Successful Pilot of Thermosyphon Process Heater Reduces GHG Emissions

Successful Pilot of Thermosyphon Process Heater Reduces GHG Emissions and

Operating Costs

W.A. Arnold, SPE, PanCanadian Resources, and J.I. Neulander, Hudson Products Corporation

Abstract

PanCanadian originally pursued thermosyphon technology to

lower operating costs. However, it is now apparent that a

more significant benefit is reduction of greenhouse gas (GHG)

emissions. Other benefits include loss management, increased

safety, improved operability and maintenance cost reduction.

A prototype ThermfloTM thermosyphon process heater was

developed by Hudson Products Corporation (HPC) as a joint

effort with PanCanadian Petroleum Ltd. The unit was

installed in a 320 m3 atmospheric heavy oil tank in

northeastern Alberta in November ’97. Performance testing

was carried out over the next several months and evaluated

using API Standards & Recommended Practices.

The testing was carried out in two phases. In phase one, we

compared the performance of the thermosyphon to a naturally

drafted venturi style nozzle burner in a firetube located in an

adjacent tank. Both units were fired using sales utility gas.

Increased combustion efficiency and improved heat transfer

reduced fuel gas consumption by 33% and cut GHG emissions

by 40%. In phase two of the testing, the prototype

successfully burned solution gas normally vented to

atmosphere. This translates to an annual operating cost saving

of about $40,000 and GHG emission reduction of about

10,000 tonnes per year.

Introduction

The thermosyphon process heater is a means of transferring

heat from an external combustion chamber to liquid inside a

process vessel or tank. It does this without having a flame

within a firetube inside the vessel or tank and is therefore,

significantly more efficient and safer than a firetube.

Employment of a prototype heater in a heavy oil field

production tank pilot project confirmed the concept and the

improved efficiency lead to substantial reduction in GHG

emission, lower operating costs and improved safety.

Background

Production Methodology. The preferred strategy of cold

heavy oil reservoir exploitation in the Western Canadian

Sedimentary Basin is to produce emulsion into field

production tanks from wells drilled on a high density pattern,

often at ten to twenty acre spacing. The emulsion is then

trucked to a centralized cleaning facility, where it is processed

to pipeline specification of 0.5% BS&W and 350 centistoke

viscosity in preparation for transportation to refineries.

Pipelining the emulsion directly to the cleaning plants is

generally not feasible due to the sand cut, high viscosity and

entrained gas. The threat of bottom or side water

breakthrough also introduces risk into the return on investment

for pipelining.

Producing emulsion into field production tanks for trucking to

cleaning plants has its own set of challenges. A property of

low temperature heavy oil emulsion is high viscosity, which in

turn lifts large amounts of sand and entrains gas with the oil.

The entrained gas is in the form of expanding microbubbles

that enhance fluid flow from the reservoir1,2. The

microbubbles continue to expand in the tank, as the pressure

drops to atmospheric. Here the gas slowly breaks out causing

foam to sit on the oil in the tank. This foam layer can be

several feet thick, increasing the risk of the tank overflowing

and causing a spill. It also raises trucking costs by reducing

the pay load. Cold viscous emulsion increases load/offload

time, which also raises trucking costs.

Emulsion Processing. Heating the emulsion breaks down the

foam, drops the sand to the bottom of the tank and separates

the water out of the oil. Introduction of chemical deemulsifier

into the tank or gathering line can assist in this

process. The type and amount of chemical is dependent on

water, clay and sand cut, oil characteristics, cleaning plant

ownership and availability, water disposal options, etc. The

apparent treating cost savings from reduced water cut may be

outweighed by the increase in “slop” (tight interfacial

emulsion) disposal costs that don’t surface for several weeks

or months. The total costs must be included in the analysis.

However, chemicals only enhance the process while heat is

essential.

The heat source usually takes the form of a naturally drafted

venturi style nozzle burner in a firetube. The burners

nominally range in size from 75 to 300 kW (250,000 BTU/hr

to 1,000,000 BTU/hr). The firetubes can be straight through

(shotgun) or U-tube, and range from 100 to 300 mm in

diameter. The nominal BTU rating refers to combustion

capability, not the actual heat transfer. Burner manufacturers

most often report combustion efficiency. The actual heat

transfer is affected by liquid residence time, heat transfer

surface area and fouling of this surface. The actual firetube

heat transfer efficiencies are typically in the 35-65% range3.

