1. CLASS PROJECT
FUNDAMETALS OF SUBSEA ENGINEERING (ENGR 689)
This project is done as a part of the completion requirements for the above course.
Completed & Presented by:
• ASHWIN GADGIL (M.S Ocean Engineering)
UIN: 523002123
• BYUNG JIN KIM (M.S Ocean Engineering)
UIN: 424002594
• THOMAS DELCOURT (M.S Ocean Engineering)
UIN: 124004654

2. • The first two wells for the Red Hawk development in GB 877 are online and flowing. A third exploratory
well has been drilled and is planned for the development. It is located about 1 mile due South and ½
mile East of the current GB 877 Well #1 and still within block GB 877 but in 5260 ft of water.
• CLASS PROJECT – Prepare a proposal for the optimum development of this third well. (Due
before end of May 4)
• Additional Information:
• Use the information provided in the Scenario Homework questions as well as the answers discussed in
class. Regarding homework outcomes, you may assume that
– WEEK 1 forging hardness – forging was successfully reheat treated and suitable
– WEEK 2 Your company did not participate in the offset well
– WEEK 3 Issues with the predrilling well results were resolved, and included in the design basis. The oil zones will be
developed separately, in a completely different project
– WEEK 4 The oil zones are not part of the scope of this project
– WEEK 5 The flowline permit documentation issues are fully resolved, the flowlines are installed
– WEEK 6 Oil reservoir development is planned to be separate from this class project
– WEEK 7 Quayside testing issues resolved, found a faulty fitting in test equipment. Both Red Hawk trees are
successfully installed and flowing
– WEEK 8 Legacy connector issues are fully sorted out, connector is fine
– WEEK 9 Surplus tree decision is still up in the air
– Additional info from remaining scenario homework assignments may be included
• The third well has been drilled but not completed. It will be completed by a different rig than the one
used for the first two Red Hawk wells.
• Assume the Red Hawk project has been successfully completed, started up and flowing, as per the
design basis
• Assume the new reservoir is similar to the existing Red Hawk wells except for some slight differences in
subsea surface elevation.
• A Design Basis has been completed for the first two wells and is attached.
• Utilize drawings from the course provided in eCampus, ie: Wellhead Layout Area, Overall Field Layout,
As-Built 5” Pipeline, 5” Jumper, Umbilical Section, etc.
PROBLEM STATEMENT

3. GRADING:
• Accuracy of deliverables, demonstrate understanding of technical material and
underlying design, execution and operational considerations
• Overall presentation quality – concise, clearly communicated, relevant detail
provided. Assume you are on the job now, done with school, and this is your first
assignment
DELIVERABLES:
• Update and complete the Design Basis for the third well. Show assumptions, be able
to explain your reasoning
• Evaluate tie-back options and recommend your proposed optimal tie-back option
based on economics, and ability to operate. Show your reasoning.
• Technical Deliverables
1. Create a seafloor layout of your recommended option specifically showing valve locations and tie in
points, controls and interface details as appropriate
2. Create a subsea equipment list identifying major components to be purchased, and any important
materials considerations or other interfaces.
3. Update the Red Hawk field P&ID to reflect the addition of this tieback, including details on valve locations,
connections, injection points
4. Prepare a block diagram control system sketch showing topsides to subsea end user control system
components, and describe the changes to topside equipment that need to be evaluated.
• List your top three uncertainties or areas of risk or concerns and how these should
be managed.

4. Index
• Introduction
• Updated Design Basis
• Viable Options Under Consideration
• Pros & Cons Of Each Option
• Specifics of the Selected Option
• Seafloor and Drill Center Plans
• Flowline Temperature Simulation
• Piping and Instrumentation Diagram (P&ID)
• Equipment List
• Block Diagram Of Control System
• General Operating and Control Procedures
• Top 3 Uncertainties and Possible Solutions
• References

5. • The first two wells for the Red Hawk development in GB 877 are online and
flowing. A third exploratory well has been drilled and is planned for the
development. It is located about 1 mile due South and ½ mile East of the
current GB 877 Well #1 and still within block GB 877 but in 5260 ft of water.
• The Well can be marked up on the field to be at the edge of a Hazard mass.
• In this project we have looked at 3 possible options to tie back the well into
the SPAR.
• The first option is a tie back to the existing manifolds of Tree #1 and #2.
• The Second Option is a route through the Hazard mass directly into the
riser via an entirely independent flowline
• The third option considered are independent flowlines directly to the risers
via the same route as for Tree 1 & 2 flowlines.
• Note: There might be other options as well but the authors have selected
these 3 based on the most popular practices in the industry, and also
maintaining a practicality in approach.
Introduction

6. Design Basis
Anadarko Red Hawk Design Basis
General Data Well 1&2 Well 3
Production - Oil or Gas Gas Gas
Gas Lift No Maybe
Gas Compression No No
Produced Water N/A N/A
Water Injection N/A N/A
Water Depth 5300 ft 5260 ft
Field Life 20 yr 20 yr
Primary Depletion or Waterflood? Dep Dep
Dry Tree or Wet Tree? Wet Wet
Type of Artifical Lift? N/A N/A
Note: As the well production is yet to be started it can not be determined if the
Gas lift system is needed as the flowrates are undefined, but authors
recommend that design should be made considering the induction of a gas
injection system near the well if desired later on.

7. Wells Number of Production Wells 2 1
Number of Production Well Locations 2 1
Number of Water Injection Wells 0 0
Number of Water Injection Well Locations 0 0
Water Production Rate per well, bwpd N/A N/A
Water Injection Rate per well, bwpd N/A N/A
Producing Water Cut, Max. % N/A N/A
Comments none none
Reservoir Reservoir Datum Depth, ft TVDSS 11-13K ft 11-13K ft
Reservoir Drive Mechanism Pressure Pressure
Initial Reservoir Pressure, psia 6900 6900
Initial Reservoir Temp, °F 150 150
Gas, SG TBD TBD
Methane TBD TBD
CO2 TBD TBD
H2S TBD TBD
Produced Water Salinity, PPM TBD TBD
Comments none none

8. Flow Assurance SITP @ Mudline (ML), psia 6900 6900
FTP @ Initial Rate @ ML, psi 5000 5000
Static Shut-in Tubing Temp @ ML , 140 140
Initial Flowing Tubing Temp @ WH ,°F 150 150
Initial FWHP, psia 5000 5000
Initial FWHT, Deg.°F 150 150
Chemical Injection:
MEG Yes Yes
LDHI Yes Yes
Hydrate formation potential Yes Yes
Emulsion formation potential N/A N/A
Asphaltene Content N/A N/A
Asphaltene Formation Potential N/A N/A
Reservoir Souring Potential N/A N/A
Barium Content in Formation Water N/A N/A
Barite Formation N/A N/A
Calcium Content N/A N/A
Calcite Formation N/A N/A
Expected TDS (total dissolved solids) N/A N/A
Foaming Potential N/A N/A
Scaling Tendencies N/A N/A
Wax Content N/A N/A
WAT ,°F (Wax Appearance Temperature) N/A N/A
Note: Since the 3rd well is predicted to be similar to the earlier ones, chemical and
pressure properties are assumed to be the same for the purpose of initial design.

