Meeting Archives

Proceedings, Crude Oil Quality Association Meeting

Long Beach, CA, 26 February 2009

COQA gratefully acknowledges Chevron Energy Technology Company for providing a continental breakfast, and Spiral Software Ltd. for providing the morning and afternoon breaks for all meeting attendees.

Links are provided (document) for copies of all of the day’s presentations in PDF format.

Subcommittee Meetings, 8:30 – 10:30 a.m.

Canadian Crude Oil Quality Subcommittee

For his update on the subcommittee’s activities, Bill Lywood (Crude Quality Inc.) presented the “Crude Characterization Form” which is being used to gather data on Canadian heavy oil.  This has been revised from its original version in response to numerous comments.  As Bill had reported at the October 2008 COQA meeting in San Antonio, members are asked to fill out these forms and submit data electronically to Crude Quality Inc. where the data will be collected in a database, run through error checking and outlier removal processes, and reports will be prepared for COQA showing the average quality of different grades at different locations.  Crude Quality Inc. will not share the original data and details about who sent what data. 

 

“How Crude Moves Through the Enbridge System – Quality Perspective”, Ashok Anand, Enbridge Pipeline.  Enbridge is a “common carrier” pipeline company with over 60 shippers, and moves over 70 different commodities between 35 receipt and delivery or transfer locations.  The system consists of 13 different pipeline companies that operate in six Canadian provinces and 12 U.S. states.  By 2012, planned additions will enable it to move crude oil to the Canadian Pacific coast for delivery to the U.S. West Coast or elsewhere, and to the U.S. Gulf and East coasts.  Commodities are grouped into eight types including heavy sours, sweet, condensates, and synthetics.  A quality or equalization bank is being considered to reduce the number of types to five.  To help minimize cross-contamination, a minimize batch size of 60,000 bbls is required of shippers.  A matrix is employed to help minimize unacceptable contamination between adjacent batches; although some lines are dedicated to certain crude types. 

A table has been developed outlining what tank bottoms each crude type can cross at each of Enbridge’s nine breakout locations.  While some larger streams have dedicated tanks, boutique crude streams may have to share bottoms.  Special procedures are employed for handling high TAN crudes and those containing olefins.  Where lines are in laminar flow and batch quality needs to be maintained, batch pigs are used.  Still, there are limitations that can result in some interfacial mixing, such as efficiency of launching and receiving pigs and in determining exact cut points.  Enbridge employs a proven set of principles and practices to minimize undesirable quality impacts.  A judicious system of multi-line splits, sequencing, and tank bottom crossings helps overcome some of the challenges associated with batched pipeline operations.  ITS quality metrics provide benefits across the entire system.

Domestic Trading Center Subcommittee (DTC)

John Maurer, chairman of this Subcommittee since its inception, has been reassigned within Valero.  In his absence, Craig Hoaglin, the chairman pro tem, reviewed a presentation prepared by Clifford Mills on data compiled from several sources on quality of “Domestic Sweet” from samples purportedly collected at Cushing, OK.  These data, however, exhibited some excursions in sulfur content beyond what is expected for delivery samples.  A conference call with Clifford is planned to review the data and determine which are valid.

A sample of Domestic Sweet from Cushing is to be included in a future round of ASTM’s Crude Oil Interlaboratory Crosscheck Program.  This will help validate the accuracy of the data collected to date. 

Energy Intelligence Group, publishers of Oil Daily, remain interested in the work of the subcommittee and have indicated willingness to publish a follow up article in the periodical once a proposal is to be submitted to Nymex.

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From 10:30 – 11:30 a.m. Gerald Bruce of MEG Energy provided two presentations to the group.

“Canadian Crude Quality Technical Association Update”,Gerald Bruce, Vice-President CCQTA, MEG Energy Corporation.  Gerald provided an update that included the Scope and Current Activity of the six active projects within the association, and discussed three project proposals that are under consideration.  The currently active projects are:

·        Iron Fouling
·        Phosphorus in Crude Oil
·        Oilsands Bitumen Processability
·        TAN Project
·        NGL Contamination
·        Condensate/Diluent Quality

The three project proposals that are under consideration are:

·        On-line Contaminant Monitoring
·        Water Free Desalting
·        Fluorocarbons in Crude

The initial Scope of the latter proposal includes gathering information on:

·        The types and concentrations of fluorocarbons used in various oilfield chemicals;

·        Impact of these on refinery processes; and

·        Their impact on finished products and stability in typical refinery unit operations.

