington Resources, will increase capacity at its Lost Cabin facility. The Lysite, Wyo., plant can currently process 90 MMcfd but after expansion of the third train by the Washington Group capacity will increase to 180 MMcfd. Because the gas from wells deep in the Madison formation is very sour, special corrosion-resistant metals will be used during construction to withstand the effects of the gas.

Sulfur

Parsons Energy & Chemicals Group Inc., Houston, has contracts for sulfur recovery projects in Saudi Arabia, Kazakhstan, Italy, and the Philippines in various stages of completion. Parsons is in the engineering phase of a Claus unit project for Tengizchevroil at Tengiz, Kazakhstan. The project, when completed in 2005, will process 2,400 t/d.

Technip-Coflexip, Rome, has been awarded a major turnkey contract for the expansion of the Berri Gas plant in Saudi Arabia. The project includes an upgrade of the existing facilities as well as two new sulfur recovery units and additional sulfur storage. Sulfur processing capacity will increase to 3,313 t/d. Completion is scheduled for November 2005.

Pipelines

Worldwide, planned multibillion dollar pipeline projects abound, including ExxonMobil Corp.'s Chad to Cameroon, China's West to East pipeline, the Russia to China pipeline, the Baku, Azerbaijan to Ceyhan, Turkey, pipeline, the Kern River pipeline expansion, Tasmanian Gas Pipeline, Gulfstream, Blue Stream, and the Blue Atlantic Transmission System. Several major US offshore projects include Cameron Highway, Caesar Oil, and Canyon Express.

No decision has been reached to this writing with regard to proposed Alaskan North Slope pipeline projects. In the long run, the question is not whether a pipeline is needed, because despite legitimate calls for NGL and GTL projects to manage available natural gas reserves in the area, it is almost certain that a pipeline will be required in addition to any other option. The questions are; which route should be chosen, what capacity should be targeted, and indeed, how many pipelines should eventually be built. Various studies will determine the best alternative in terms of local and international economics, project financing, available technologies, and regulatory obstacles per scenario.

BGC Gas Inc.'s Bison Pipeline Ltd., Calgary, plans to build a 300-mile, $800 million pipeline from the Athabasca oil sands project to Edmonton. The pipeline will transport 100,000 b/d of bitumen via an insulated system to maintain temperature with minimal use of diluents. A mid-2005 completion is planned.

Iran and Turkey have completed and inaugurated a 1,600-mile natural gas pipeline linking the two countries. The pipeline will supply Turkey with 4 bcm of gas in 2002. Iran has an option to send some of the gas through Turkey and into Europe.