1998 00 00
Heavy Oil Upgrading with Water via Super Critical Partial Oxidation
Pre-Project Status Update

RESEARCH PROPOSAL

NCUT, in close cooperation with CS Resources, is trying to set up a joint industry/NCUT sponsored program to investigate low cost upgrading options for reducing diluent requirements (producers' perspective) and improving heavy oil properties (refiners' perspective).

Objective
To develop the proposed projects to the stage that an economic evaluation can be made.

Background
Heavy oil and bitumen production has increased substantially in the last decade and as a result of new technological advancements in drilling and recovery techniques significant further increases are expected. These heavy oils have to be transported from the production area to refineries and upgraders where they are further processed into intermediate products (SCO) or final products. The pipeline companies who transport these feedstocks from the production fields to their markets have minimum specifications for viscosity, density and bottoms sediment and water (BS&W) for the feedstocks that they will accept for transportation. To meet these specifications the heavy feedstocks have to be mixed with varying amounts of diluent depending on the particular feed. In winter for some heavy feedstocks up to about 30% of diluent might have to be added.

The diluent used is normally a condensate separated from natural gas. It consists of C5 and higher hydrocarbons. Forecasts of Canadian heavy oil and bitumen production indicate that production could go up as high as about 900,000 b/d by 2000 from a 1995 level of about 600,000 b/d (Purvin & Gertz, 1996, ACR meeting). A condensate production forecast is essentially flat or increases slightly until 2000 and then decreases (T. McCann, ACR meeting). As a result the expectations are that the diluent supply will be very tight or that even shortages might develop. This issue is forcing producers to look at alternatives, such as diluent replacements, e.g. water, or heated pipelines or modifying the oil properties (i.e. upgrading).

Field Upgrading is a term frequently used to describe the last option. It indicates a type of upgrading process that could be used out "in the field". A certain number of characteristics are presumed to be associated with it in order for it to be feasible and which distinguish it from the more conventional commercial upgrading processes which are typically applied in a refinery setting or in a stand alone upgrading complex. The main characteristics are:

it is simple; the process does not require a host of supporting unit operations or other processes to make it work. The process can be operated with a minimal number of field personnel. This means capital and operating costs will be low.

it works at a small scale (< 10,000 b/d). Though economies of scale still would reduce costs, the process would work with the smaller available volumes in the field without the costs becoming prohibitive.

The product from a field upgrading operation would thus have to meet the minimum pipeline specifications for viscosity, density and BS&W. It is expected that such specifications could be met by a relatively mild upgrading process. Additional benefits might be possible if the upgrading process simultaneously reduces the content of hetero atoms (sulphur, nitrogen, metals, for example) and increases the amount of lighter product (more distillate and less pitch/residual oil and less asphaltenes). It is expected that such a product would fetch a higher price and could open up additional markets. Moreover, no diluent is needed which would free up additional capacity in the pipeline system.

Such a product might have benefits for the refineries too. It is a fact that the quality of crude oils processed in North America is declining. For example, the average gravity of crude oils processed in US refineries has declined 2 points (from about 33 to 31 API) in the last 12 years (Swain, Oil & Gas J, Jan 2, 1995). In addition, production of light conventional crude in western Canada is declining. The latter coupled with the increased production forecasts for heavy oil and bitumen points to the need for additional conversion capacity in western Canada and possibly the US. By performing an upgrading step upstream of the refinery and converting the heavy oil/bitumen to a product similar to conventional crudes, which the refineries can handle, refineries would not have to make additional investments into conversion capacity, while producers would solve the diluent problem, produce a value added product and diversify their market. Potential products could range from heavy sour to light sour to all the way to SCO.

In fact this is happening right now in Venezuela. Five new projects are underway of which 4 will produce a product with a gravity below 30 API. Further processing of these "first stage products" will take place in refineries in the US with which the Venezuelans have formed partnerships.

Producers will probably be of the opinion that conversion is the refiner's problem and the refiner will likely say "it's not my problem, I just buy light crude". Therefore, it would be beneficial and possibly profitable if both parties would joins forces. NCUT would like to help by providing the technical expertise and facilities to obtain the required technical data needed for economic evaluations in order to be able to differentiate between the various options.

Projects
A number of projects to improve the quality of the heavy oil/bitumen are proposed, selected based on the criteria that the processes should be technically simple, have low capital cost and be applicable at relatively small scale (10,000 b/d):

Low severity upgrading; The viscosity of the heavy oil will be reduced at mild conditions but over a relatively long time. This step could also act as a final cleaning step of the heavy oil. Properties other than viscosity are not expected to change much.

Combustion upgrading; Heavy oil will be partly combusted in the presence of oxygen and supercritical water. The heat produced will thermally upgrade the remainder of the oil. Under the conditions employed hydrogen should be formed from the reaction of water with the CO formed by incomplete combustion. This hydrogen should result in hydrogenation of the oil and further improvement of the product's quality.

Extended visbreaking; Initially a low conversion option will be investigated. A novel reactor will be employed, designed to result in a more stable product than obtained from conventional visbreaking which in turn will allow higher severity.

The above projects were developed for a "remote" setting. If the upgrading would be done at a refinery additional synergies will exist which could favour other options. Additional projects can be considered and NCUT can also test commercially available processes for the Canadian feedstocks being considered. Examples are conventional visbreaking, hydrovisbreaking and coking.

Potential Benefits
Potential benefits are: Reduction in produced oil cleanup requirements (water/solids removal); Reduction of diluent requirements; Improvement of additional oil properties such as viscosity, density, sulphur, metals and asphaltenes content; Differentiated product; Additional markets.

Specific improvements will depend on the project and "process severity" applied.

Economics
The decision by companies to proceed will always be based on economics, unless legislation becomes overriding, e.g. zero emissions/waste would favour hydrogen addition vs. coking. By making certain assumptions one can estimate the $ margin available for upgrading the heavy oil to a medium oil that would meet pipeline specifications. We assume that the "upgraded" medium oil would fetch the same price as the posted Medium Blend @ Hardisty (assumption: heavy oil + 30% diluent). By backing out the diluent cost and adjusting for heavy oil volume differences (capacity) one estimates the margin to be around $4-5/b of heavy oil.

If we now take this value and assume we want to build a 10,000 b/d unit, have $2/b operating cost and take the cost of the capital at 15% per year. To (still) break even the maximum "allowable" capital cost comes out at about $5000-$7000 per barrel installed capacity. Thus, if we could build a facility for $5000-7000 per barrel installed capacity and have $2 in operating cost we would still make the same profit as before by blending! If we can do it for less, our profits would be higher. This value includes the whole operation and indicates that high pressure, capital intensive processes, such as hydrocracking, are out of the question for this application. However, such processes are bound to capture additional value because of the prime quality of their product and high liquid yields.

Typical installed costs for a visbreaker and delayed coker are given in "Petroleum Refinery Process Economics" by R. E Maples, 1993 as about $1000 and $2300, respectively, per bbl installed capacity in 1991 US dollars.

A prime unknown is the quality and associated price of the product of any field upgrading scheme. Each proposed scheme will have to be tested to obtain yield and quality data from which possibly a product value can be estimated. Additional benefits could arise for the producer if the proposed field upgrading scheme would result in reduced up front cleanup costs for example. Only if the specifics are known the economics can be calculated.

Dr. Subodh Gupta, PanCanadian
phone: (403) 260-6149
subodh_gupta@pcp.ca

Dr. Theo de Bruijn
National Centre for Upgrading Technology (NCUT)
phone: (780) 987 8710
fax: (780) 097 5349
debruijn@nrcan.gc.ca