 

“Alberta Oil Sands Industry Update”, Gerald Bruce, MEG Energy Corporation.  As Gerald noted in opening his presentation “what a difference a year makes.”  In the eight months since the joint COQA/CCQTA meeting in Calgary, the price of crude oil has plummeted from over $140 to around $40/barrel.  This is posing a number of challenges for the oil sands industry, and many changes are being made or planned.

·    Production forecasts have been adjusted downward.
·    Upgrader projects are being deferred, meaning more heavy blend and less light crude will be produced.
·     Production project applications are being withdrawn,
·     Capital spending plans are being reduced with project timelines extended.

This slowdown in growth rate is focusing attention on sustainability, and the environment – greenhouse gases, CO₂, water, and land.

CAPP continues to forecast growth, but at a slower pace.  By 2020, they project total oil sands production to be about 3.3 million barrels per day, or about 300,000 b/d less than previously forecast.  This will be fairly evenly split between mining and in-situ recovery.

Gerald provided a table summarizing recent announcements of oil sands project delays and discussed a few of them in more detail and with respect to their impact on overall production.

CHOA too predicts that Alberta oil sands production will continue to increase, but at a slower pace than previously envisioned.  With upgrader project cancellations, production will shift away from premium sweet synthetic grades to more bitumen blends.  Infrastructure/pipeline projects continue that will improve access to U.S. and emerging markets.  Finally, the changes taking place are providing an opportunity to rethink the best upgrading strategy.

 

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General Meeting, 1:00 – 5:30 p.m.

In opening the General Session, Harry Giles, COQA Director, gave a brief summary of some of the business conducted at meetings the evening of February 25, 2009.  The first meeting of the initial Board of Directors of the newly incorporated Crude Oil Quality Association was held.  The association was incorporated by the Virginia State Corporation Commission on February 6, 2009.  A number of items needed to be considered at this meeting to comply with Virginia Code pertaining to incorporation of a non-profit association.  These included adoption of Bylaws, election of officers, adoption of several resolutions pertaining to financial matters and application to the Internal Revenue Service for recognition as a tax exempt organization under Section 501 (c)(6) of the Internal Revenue Code.

Following this, the COQA steering committee met to consider a number of the issues related to transition to the new association.  Most of these are expected to be handled through conference calls prior to the next meeting of the Group in Philadelphia on June 18, 2009.   Virginia Code permitting, the steering committee will become an advisory panel to the new association.  At the next meeting – which will be our first on the East coast – it is planned to focus on issues pertaining primarily to PADD I supply and refining.

Technical Presentations

“U.S. Refining Industry:  Forecasts, Capacity, Challenges”, Cindy Schild, API.  In opening her presentation, Ms. Schild reviewed historical and forecast data on trends in recent years in world oil consumption, OPEC production capacity, and diesel, gasoline, and crude oil prices.  She then discussed changes in and projections in the U.S. refinery industry.  While the number of refineries has decreased significantly in recent years, refinery capacity has increased through expansions.  Over the last 5 years, demand for diesel has increased and now accounts for one-fifth of highway fuel.  Diesel demand is expected to grow, while that for gasoline is expected to decline.  Over the last 25 year, sulfur content of crude processed in the U.S. has increased from about 0.9 to over 1.4%.  This has coincided with a decrease in API gravity from about 32.5° to just over 30°. 

Liquids from oil sands comprise ~ one-half of the Canadian crude oil imported into the U.S.  Ms. Schild stressed this is a “reliable and plentiful strategic reserve” and continued U.S. investments are important in helping ensure America’s energy security.  U.S. refineries are currently undertaking or planning for over $30 billion of expansion project to increase their ability to process oil sands liquids.  Ms. Schild provided an overview of the numerous plans to move Canadian crude oil to U. S. refineries.  In closing, she noted there are a number of considerations related to new refinery projects.  Among these are:

·        Supply/demand expectations
·        Climate legislation
·        Tax disincentives
·        CAFE standards
·        Alternative fuels, such as ethanol and biodiesel.

