Subsea Boosting John Friedemann
GE Oil & Gas Land Pipelines ipigs Offshore LNG Liquefied Natural Gas Compression Trains Refinery Subsea
A little History 969 OTC 94 97 SPE 463 985 OTC 7438 3
Topics Why? Field Example Pumps Compressors Multiphase Boosters Operational Issues Questions 4
Artificial Lift: A definition Simply put, artificial lift describes the application of technology to ensure production when the well or riser will not flow naturally www.lufkin.com (GE Oil and Gas) 5
The Boosting Decision Process 6
Operator Steps - Defining the Problem - Setting the goals 3- Building Models 4- Optimizing the Process 5- Verifying the solution 6- Field testing 7
Problem: Increasing Recovery Oil or Gas Rate Effect of Boosting / Separation But this has a cost: need to be sure 8
Building the model Based on net available data 9
FDCP Tubing Performance Graphical method to Describe Wells Built from: - Pressure drop from reservoir DP=Q/J J Production index (for example) - Tubing Pressure Drop DP=rgDz + /rfq L/D 3- Choke DP=rQ /C v Rate Note: using single phase flow for this example 0
FRBP Riser Performance Graphical method to Describe Wells Built from: - Tubing Pressure Drop DP=rgDz + /rfq L/D Riser Rate Note: using single phase flow for this example
FDCP/FRBP Operating Point is the Intersection Riser Rate
Pressure The Boosting Problem is Gap-Filling Simple Well Or Riser Supply Flow 3
Pressure In Well Compensation Simple Well Or Riser Effect in Well Flow Offshore version is a drilling rig 4
Booster Gas ESP Issues: Reliability Normal Operations Gaslift? Pros Simplicity Cons Reliability Maintenance 5
Pressure Solution 3: Compensate Simple Well Or Riser Effect in Well Supply Flow (GE Oil and Gas)
Pressure Or Curve Displacemnt: Gas Lift Simple Well Or Riser Effect in Well Supply Flow www.lufkin.com (GE Oil and Gas)
Depth Gas Lift Design: Simple Density Method Source Pressure Gas Gradient Mandrel Location Pressure Valve Opening Pressure 8
Flow Rate Gaslift Issues: Efficiency and Flow Optimum? Gas Lift GLR Pros Simplicity Maintenance Cons Efficiency Stability Fluids Related 9
Pressure Solution 4: Seabed Compensation Flowline NPV 70 99 Supply Flow (GE Oil and Gas) NP 99 KBS 00 0
Pressure, bar Reservoir Fluids 60 40 Oil 0 Bubble Point Gas Cap 0vol% Gas 00 99.99vol% Gas Dew Point 80 40vol% Gas 99.9vol% Gas 60 99vol% Gas 60vol% Gas Dew Point 40 Bubble Point 80vol% Gas 0 0-00 -00 0 00 00 300 400 500 Temperature, oc
Back to our field
Optimizing: Options - Local processing FPSO,. - Subsea to Beach Separation Singlephase boosting Multiphase Boosting Sevan Marine Rule: Concept independence ie, ignore benefit? 3
Export Solutions Melkøya ca. 90 km Sørøya ca. 70 km Snøhvit ca. 70 km Water Depth: 380 m 4
What options did they look at? Combinations. Boosting. Separation What are the issues with boosting? 5
Pump Technologies Centrifugal Low GVF High Boost Heli-Coaxial Broad GVF Range Moderate Boost Range Twin-Screw High Viscosity High Boost High GVF No Full Spectrum Solution 6
Verification & Risk: Tech. Readiness Levels TRL 0 Unproven Concept: Basic R&D, paper concept Basic scientific/engineering principles observed and reported; paper concept; no analysis or testing completed; no design history TRL Proven concept: Proof of Concept as a paper study or R&D experiments ( a ) Technology concept and/or application formulated ( b ) Concept and functionality proven by analysis or reference to features common with/to existing technology ( c ) No design history; essentially a paper study not involving physical models but may include R&D experimentation TRL Validated Concept: Experimental proof of concept using physical model tests Concept design or novel features of design is validated by a physical model, a system mock up or dummy and functionally tested in a laboratory environment; no design history; no environmental tests; materials testing and reliability testing is performed on key parts or components in a testing laboratory prior to prototype construction TRL 3 Prototype tested: System function, performance and reliability tested (a) Item prototype is built and put through (generic) functional and performance tests; reliability tests are performed including; reliability growth tests, accelerated life tests and robust design development test program in relevant laboratory testing environments; tests are carried out without integration into a broader system (b) The extent to which application requirements are met are assessed and potential benefits and risks are demonstrated TRL 4 Environment Tested: Pre production system environment tested Meets all requirements of TRL 3; designed and built as production unit (or full scale prototype) and put through its qualification program in simulated environment (e.g., hyperbaric chamber to simulate pressure) or actual intended environment (e.g., subsea environment) but not installed or operating; reliability testing limited to demonstrating that prototype function and performance criteria can be met in the intended operating condition and external environment.trl 5 System Tested. Production system interface tested Meets all the requirements of TRL 4; designed and built as production unit (or full scale prototype) and integrated into intended operating system with full interface and functional test but outside the intended field environment TRL 6 System Installed: Production System Installed and tested Meets all the requirements of TRL 5; production unit (or full scale prototype) built and integrated into the intended operating system; full interface and function test program performed in the intended (or closely simulated) environment and operated for less than 3 years; at TRL 6 new technology equipment might require additional support for the first to 8 months TRL 7 Field Proven: Production System Field Proven Production unit integrated into intended operating system, installed and operating for more than three years with acceptable reliability, demonstrating low risk of early life failures in the field 7
Testing: Need to verify everything Dry vs Wet 8
Pressure Basics of Pump Design Assumptions Incompressible liquid No gas Liquid not near vapor pressure Pump path Temperature 9
Total Discharge Head and NPSH Total Discharge Head TDH = h d -h s Net Positive Suction Head Available P v = vapor pressure of fluid at inlet NPSHA P inlet r P v h v Pump Power Delivered Required Power Q * TDH * r * g DP * Q DP * Q Required Power Efficiency 30
Definitions Note difference in suction elevation Head [=] m or ft 3
Head Pump head V [=] m/s G=9.8 m/s D [=] m n=rotational frequency Velocity head= h v Q [=] m 3 /s Head Head v tangential g v g flow D n pipe g D g 4Q impeller Pressure head P [=] Pa Ρ [=] kg/m 3 Head P r g 3
Head Total Dynamic Discharge head, h s Static Discharge Head+Velocity head+outlet friction head Head at pump outlet during operation Friction head = h f f = friction factor Head vflow f g L D pipe Total Dynamic Suction Head, h d Static Suction Head+Velocity head-inlet friction head Head at pump inlet during operation 33
Effect of Changing Speed 34
Multistage vs Single Stage 35
Pumps as they are really installed 36
Affinity Laws: Used to evaluate sizing Impeller diameter D held constant: pump speed Rate Head Power With speed N held constant: Diameter Rate Head Power N N Q Q N Q N N H H N H 3 3 N N P P N P D D Q Q D Q D D H H D H 3 3 D D P P D P
Affinity Laws: Used to evaluate sizing Impeller diameter D held constant: pump speed Rate Head Power With speed N held constant: Diameter Rate Head Power N N Q Q N Q N N H H N H 3 3 N N P P N P D D Q Q D Q D D H H D H 3 3 D D P P D P
Pump Curves 39
Pump Cavitation Handled by inlet pipe line sizing rule: API RP 4E v max fps = 50 ρ,( lb m ft 3 ) (carbon steel) 40