An industry benchmarking study4 reports utilities as the third

highest cost driver. Tank heating can comprise one half of

utility costs. Obviously low heat transfer efficiency raises

operating costs, but it also greatly increases GHG emissions.

Firetube Fouling. A serious problem encountered with

firetubes is fouling or coking which leads to the development

of a “Hot Spot”. This hot spot normally occurs due to flame

impingement baking the formation sands, clays, salts,

asphaltenes, etc. on to the outside of the firetube. This coke

product acts as an insulator preventing heat dissipation and

eventually causing the metal to become so hot the tube

collapses. This has the potential for personal injury or death,

equipment damage and production loss. Fires have resulted

due to the emulsion entering the firetube through cracks, and

in some instances, the roof of the tank has blown off. In any

case, significant costs are incurred cleaning up the spill

resulting from the emulsion leak and replacing the damaged

firetube. The tube we replaced for the pilot had significant

buildup that we were unaware of. This tube likely would have

failed within two months.

Integrated Solution. PanCanadian recognized these problems

and implemented a firetube preventive management program

in 1994. We also chose to use an integrated risk management

approach to solve this problem. The integrated solution of the

problem would:

! Lower Operating Costs

! Improve Safety

! Improve “Operability”

! Improve Loss Control Management

! Lower Green House Gas Emissions

Table 1) outlines the methodology of the Hazop Process we

followed. Table 2) contains the results of the exercise that

compelled us to pursue heat pipe technology. (Appendix C

provides a sample calculation to show how we arrived at cost

of keeping emulsion at 85°C.)

PanCanadian started experimenting with heat pipe technology

in 1989. Two heat pipe systems were installed in pressurized

process vessels during 1994 with limited success. The

application of this technology developed very slowly due to

supplier economic stability, technology ownership issues and

failures of heat pipes in unrelated industries. In 1996

PanCanadian approached HPC to develop an alternative

heating system for our atmospheric heavy oil storage tanks.

At the time HPC was a supplier of heat pipes for use in heat

exchangers but not a manufacturer of an externally heated

system. Working as a team, we set out to develop a

thermosyphon process heater.

Prototype Description

Gravity-assisted heat pipes or thermosyphons5 are selfcontained

devices for thermal energy transport. They are

characterized by their ability to transport heat at high rates

over considerable distances, yet require only small

temperature differences to drive the heat flow. The basic

principles of thermosyphon operation are relatively simple.

Referring to Figure 1, the working fluid inside a

thermosyphon exists as liquid and vapor at nearly equilibrium

thermodynamic conditions. During operation, two transport

mechanisms exist – heat and mass transport. When a

thermosyphon is exposed to heat source and sink, the working

fluid equilibrates to an average saturation temperature and

pressure. The temperature of the working fluid is nearly

uniform through out the tube between the temperatures of the

heat source and sink. Heat addition causes the liquid within

the tube to evaporate and enter the vapor phase. Heat removal

at the condenser section condenses the vapor, returning it to

the liquid state. This simultaneous influx and efflux of vapor

creates the driving pressure differential for the nearly isotherm

flow of vapor from the evaporator to the condenser. To

complete this thermodynamic and transport cycle, the liquid or

condensate must be transported from the condenser to the

evaporator. Condensate return is accomplished via gravity

force.

In 1996, HPC began development of the thermosyphon

process heater for use in heavy oil storage tanks. This was a

very challenging application of the technology given the

stagnant fluid and temperature limits of 100oC within the

storage tanks. Drawing on past and recent work on

thermosyphon technology, in mid 1997 a prototype heater was

designed and constructed.

The inherent design advantages of the thermosyphon process

heater over naturally drafted venturi style nozzle burners

include:

! External low pressure burner can utilize lower quality gas

as a fuel source

! External burner and lower surface temperature of

thermosyphons, is safer

! Higher effective heat transfer allows for quicker heat

times, more consistent emulsion temperatures throughout

the tank, lower operating costs and less GHG emissions

Test Design

The field trial was designed using API Recommended

Practices & API Standards to maximize the repeatability of the

results. We chose a site at our Marwayne Field located in

northeastern Alberta that had sixteen wells drilled on ten acre

spacing, with eight wells producing into each of two 320 m3

tanks. We proposed replacing one firetube with the

thermosyphon prototype, allowing direct comparisons of

performance by mitigating the effects of varying ambient

temperature, inconsistent oil properties and differing

production rates on the resultant data. Equipment

specifications are summarized in Appendix A.

