Subsea Presentation

SUBSEA WELL CONTROL

SUBSEA STACK DIFFERENCES Choke and kill line connected directly to stackChoke and Kill lines are Manifolded so that either can be used for circulation and returns during a kill operationUse of blind/shear rams are used in place of ordinary blind ramsRams are equipped with integral or remotely operated locking systems

SUBSEA BOP ARRANGEMENT

SUBSEA STACK AND CHOKE MANIFOLD ARRANGEMENT

Subsea BOP Controls

SUBSEA CONTROL SYSTEM

SUBSEA CONTROL SYSTEMTYPICAL HYDRAULICHOSE BUNDLE1. 1 I.D. