Optimization/ Facility Planning Team Weekly Report
Week of September 25 - 29, 2000




ET&S Outages  (Outages: Jerry Graves  713/345-8923) 





System Optimization Team  (Team Leader: Ben Asante  713/853-9432)

TW Fuel Performance Measurement Model (FPM)
Working with the SCADA support group to identify the equivalent SCADA points 
to existing MIPS Points, for conversion of the model to a real-time basis. An 
initial query revealed that only ~50% of MIPS points have a SCADA 
equivalent.  Priority will be given to identification/addition of points on 
the San Juan Lateral and the Thoreau Junction to Needles.  

Developing an estimate of the time required to complete the conversion of the 
FPM Model to a real-time basis.

TW Fuel Performance Measurement for Fuel Overage Forecasting
The Revenue/Risk Management group are analyzing the existing FPM model 
groupings to evaluate the use of our model in combination with their demand 
model.  The combined model would provide fuel burned on forecasted demand.   
Initial analysis looks promising and they hope to give us an answer by next 
week whether the FPM model can be used as is. 

Beaver to Mullinville B-C Sweeping 
 Pipeline operating conditions have been analyzed since the sweep was 
completed on 09/21/00.  Recent sweeps had improved flow efficiency only about 
5%.  Last week's sweep improved the efficiency by 35% to about 85%.  Pressure 
drops decreased from 125 PSI down to about 40 PSI.  Mullinville has operated 
with one less 2000 HP unit while Beaver units are operating with less load 
while producing lower suctions.

Outage Modeling
Ran hydraulic models for Gas Control to determine flows with Bisti down and 
with Unit 303 down.

San Juan Efficiency Study
Developed multiple scenarios for San Juan flows and pressures if the line was 
to be cleaned.  Basic economic analysis was also performed.

Hydraulic Model for EOTT
The current EOTT hydraulic model has been revised to include the dependence 
of the fluid properties on temperature and pressure as well the appropriate 
heat transfer considerations.


Houston Facility Planning Team    (Team Leader: Perry Frazier 713/853-0667)

TW Expansion Studies 
Looked at different combinations of pipe loop and compression trying to 
reduce overall costs.  No luck so far.  A brainstorming session is scheduled 
next week to see if there are any different approaches not considered to date.
El Paso Field Services
Compiling information for inclusion into the Interconnect and Operating 
Agreement between EPFS and Enron.  Mostly locations, materials and POI 
number, expect to have all information gathered by the end of the week.

San Juan Lateral
Enron Operations Services has visited 3 laboratories in the area and compiled 
information on their analysis procedures.  They want Facility Planning to 
help evaluate and choose one for the sample evaluation.  Results will take 
about 2 weeks.  Also, received some expected flow/pressure enhancements for 
the last 30 - 40 miles of the SJ Lateral, using the expected efficiencies 
calculated for a pressure profile taken after the 1998 chemical cleaning 
run.   Results will be reported next week. 

Liberal Operations - PRIDE Meeting
Attended operations meeting in Liberal that covered various areas of 
operations and ways to improve.  Facility Planning did a presentation on the 
proposed Emergency Response Program and provided general information on 
Facility Planning services that can assist Operations.

Prospective Market Zone Wichita, Kansas
Commercial requested market study of competitor pipelines serving the 
Wichita, Kansas area (Duke, KPL, Williams), research possible load 
requirements, and facility requirements to connect the area to NNG's pipeline 
system.  Wichita is located about 90 miles from the Macksville compressor 
station as a crow flies.
Outage Coordination 
 Provided the study to determine flows on the San Juan lateral and mainline 
when Bisti outage occurs in October.  Both San Juan and the mainline will 
have reduced flows.  Study results were given to Market Services. Also 
provided support for System Optimization to determine the flows west when 
Station #3 unit 3 is out of service.

Marketing Strategy Meeting 
Attended and participated in the Marketing Strategy meeting.  Main assignment 
for Planning is to continue looking for revenue generating projects.

E&C
Participated in a review of the responding candidates for the vacant Project 
Engineering position.



Omaha Facility Planning Team     (Team Leader: Steve Thomas 402-398-7468)

Earlville Outage
On October 12th starting at 8:00 am the Earlville unit will be taken down for 
relocation of the blow down silencer.   Solar will also be on site to do some 
bleed air manifold baffle modifications.  After this work is completed, the 
District will perform a water wash in preparation for emissions testing on 
October 16th & 17th.  The unit should be back on-line sometime near midnight 
on October 12th.

With Earlville down for this time frame the flow on the East leg will be 
limited to the 660-680 mmcf/d range.  We anticipate that normal nominations 
will be below this threshold, and that by packing the system the night before 
we will be able to make it through without any impact.   Gas Control is 
putting this outage on the EBB.  From a Marketing perspective we should limit 
short term sustainables, but Ops did not want to call an allocation day.  If 
we did, the allocation would be 86% of firm in Zone D for all deliveries.  

The emissions testing on October 16th & 17th will have very little impact on 
system flows.

Planning White Paper
Planning met with various Marketing representatives to try and attach a value 
to the four ideas put forth in the White Paper.   The ideas were thoroughly 
discussed and the input we received will be incorporated into the Paper.   
One suggestion was that we use the Pricing Desk to determine the value of the 
additional capacity.  We will be meeting with them to do that.  Meanwhile 
research continues on the various costs associated with the White Paper, 
specifically sites for proposed inlet pressure additions.  

Engineering Records Research
EOG - Texas Co. #4 (C.000269.01):  
This is an interconnect where the Texas Co. #4 8" Lateral (OKG-19301) 
connected to the 24" OKM-12001.  An incorrect line number on the project 
authorization located the project six miles upstream of the actual site.  
Engineering Records did not have the one page amendment with the project 
authorization to explain who owns and operates the facilities.  Texas Co. #4 
facilities had been removed.  The remaining pipe downstream of the compressor 
site to OKM-12001 (approximately 4.5 miles) has been transferred to EOG 
Resources as of June 16, 2000.  (Project Authorization C.000369.02/Removal).

Ogden H2S Monitor (SN0157):  
Verification of materials used in the construction of the monitor was 
needed.  Operations confirmed that a Farm Tap Assembly was used to create the 
monitoring facilities, not to install a farm tap within the Ogden Plant yard. 
 
Cedar Falls #2
Marketing needed to know if there was any money left in the work order to 
purchase a new regulator, since the interruptible peaking turbine load is 
causing problems with the existing regulator.  Property Accounting reported 
the amount remaining, but it will not be enough for a new regulator.

St. Croix Valley
Provided options for the proposed ten year expansion for St. Croix Valley.  
Examined cost versus incremental growth on the Black River Falls Branchline.  
Provided an analysis for option of integrating the growth with the Wisconsin 
Gas proposal.  Following the latest strategic marketing meeting, will examine 
compression alternatives for St. Criox Valley as a stand-alone project.

Grimes #1 TBS - Pressure Increase
Working with Marketing and the Field.  Examined several options regarding the 
customer,s request for a pressure increase to a delivery of 150 psig.  
Marketing will examine all the options in order to determine best strategic 
fit for the customer.

Ogden Building #2 Discharge Pressure
Research has been completed in trying to locate documentation that supports 
the 1000 psig MAOP for the building #2 discharge header.  The supporting 
documentation has been forwarded to Lisa Choquette in Codes for approval.  If 
documentation is approved as supporting evidence for the 1000 psig MAOP then 
only minor controls work will be required in the field in order to increase 
the discharge pressure of the building #2 engines.  

Pengilly TBS - Mesabi System
Marketing was presented with two separate estimates for modification required 
to increase firm at Pengilly from 12 mcf/day to 210 mcf/day.   The first 
estimate for $85,000 consisted mostly of contract labor with field personnel 
only installing the EFM.  The team responded with a proposal that they would 
be willing to do all of the labor if it could be scheduled during Jan-March.  
A second estimate of $66,000 was submitted to Marketing, which included all 
district labor.  This estimate is contingent on completing the deal prior to 
Dec 31,2000.  If a deal is made after Dec 31, 2000 then the higher cost 
estimate applies.

Monroe #1 TBS Mods / Pressure Increase
The Monroe #1 TBS Mods Project was released to Engineering.   The project was 
the result of WIGas raising the IT load by approximately 4000 mcf/day.  They 
also requested a pressure increase at the station from 80 psig to 275 
psig.    A Form 2476 "Pressure Increase Request Form" is being circulated for 
signature.  The project has a targeted Nov 30, 2000 in-service date.  The 
modifications consist of replacing both meters with spool pieces and 
performing a pressure test to upgrade the MAOP.