Field Description. The Marwayne Field is drilled into the

Mannville group of zones at a depth of about 700 meters. The

wells are drilled with slant rigs, keeping the boreholes as

straight as possible to minimize tubing and rod wear. The oil

is lifted using PCP 15-1400EL pumps (15 m3/d @ 1400 m

head) with 22kW electric motors c/w VFD’s. The two zones

are commingled and yield an emulsion at surface of about 11°

API and 35,000 cP viscosity. Emulsion temperature at surface

is 27° C. The sand cut ranges from up to 30% initially, to 1-

3% after flow stabilization in one to three months.

Test Objectives

Prior to test initiation, HPC and PanCanadian met to confirm

that each company’s objectives were mutually attainable. The

field test was designed to ensure operability and to provide

information about the equipment specifics.

Here is the compiled list of test objectives that we intended to

establish:

! overall thermal efficiency (fuel based)

! heat input and heat transfer rates (tank emulsion heating)

! firing, safety, environmental and operating cost

improvements by implementing the prototype for indirect

heating with burner equipment firing outside the storage

tank causing less coking/build up on firetubes

! operational advantages in implementing thermosyphons

for transferring heat into the tank with high rate of sand

deposits

♦ better temperature control of emulsion

♦ quicker emulsion heating times

♦ improved burner reliability

! energy conservation, fuel saving and decreased CO2 and

NOX emissions on equipment burners

! ability to burn solution gas with no significant decrease in

preceding objectives

Test Procedure

The thermosyphon prototype was assembled at the

manufacturer’s Beasley, Texas facility. The unit was designed

for retrofit installation into the 320 m3 atmospheric storage

tank through the existing 300 mm firetube flange.

Thermosyphon performance was verified by testing the

prototype for equipment and control system operability in a

tank simulator at the Beasley site in Oct ’97. The simulation

was successful, and the prototype was shipped.

The prototype was installed at the field site on November 13,

1997. The assembly and installation of the unit took about six

hours using a maintenance crew, picker truck and a welder.

We were very pleased with the time considering this was the

first time the operations personnel had seen, let alone handled

this equipment. As a prototype, the thermosyphon employed a

number of features to ensure test reliability, which increased

the size of the unit. Plans are already underway to reduce the

size of the external heat processor. In future, standardized

flanges and procedures could further shorten the installation

time.

The testing was scheduled to run approximately three months.

Preparation for and testing was carried out according to API

RP #532, Sect 2, Par. 2.1 & 2.2. The following measurements

were taken during the test using API RP #532, Par. 15:

! Fuel flow rate

! Process flow rate

! Process fluid inlet temperature

! Process fluid outlet temperature

! Process fluid inlet and outlet pressure

! Fuel pressure at the burner

! Flue gas draft profile

To evaluate firing, combustion, heat generation and heat

transfer performance of the thermosyphon, a testing method

was developed in four stages. In stage 1, we would monitor

the flue gas side and measure: fuel gross efficiency; net

efficiency in the fire box; and, combustion efficiency.

Expected duration was one week. In stage 2, we would

monitor the process side and measure: heat transfer; and, heat

absorbed by the process. Expected duration was one week. In

stage 3, we would monitor overall heat balance and

measure: combustion efficiency, heat transfer efficiency, and

relative waste. Expected duration was five weeks. In stage 4,

we would burn solution gas normally vented to atmosphere up

the casing. Expected duration was six weeks.

Stage 3 & 4 ran extended times to gain experience operating

the prototype under field conditions and allow for

optimization of:

! Available heat/ radiant-convection section

! Heat picked up by process / liquid in pipes

! Distribution of heat in lowest row and in between pipes

! Flue gas circulation and distribution in between pipes at

different bundle height inside the fire box

! Stack draft and damper effect

! Size and equipment dimensions to optimize heat transfer

Evaluation

The performance testing compared tank operation,

temperature and energy consumption between the

thermosyphon process heater installed in tank “A” and the

firetube and natural draft burner in tank “B”. The objective

was to compare and investigate Tank A and Tank B operation

by evaluating the following steps:

1. Fuel Consumption - Measuring the differences in

operating Tank A vs. Tank B by maintaining the product

in tanks at the same temperature level.