 

“Plains All American Pipelines”, L.P., Dominic Ferrari, Vice President West Coast Pipelines, Plains All American Pipeline.  Plains operates over 17,000 miles of pipeline and has ~ 85 million barrels of storage capacity in their system.  This encompasses over 40 U.S. states and 5 Canadian provinces.  They also operate ~1700 LPG railcars, and truck and barge fleets.  These are functionally grouped into transportation, facilities, and marketing systems for handling crude oil, refined products, natural gas, and LPG.  Plains’ has a portfolio of capital projects planned to be in service over the next several years; many of which involve expansion of existing facilities.

On the West Coast, Plains owns and operates an extensive crude oil pipeline network comprised of 5 systems designed to gather OCS and SJV crude oils for delivery to the Bakersfield and Los Angeles refineries.  These have a total capacity of nearly 700,000 barrels per day, but with a current throughput of just less than 300,000 barrels per day.  Plains also owns and operates two terminal systems on the West Coast.  Plains Product Terminals LLC with a capacity of >10,000,000 barrels for crude oil and products, provides tankage services and pipeline connections throughout the Bay area.  Pacific Terminals LLC with tank capacity of 10,000.000 for crude and fuel oils, provides tankage service and connections to the Southern California distribution network.

 

“Chevron U.S. West Coast Operations Nearing 130^th Anniversary”, Scott Sederberg, Chevron.  Chevron, headquartered in San Ramon, CA, had its origins in the 1870s with the California Star Oil Works (CSOW) which began upstream operations in Pico Canyon near Los Angeles.  There, they operated “Pico No. 4” the first commercial oil well in the Western U.S.  Refining began with CSOW’s still at Newhill, CA in 1875.  Scott used numerous historical photographs in illustrating his presentation.

Today, Chevron has over 15 refineries in 11 countries worldwide.  In addition to their refining operations in California, Chevron Upstream is very active in the San Joaquin Valley where it produces >200 MB/D from ~17,000 wells in eight fields.  Eighty percent of this production is heavy crude, and much of it involves steam flood.  Chevron Upstream is also active in Alberta where they are engaged in mining of Athabasca oil sands, upgrading, and developing a steam assisted recovery process.  Chevron Retail marketing has a significant presence in the West where it markets gasoline, diesel, jet fuel and lubes, and operates over 3400 retail sites.  Chevron Pipeline Co. operates a number of systems that deliver over 2500 MB/D of crude oil, refined products, and LPG, terminals that provide 11 million barrels of storage for crude oil and refined products, and natural gas pipelines that deliver over 2 BCF/day.  Chevron also owns and operates Henry Hub.  Chevron Shipping Co. operates a fleet of vessels that deliver crude oil into their California refineries.  Chevron Energy Technology Co. develops solutions and provides expertise for all of the company’s operating units globally.  They also provide consulting services to industry and government and, through a joint venture with Lummus, license technology worldwide.  Competency extends to a number of disciplines including, but not limited to the earth sciences, reservoir and process engineering, HS&E, analysis, and catalysis.

 

“Understanding the Quality of Canadian Bitumen and Synthetic Crudes”, Pat Swafford, Spiral Software Ltd.  Numerous crude oil streams originate in Canada and include, among others, condensates and light sweets, heavy sours, and synthetics of two types.  Streams from the Western Canadian Sedimentary Basin (WCSB) volumetrically comprise the largest number of Canadian crude oils. Many of these are produced from bitumen, and most are blended to some extent.  These can have some characteristics that can cause processing difficulties if not planned for.  Refiners need to understand the quality issues to successfully handle them from both economic and processing standpoints.  To help illustrate his presentation, Pat showed several yield curves in which he compared a 34° API stream to various WCSB streams.  These clearly depicted how yields differ from a conventional crude.  Other graphs were presented that illustrated differences in several quality aspects for conventional vs. synthetic crude oils.  Diesel cetane index and jet fuel smoke point are generally lower for the synthetic crudes, which can make upgrading to specification challenging.  Many synthetic crudes also have little or no residuum; an important consideration for the refiner with cokers.

To effectively plan the processing of Canadian crudes it is important to have accurate assay data on “as shipped” streams – data that is often not available.  Pat illustrated how batch testing data compiled and published on CrudeMonitor.CA can be used to effectively update existing assays.  Further, determining an optimum mix of crudes in which Canadian crudes are a component is important to traders and refinery planners in making economic decisions.  An example was presented involving a three-component mixture to be processed at a U.S. refinery.  Three scenarios that maximized or minimized components and set max/min limits on sulfur, acidity, and naphtha and vacuum residuum yields were set.