9. Subsea, Umbilicals and Flowlines
Sub-Sea Wells Type Completion Horizontal Horizontal
Wellhead Flowing Pressure, psig 5000 5000
Maximum SITP, psig 6900 6900
Wellhead Flowing Temperature, oF 150 150
Flowline Arrival Temperature, oF 90 74.31
Riser Base Gas Lift Kickoff N/A N/A
Subsea Manifold Gas Lift N/A N/A
Downhole Gas Lift N/A N/A
Subsea Choking? yes Yes
Design Life, yrs 20 20
Design Pressure , psig TBD TBD
Sub-Sea Facilities Design Temperature, oF 150 150
Subsea Tree Size 4 x 2 4 x 2
Subsea Tree WP 10000 psi 10000psi
Subsea Tree Trim HH -1.73 °
Subsea Well Jumper Yes Yes
Subsea Manifold Yes Yes
Flowline Jumper Yes yes
PLET Yes Yes
HIPPS No No
Control System Type E/H E/H
Topside Controls - List Items
HPU Yes Yes
MCS Yes Yes
TUTA Yes Yes
Chemical Inj Storage Yes Yes
Note: The Flowline temperature is predicted via a temperature simulation model
developed by the authors which will be explained later on in this presentation.

10. Umbilicals No. of Control Umbilicals 1 1
Control Umbilical Size 6 in 6 in
Control Umbilical Configuration SS Tubes SS Tubes
No. of Power Umbilicals Inc. Inc.
Power Umbilical Size Inc. Inc.
Power Umbilical Configuration 3 TP 3 TP
Umbilical Termination Assenbly Yes Yes
Flying Leads Yes Yes
Subsea Control Modules Yes Yes
Subsea Metering No No
Subsea Boosting No No
Subsea Chemical Distribution No No
Installation Tools Yes Yes
Note: The existing umbilical is assumed to be designed for further
expandability and hence the existing umbilical is being extended to the 3rd
well for all options under consideration.

11. Prod Flowlines Diameter, inch 5 1/2 OD 5 1/2 OD
Wall Thickness, inch 0.85 in 0.85 in
Length On Bottom/No. 10000 ft 10000= 7920 ft
Length for Riser/No. 7200 ft 7200 ft
Flexible Pipe Length Top of Riser/No. N/A N/A
Corrossion Allowance, inch 0.06 0.06
Flowline design based on API RP 1111? Yes Yes
Wet Insulation Thickness, inch N/A N/A
PIP Required? No No
Outer Pipe Size N/A N/A
Coiled Tubing Access Required? Yes Yes
Bi directional Piggable Flowlines Req.? Yes Yes
Other Flowlines Diameter, inch 5 1/2 OD 5 1/2 OD
Wall Thickness, inch 0.85 in 0.85 in
Length On Bottom/No. 10000 ft 10000+7920 ft
Length for Riser/No. 7200 ft 7200 ft
Flexible Pipe Length Top of Riser/No. N/A N/A
Corrossion Allowance, inch 0.06 0.06
Flowline design based on API RP 1111? Yes Yes
Wet Insulation Thickness, inch N/A N/A
PIP Required? No No
Outer Pipe Size N/A N/A
Coiled Tubing Access Required? Yes Yes
Bi directional Piggable Flowlines Req.? Yes Yes
Note: The Flowline thicknesses determined are also a bi-product of the
temperature simulation, which indicated that even with the same amount of
insulation and with the added length the temperature does not go into to the
predicted hydrate formation range.

12. HULL Type SPAR SPAR
Weight, tons 7300 7300
Production Deck Size 112x133 ft 112x133 ft
Spar Deck Size 91x75 ft 91x75 ft
Diameter, ft Aprox 92 ft Aprox 92 ft
Length, ft 560 ft 560 ft
Risers Type SCR SCR
Gas Production 4 - 6 in 4 - 6 in
2 installed, 2 spare
Oil Production 2- 10x6 PIP 2- 10x6 PIP
2 spare
Gas Export - installed 16 in 16 in
Oil Export - spare 10 in 10 in

13. Option1: Tie Back to Existing Wells
Green: Umbilical; Red: Flowlines

14. PROS & CONS
PROS CONS
Less flowline used compared to direct
tie back hence cheap
Increased number of components.
Allows expandability near the 2rd well
due to extra hubs available on the
manifolds
Testing of more number of
components has to be carried out
New route need not be figured out all
the way till the SPAR as we will be
flowing through established lines.
The flow rates might be limited due to
design constraints and pipe diameter
Safer compared than going through
hazard mass.

