Dilution-Based Dual Gradient Well Control Presented at the 2011 IADC Dual Gradient Workshop, 5 May 2011 by Paul Boudreau, Dual Gradient Systems LLC
In this very short presentation, we will Review Dilution-based Dual Gradient (DBDG) well design, wellbore configuration, and well control equipment. Look at DBDG in conjunction with an MPD system; i.e., Transocean s Continuous Annular Pressure Management (CAPM) system. (Any feature which does not apply to DBDG in absence of MPD will be highlighted.) Compare CAPM/DBDG and conventional single gradient well control. Have a quick look at the various well control options which may be employed within CAPM/DBDG. 2
DBDG vs. Single Gradient Well Design Single Gradient DBDG Well Design Considerations Not all casing seats determined solely by PP/FG/MW inter-relationship. Isolation of stray hydrocarbon zones. Maintaining adequate kick tolerance. Maintaining multiple barriers between reservoir and the world. Contingency planning. Completions design. 3
CAPM (Continuous Annular Pressure Management) DBDG System 4
CAPM/DBDG Circulating System DRILLSTRING PDP PDIL CONVENTIONAL FLOWLINE PRCD ROTATING CONTROL DEVICE SHALE SHAKERS INNER RISER DRILLING CHOKE MANIFOLD CORIOLIS FLOWMETER DEGASSER MARINE RISER PCHOKE PRISER BOOSTER LINE CENTRIFUGES CHOKE LINE KILL LINE MUD PITS MUD PITS MUD PITS PBOP SUBSEA BOP MUD PUMPS DILUTION MUD = LIGHT WEIGHT DISCHARGE FLOW STOP VALVE PPWD DOWNHOLE MUD = HEAVY WEIGHT DISCHARGE DILUTED MUD = RISER MIX MUD = FEED MUD 5
Dual Gradient Drilling FSV U-Tube Arrested with Pumps Off Upstream - Drillstring with Downhole Mud Downstream - BHA and Drill Bit U-tube Pressure Resisted by Spring Forces 6
Dual Gradient Drilling FSV Bringing on Pumps Through Choke Pump Pressure + U-Tube Overcome Spring Force Flow is Restricted to Provide Main Piston Opening Pressure 7
Dual Gradient Drilling FSV Main Valve Opened for Normal Drilling Choke is Bypassed once Main Valve Opens 8
Dual Gradient Drilling FSV Valve Closes Once Pumps Off Upstream - Drillstring with Downhole Mud Downstream - BHA and Drill Bit 9
Conventional vs CAPM/DBDG Well Control Conventional Single Gradient Theory and Practice Conventional CAPM / DBDG Unconventional and new to industry Special Equipment None Flow Stop Valve required Kick Detection Conventional, open system subject to heaveaffected returns Kick Volume Conventional, open system subject to heaveaffected returns Determination of Bottom Hole Pressure Direct using SIDPP Enhanced using Coreolis flowmeters and micro-influx detection on closed circulating system Smaller due to enhanced detection Drillstring normally overbalanced. BHP determined indirecly, by change in FSV crackopen pressure. (Direct after influx circulated above BOP pressure gauge) continued... 10
Conventional vs CAPM/DBDG Well Control...continued Conventional Single Gradient Well Control Conventional Operations Casing Shoe Higher Pressures Margin Between Lower Wellbore Pressure and Fracture Weight-up Strategy Weight up below BOP, then riser Time to Kill Well Conventional, may even use both choke and kill lines Redundancy in C&K Yes Lines CAPM / DBDG More complex in that dilution must be maintained, but also offers more flexibility Lower shoe pressures due to heavier MW between kicking formation and shoe Larger due to higher MW Can kill well by raising Downhole MW, Riser MW, or both. May be able to kill well without increasing Riser MW. Increased due to having to dilute choke line returns. May be reduced in some cases by beginning circ through drilling choke. No, must use one to inject dilution mud 11
Conventional vs CAPM/DBDG Well Control Kick Detection Bottomhole Pressure Determination Kill Method Options Conventional Single Gradient 1. Return flowrate 2. PWD 3. Pit gain (detection problematic in very large circulating systems) 4. (ROP) 5. (Hook load) 6. (Standpipe pressure) 1. SIDPP 2. Shut in BOP pressure* 3. SICP* 1. Wait-and-weight 2. Driller s method 3. Riser Kill 4. Bullheading CAPM / DBDG 1. Delta flow in/out (using Coriolis flow meter on mud return line) 2. Subsea BOP and Riser pressures (due to more downhole mud flow into riser) 3. PWD 4. (ROP) 5. (Hook load) 6. (Injection / boost line pressure) 7. (Pit gain) 1. Flow Stop Valve crack-opening pressure 2. Shut in BOP pressure (delta)* 3. SICP* * Especially once kick circulated above or out. 1. Driller s Method (no increase in MW for first circulation); through choke manifold and/or MPD drilling choke manifold 2. Wait-and-weight (increase Downhole MW) 3. Riser Kill (increase Riser MW) 4. Bullheading 12
CAPM/DBDG Well Control Flexibility In this example, a kick is taken at 16,000ft at the section TD. Because there remains a wide margin between the mud hydrostatic and the frac pressure at the previous shoe (at 11,000ft), either the riser mud weight or the downhole mud weight may be increased to kill the well. The riser mud weight in this case is programmed to increase for the next hole section. Note that the 12.85ppg pore pressure at TD exceeds the ~12.65ppg frac pressure at the shoe above (see dotted brown line); thus SG well control would not be possible with this casing design. 13
SG Well Control Kick Indicators 14
CAPM/DBDG Well Control Kick Indicators 15 15
CAPM/DBDG Well Control Options Method Advantages Disadvantages Wait-and- Weight (increasing Downhole MW) Driller s Method (no change to mud weights for first circulation) Riser Kill (increasing Riser or Choke Line MW by decreasing dilution ratio) 1. Lower annular pressures compared to Driller s Method (well-specific). 2. Lower shoe pressures than with Riser Kill method. 1. Circulation can begin immediately. 2. Barite not required to begin circulating. 3. Can calculate BHP down annulus once kick is above BOP stack. 1. Can kill formation quickly by displacing choke line and/or riser, even with kick still on bottom. 2. In certain situations; e.g., salt water kick, allows circulating up kick conventionally through open BOP. 3. No requirement to weight up mud on surface prior to commencing circulation. 1. Delay in circulation while building kill weight mud. 2. Complicates fluid management and calculations. 1. Requires additional circulation to kill well. 2. Higher surface pressures than W&W or Riser Kill. 3. Higher shoe pressures are possible. 4. Requires both C&K lines (one to inject dilution mud below closed BOP, one for well returns) when circulating out through the choke. 1. Requires use of both choke and kill lines to inject dilution mud below closed BOP when circulating out through the choke. 2. Relies on properly functioning FSV to maintain constant BHP. 3. Increases shoe pressure compared to W&W method. 16
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