Successfully reported this slideshow.
We use your LinkedIn profile and activity data to personalize ads and to show you more relevant ads. You can change your ad preferences anytime.

Subsea689_FinalSubmission_Ashwin_Kim_Thomas

1,371 views

Published on

  • Did You Get Dumped? Do you still want her back? If you act now, I can help you. ➤➤ http://t.cn/R50e2MX
       Reply 
    Are you sure you want to  Yes  No
    Your message goes here

Subsea689_FinalSubmission_Ashwin_Kim_Thomas

  1. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 13. Option1: Tie Back to Existing Wells Green: Umbilical; Red: Flowlines
  14. 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. 15. Option 2: Independent Flowline through Hazard Mass
  16. 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. 17. Option 3: Independent Flowlines to Riser via Existing Route
  18. 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. 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. 20. Seafloor Layout
  21. 21. Drill Center Plan Jumper Flying Leads
  22. 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. 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. 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. 25. P & ID: Manifold Connections Only
  26. 26. P & ID: 3rd Tree Integrated with manifolds
  27. 27. Manifold Configuration with 2 PLEMs at 3rd Well
  28. 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. 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. 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. 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.
  32. 32. 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
  33. 33. • 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.
  34. 34. 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.
  35. 35. 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
  36. 36. 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.
  37. 37. 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.
  38. 38. 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.
  39. 39. 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

×