15. Option 2: Independent Flowline through
Hazard Mass

16. PROS & CONS
PROS CONS
No complications of induction into
existing system
Hazard mass is unexplored and hence
uncertainty is high
Independence from the other 2 wells Pipe protection/trenching costs in
hazard mass area are high
No constraint on flow rate 2x3=6 miles of new pipeline has to be
laid, this adds to cost tremendously
while we are still unsure of the
profitability of the 3rd well
1 riser is lost for expansion
New route has to be mapped and
explored in detail

17. Option 3: Independent Flowlines to Riser via
Existing Route

18. PROS & CONS
PROS CONS
No complications of induction into
existing system
2x3=6 miles of new pipeline has to be
laid, this adds to cost tremendously
while we are still unsure of the
profitability of the 3rd well
Independence from the other 2 wells 1 riser is lost for expansion
No constraint on flow rate New route has to be mapped and
explored in detail

19. Specifics Of Selected Option (Why and How)
• On comparing all the pros and cons of all the 3 options we have decided to go ahead with
the first option due to Pros outweighing the cons and less uncertainty in the option as we
have limited information about the geomorphology.
• We are using two flowlines going from the 3rd well to the existing 2 manifolds (PLEMs) to
ensure pigability of the flowlines which go to the 3rd well.
• At the 3rd well drill center we need 2 PLEMs or one PLEM and one PLET depending on the
cost difference between a PLEM & PLET.
• We can use the tree which we have in storage as per the design scenario background, as
the 3rd well is assumed to be similar to the previous 2.
• The 2 flowline design makes pigging possible for the flowlines.
• Pigging could have also been accomplished with a single flowline and a subsea pig
launcher but that increases the cost and complexity of the system.
• Also if the well turns out dry or produces less than predicted then a complex and costly
system will be a investment in futility.
• The most important consideration in selecting this design was the flexibility it offered in
terms of expandability while keeping the costs to a minimum.
• Another important advantage this design offers over the other 2 is that if the well turns out
to have excess production we can always reroute/reuse the existing pipelines to 2nd or 3rd
option but the vice versa is not feasible.
• NOTE: The design could be started with a single flowline to first ensure a feasible
production from the well and once that is established we could expand to the second
flowline as shown. We are going to present and examine the entire setup for the purpose of
this project.

20. Seafloor Layout

21. Drill Center Plan
Jumper
Flying Leads

22. Temperature Drop Simulation in Flowlines
• The simulation was carried out based on net heat content of natural gas
based on the formula:
• 𝑄𝑛𝑒𝑡 = 𝜌𝐶𝑣𝜋𝑅 𝑖𝑛 2 𝐿𝑇(𝐾)
• Cv for natural gas is 1.85 kJ/KgK
• The loss in heat per meter was calculated based on the following formula:
• 𝑄 =
2𝜋𝑘𝐿∆𝑇
ln
𝑅𝑜𝑢𝑡
𝑅𝑖𝑛
• The value of K was calculated by applying the above equations to flowlines
of well 1 and 2 and was found to be 0.0295 which is close to the insulation
constant of polyurethane(0.0245). The variation can be attributed to the
steel inner lining, or concrete coating.
• Now equation 2 was used along with the value for K to calculate the heat
loss per meter for products from well 3.
• For ever meter of heat loss we use equation 1 to calculate temperature and
then repeat previous step. Result graph published on the next slide.

23. Simulation Result via MS Excel
0
10
20
30
40
50
60
70
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
TemperatureinDegreeCelcius
Length of Flowline in Meters
Drop In Temp As Per Simulation
Final Predicted Temperature at SPAR for well #3: 23.51 Deg Celsius= 74.31F

24. The 3rd well is predicted to have lean gas. Based on the predicted value of temperature via
simulation and the graph above we can say that solely based on temperature and pressure
conditions hydrate formation is inhibited.
Note: This does not mean hydrates will not form under any conditions, inclusion of water or
change is gas composition might still lead to hydrates, MeOH and MEG injection systems
are to be installed on the 3rd well also for this reason.