 

“Residual Fuel Market Issues”, Kurt Barrow, Purvin & Gertz.  Overall demand for residual fuel has been declining in recent years, especially in the power generation sector.  Residual bunker fuel demand, however, has increased sharply over the same time span.  Proposed International Maritime Organization (IMO) regulations will result in significant reduction in sulfur emission from bunker fuels over the next 5 to 15 years.  This has major and complex implications for both the shipping and refineries industries.  The shipping industry will need to shift to higher cost distillate fuels or install on-board scrubbers to reduce SO_x emissions.  Security of supply and quality assurance will be other aspects that will be need to be considered in fuel switching.  Phased transition over an indefinite period complicates decision making.  With the proposed IMO changes, the refining industry must consider whether on-board scrubbing will be widely adopted – meaning continued demand for residual fuel – or the market will wane and further investments will be needed to install upgrading technology to convert the “bottom of the barrel.”

Complicating the final outcome will be the role of CO₂ emissions.  Reducing sulfur emissions generally results in an increase in CO₂emissions

·        Through an increase in refinery processing to reduce sulfur content; and

·        Seawater scrubbing releases carbon from seawater and uses energy in the process.

This is a complex inter-industry issue necessitating far reaching and potentially very costly decisions on who invests and what quality of fuel will be needed over the next 5 – 15 years.

 

“Nigeria, Meeting the Challenge of Crude Oil and Gas Production”, Bassey I. Ekpokai, ExxonMobil Nigeria.  Bassey provided an informative overview of Nigeria including its demographics, geography, government, and domestic and foreign policy.  Knowledge of these is important in understanding the current situation in the country relative to oil and gas production.  He then provided background on ExxonMobil’s activities in the country dating back to 1999 when the two companies merged, and on the numerous other companies active in Nigeria’s petroleum industry.

All these companies face a number of challenges in operating in the country and in producing oil and gas.  Such challenges include cost of transportation, equipment maintenance, environmental degradation, Niger Delta militancy, Government policy and regulations, operations’ integrity, safety standards, and widespread corruption.  Together, these are resulting in Nigeria losing her position as a major exporter of crude oil.  In 2006, the country was ranked as the world’s 12^th largest petroleum producer, but in 2007 this had fallen to 37^th.

In closing, Bassey provided a number of recommendations he believes will help Nigeria resume a position as a major source of petroleum.

·        Improve equipment maintenance and calibration;
·        Reduce widespread corruption among company and government officials and others;
·        Improve the lives and wellbeing of the citizens of the Niger Delta through more employment, better environmental management, infrastructure development, and provision of basic amenities;
·        Perform routine staff training; and
·        Improve safety standards implementation.

 

“Heavy Oil Desalting ‘Performance Issues’”, Dr. Davis Taggart, NATCO R & D.  Desalting heavy crude oils such as some of those from Canada can be problematic if operating conditions are not selected correctly.  Demulsifiers are used in the field to dewater crude oils, then again at the refinery.  If the incoming stream is over treated, water content of the crude leaving the desalter can initially decrease then increase with increasing chemical charge.  Heavy streams have lower heat transfer rates and require higher temperature for effective processing.  This increases the potential for crystalline salts to form leading to increased exchanger fouling.  Mixing is less efficient with the heavier streams and tight emulsions can form and contribute to a larger interfacial rag layer of up to about 15% of charge.  An interface drain is advisable, but the rag layer should not be recycled but should be treated separately.  Mud washing the desalter unit should be on a continuous rather than intermittent basis, but this can result in heavier loads with a higher organic content reaching the wastewater treatment plant.

Desalter capacity and throughput are lower with the heavier crude oils.  With the lower density differential between the crude and wash water, separation is slower and can be hindered by the presence of filterable solids.  The type of electrostatic field used can affect salt removal.  In a study in which different types of fields were used, an inlet stream having 300 ptb salt was variously reduced to from 2 to 15 ptb.  Water effluent from the desalter can have heavy solids content – both organic and inorganic – and oil loading, reducing rates in the biotreater plant.

 

This concluded the February 26, 2009 meeting of the COQA.  The next meeting will be June 18, 2009 in Philadelphia, PA.

Harry N. Giles
Director, COQA