2. Temperature Gain - Compare operating temperatures in

Tank A vs. Tank B at the same rate of fuel input

comparing temperature increase and response time.

3. Operational Difference - Compare Tank A vs. Tank B by

firing each tank at its maximum firing capacity and

measuring the CO2 and NOX emissions, coking/buildup,

equipment reliability.

Performance and operability of the thermosyphon was

evaluated according to API Standards and Recommended

Practice issued for fired heaters covering the subjects:

" Measurement of the Thermal Efficiency on Fired Process

Heaters - API RP #532 (Aug ’82)

" Fired Heaters for General Refinery Services - API

Standard #560 (Jan ’86)

" Instrumentation and Control System for Fired Heaters

And Steam Generators - API RP #556 (May ’97)

" Process Analyzers - API #555, 550 part II

The flue gas was analyzed according to API RP #532, Par.

1.4.2 using a portable analyzer for oxygen and combustible

gases.

The measured data was interpreted for GHG emissions using

VCR Reporting Guideline Rev 98/April/8, published by the

Canadian Association of Petroleum Producers (CAPP). The

portion of the report containing relavent information is

reproduced in Appendix B. This report converts total

greenhouse gases to a carbon dioxide equivalent (CO2E).

All parameters, fuel consumption, temperature and firing

capacity were recorded on survey forms and the tank heating

efficiency was calculated using computer models and heat

balance calculation forms developed by HPC. All activities

including collection of data and analysis were conducted

according to a Standard Practice Manual certified under ISO

9001. The objective of this quality management system is to

ensure that all project work is performed on time and within

budget and the project will achieve the intended R&D

objectives and is understood, and, if necessary could be

reproduced successfully by others.

Test Results:

Table 3) summarizes the results. Appendix C provides some

sample calculations. The thermosyphon process heater had a

combustion efficiency of 83%, which is extremely high for a

naturally drafted burner. This was 25% higher than the

firetube burner. The effective heat transfer was double that of

the firetube system. The prototype burned 33% less fuel while

providing more heat to the emulsion. GHG emissions were

reduced by 5,000 tonnes per year.

Please note that in this test we adjusted the firetube burner on

a weekly basis to maintain maximum combustion efficiency.

Most field tank burners are lucky to receive annual tune-ups.

For each 1% drop in combustion efficiency, the CO2E

increases by 2%. Or, given the above fuel rates, a fire tube

burner at 50% combustion efficiency would have a 30%

higher CO2E than we reported. This assumes there is no

increase in fuel consumption due to decreased heat transfer

effectiveness. There are several operators who use two fire

tubes per tank to achieve the required heat input.

We were forced to make one change after initial results were

analyzed. In designing the test, we overlooked the fact that

the water cut in the emulsion going in to each tank was

significantly different. Therefore we added a step to the test

by switching which tank and burner system the emulsions

flowed into. This required some mechanical rework of the

gathering lines and extended the test one month, but it did

verify the initial test results.

In the last phase of the pilot, we burned solution gas in the

thermosyphon process heater that is normally vented to

atmosphere out the casing. The heating value was fairly

similar to the fuel gas we were purchasing, but being solution

gas, it was much richer. The richness and moisture content of

solution gas normally causes problems in the nozzles of

firetube venturi burners. We experienced no operational

problems and the thermosyphon process heater performance

was equivalent to using commercial gas. The GHG emission

reduction in this case is 10,000 tonnes per year.

Summary:

All objectives of the pilot were met. PanCanadian Petroleum

Ltd. is very pleased with the THERMFLO Tank Heater

supplied by Hudson Products Corp. Perhaps the most

significant measure of the success of this pilot is operator

endorsement. From the day the unit was fired, it has

performed trouble free and beyond all expectations. The unit

is operator friendly, safe and efficient. The prototype is still in

use. It has the potential of saving about $40,000 per year in

fuel gas costs on this pad, and is the equivalent of parking 9

cars per BOPD.

Acknowledgments

We thank Bob Giammaruti, George Millas and F.G. Russel

with HPC for valuable discussions on the interpretation of the

pilot results and strong R&D support; Jack Whittaker, Steven

Lee, Jody Kissick and Dale Cussack with PanCanadian for

their assistance in executing the pilot, and their helpful

feedback