25. P & ID: Manifold Connections Only

26. P & ID: 3rd Tree
Integrated with
manifolds

27. Manifold Configuration with 2 PLEMs at 3rd
Well

28. Preliminary Equipment List
S/N TYPE Q'ty
1 PLEM 1
2 PLET 3
3 SUTA 1
4 Umbilical 1
5 Electrical/Hydraulic Flying Leads 5
6 5" Hard Pipe Jumper 4
7 TREE 1
S/N Type Q’ty
1 PLEM 1 or 2
Manual Valves 3
Actuated Gate Valve 1
Transmitter 1
2 PLET 3
Manual Valve 1
3 SUTA 1
4 JUMPER 2
5 Tree 1
Valves 17
Actuated Valves 12
Manual Valves 3
Poppet Gate Valve 2
Transmitter 1

29. Block diagram of control system
Process Control
System
Master Control
Station
Electrical Power Chemical injection UnitHydraulic Power Unit
TUTU
PLEM #1
SUTA
PLEM #2
PLET #1
PLET #2
TREE (WELL #1)
TREE (WELL #2)
PLEM #3
SUTA
PLET #3
TREE (WELL #3)
Note: This block diagram is only specific and
limited to control systems (umbilical etc.) and
does not show flowlines etc.

30. Generic Operations & Controls Procedures
• Normal Operations
• Normal Shutdown/Planned Shutdown
• Hydraulic Shutdown/Emergency Shutdown
• Modes Of Operation (Start-up, Testing)
• Pigging
• Installation methods and requirements

31. Normal Operation
• In normal operation, the control system will provide several key information
for the operation and the production such as:
• Temperature/Pressure the flow rate
• Allow the subsea valve and choke to be operated
• Any specified status changes and alarms will display
• As soon as operation condition are outside pre-defined LoLo or HiHi
conditions or for any shutdown or safety event, action are required.
• Here are some of causes of shutdown:
• LoLo or HiHi pressures and temperatures in various part of the system eg
trees flowlines control fluid
• Loss of power or communications to MCS, drilling center or SCM
• Shutdown of process or injection equipment topside on installation
• Shutdown signal received by radio signal from MODU working at a drill
center
• We have to use the cause and effects chart to manage shutdown events. It
will specify how system reacts to specific events as shown ahead.

33. Normal Shutdown
• Definition: A normal shutdown is to shut-in the
tree by closing all or most of the valves on
the tree
A typical procedure is:
• Close the production insulation valve to
protect the USVs
• Close all the CIV and annulus Valves
• Close the choke (15% normally)
• Close the primary USV and lastly the SCSSV

34. • Planned Shutdowns
• We can plan that for well testing,
maintenance/repairs on tree or
long term subsea system
downtime.
• For short term well shutdown:
• While well still flowing, we inject
hydrate inhibitor at the tree until
whole jumper or flowline contain
protected fluid.
• Then we control the shutdown of
the well using choke. We close
then the FIV, PWV PMV and
SCSSV.
• If the period has to be greater
the process remains the same
but we have to inject Hydrate
inhibitor treatment at the tree
and the tubing.

35. Emergency Shutdown
• A hydraulic shutdown are used if there is a loss of
communication with the SCMs or there is a need
to depower the subsea system completely
• First, by activating the blow down valve (BDV) at
the HPU headers, all hydraulic pressure from the
SCM and umbilical will be released from the BDVs
and vented to the HPU return tank.
• Therefore, the Low pressure line will be vented
first to close all other subsea prior the SCSSVs.