Milbank Project
Continued gathering data to model the Milbank system as it is today.

Melbourne #1 - Project Release
The Melbourne #1 TBS Mods project was released to Engineering.   The project 
consists of TBS mods to support the increase of firm from 330 mcf/day to 500 
mcf/day at Melbourne. Presently the Marshalltown B/L is constrained and could 
not support the incremental firm.  Alliant will realign gas away from the 
Marshalltown #1 TBS which is at the end of this B/L to the Marshalltown #1A 
TBS which is on a different B/L.  This will open up capacity on the line for 
this new load.   The project has a targeted Nov 30, 2000 in-service date.  
Modifications consist of replacing the first and second cut regulators and 
replacing the meter.

Adel #1A TBS Mods - project release
The Adel #1A TBS Mods Project was released to engineering.  This project was 
a result of the customer wanting to convert an existing IT load at Adel #1A 
to a Firm load.  The new Firm load will be 1400 mcf/day.   The project has a 
targeted Nov 30, 2000 in-service date.  The station will have a new meter 
installed along with piping size modifications.

Ethanol Injection
Reviewed and researched (for Marketing) the possibility of injecting Ethanol 
into the pipeline for a possible "Green Energy" rating and as a means of BTU 
enhancement.  Since ethanol would remain a liquid at any normal pipeline 
conditions, even atomizing the ethanol at the point of injection would not 
insure the Ethanol from liquefying, dropping out and collecting into the 
pipeline low spots.  Also, there were many issues concerning possible liquids 
entering the fuel systems of our equipment and other customers, equipment.  
Planning recommended that this project not be pursued.

Researched (for Marketing) was the possibility of burning a Methane/Ethanol 
mix in our equipment (i.e.: Turbines) in order to receive a "Green Power" 
rating.  Solar was contacted concerning the possibility of "co-burning" 
ethanol and methane.  As a manufacturer they said they would be willing to 
work with us, however, they only recommended it if it were to be a constant 
fuel source.  Solar said there would be considerable fuel injection system 
retrofits required.  Also, if this were not a constant fuel then there would 
have to be two separate fuel systems (co-burn and methane only) and a 
complete fuel control system change.  With all that the project has been 
deemed cost prohibitive.

Vapor Injection of Propane (VIP Service)
Research was started for Marketing into the possibility of injecting 
vaporized propane into the pipeline as a way of increasing capacity during 
peak days.  Upon initial review many questions were generated by the planning 
team concerning specific requirements of the new service (i.e.: # of days/yr, 
firm, daily firm etc.)  Planning awaits feedback from Marketing before any 
more action is taken.

Electric Generation 
Proposal was reviewed for Marketing from APA for an engineering study to 
review the possibility of utilizing stand-by generators as electric producers 
for the Utilities during peak power times in the summer months.  A few 
discrepancies were found and are being worked out before APA can be released 
to complete the engineering study.

Beaver Dehy
A request was received from John Sturn of the optimization team to review the 
Capacity of the Mole sieve Dehy system at Beaver Compressor Station on the SE 
24" line.  Beaver is considering a capital project to re-route the dehy 
system that is currently piped into the suction of the station to the 
discharge, thus increasing the capacity.  

Cogentrix Power Plant
Three detailed cost estimates for the Cogentrix Power Plant proposals were 
prepared and forwarded to Marketing.  The details of the cost estimate 
included a breakdown of costs for:
Material Costs
Labor
Freight and Taxes
Surveys/Permits
Construction Support
District Labor
Engineering/Drafting/As-builts
Contingency
Overhead
AFUDC
The break down of costs was done for the Sheldon, Lehigh, and Raun projects 
in Nebraska and Iowa.

Cherokee Ethanol Projects
Seven sites were examined for a proposed ethanol plant in Cherokee County, 
Iowa.  The delivery volume was for 8 MMCF/D at a delivery pressure of 70 
psig.  It was assumed for this study that the initial load would be for 4 
MMCF/D for two years and then increase to the 8 MMCF/D level.  The cost 
estimate assumed that the initial design would be for the 8 MMCF/D.  This was 
done to reduce the cost for the project.  Each cost estimate was done for a 
firm transport level and an interruptible transport level (14 cost estimates 
total).  Two of the sites are on the C line approximately 10 miles southwest 
of the Paullina Station.  The remaining sites were on the Storm Lake/Lytton 
Branchline.