36. Unplanned well shutdown
• It can be caused by:
• Failure of subsea equipment (Hydraulic leak, Electrical failure…)
• Pressure or temperature alarms
• Failure of subsea controls equipment
• As it is unplanned, we need to pay attention at the time line designed to release hydrate
mitigation in good time.
• Here is the time line:
• ‘No Touch time’: It is the time period immediately following a shutdown when no hydrate
mitigation is necessary.
• During this time the main focus is to get the plant re-started. But some preparation must be
done to ensure ‘light touch'
• Light Touch time: The time period between end of no tough time and start of displacement.
• During this period MeOH is injected into dead leg areas such as trees, well tubing and tree
jumpers. The time period needs to be sufficient so that all volumes are treated before
‘displacement’ has to start.
• So we will have a small volume for a shutdown less than 1 week. And we will inject below
SCSSV if it is superior to 1 week.
• Displacement: Time when live crude in the flowlines is displaced. Displacement must be
completed prior to the end of Cooldown time

37. Modes of Operation
• Well start-up
• During starting up a well, we need to pay
attention if the well and the flown are warm
or cold. The process is the same but it will
more or less time to warm up and
therefore more or less MeOH.
• We open PWV, PMV and SCSSV and
equalize differential pressure using MeOH
through Meg injection.
• We equalize and open the PIV and the
manifold header valves. We control the
flow using the choke.
• We have to check the sand detector and
the PT2 to ovoid the hydrate formation.
• During starting up a well we are injecting
Hydrate prevention chemical (MeOH)
continuously until arrival temperature
reaches pre-determined level.
• To test of flowline for our case, the single
well will flow into a test flowline usually its
own. The test flowline is directed to a test
separator. It should reflect actual normal
flow operation conditions.

38. Steps to Pig the 3rd well (Pigging)
1. Out of the two flowlines coming from well#3 one has to be
closed by shutting the respective PLEM/PLET.
2. Out of the 2 flowlines from well 1&2 one has to be shut.
3. Then a pig can be launched down one of the flowlines going
to the SPAR.
4. By keeping the jumper between well 1 & 2 closed we direct
the pig towards well 3.
5. Once the pig reaches well 3, we open the jumper between
the two PLEMs at well 3.
6. The pig flows into the actual production line and flows back
to the SPAR.
7. Note: Refer P & ID for better understanding.
Installation methods and requirements are to be directly referred
from API RP 17 and can not be changed for specific fields.

39. Top 3 Risks & Uncertainties
• List of top 3 areas of Uncertainties or concerns and intended plan to cope with them:
1. Not Enough Downhole Pressure: Although the well is assumed to be similar to the 2
others and designed accordingly. The downhole pressure during production might very
well turn out to be lower than anticipated for the flow to occur all the way to the SPAR
due to the addition of one mile of flowline length. The way to deal with this uncertainty
would be to have the extension of the umbilical designed for the inclusion of a gas
injector. Also it has to be ensured that the tree being used is capable of gas injection.
Also statistically, a gas injection system would boost the productivity of the well by 20%.
2. If the well is producing at a rate higher than what the planned tie back configuration is
capable of handling. In this case an alternative concept design has to be ready to be
implemented (option 3&2 etc.) for a direct tie back into the risers. Also the use of 2
PLEMs instead of PLEM and PLET near the 3rd well ensures the field expandability in the
future if needed.
3. The composition of products is far from anticipated. This would be a very serious concern
since it would throw all our insulation and hydrate mitigation calculations off the mark.
The first option would be to increase the MEG or MeOH injection if necessary,
adjustments for the same need to be incorporated into the design. If the inhibition is still
not effective a new pipeline with better insulation or PIP etc. might have to be applied at a
huge cost to the operator/Owner.

40. References
• Fundamentals of Subsea engineering notes &
Videos (TAMU)
• Prof. Dave Lucas (TAMU)
• www.Engineeringtoolbox.com
• Dr. M. Bramhi (Simon Frazier University)
• API
• PetroWiki
Thankyou!
Please mail any questions to:
ashwin.amrina@tamu.edu
thomasdelcourt@tamu.edu
byungjinzzz@tamu.edu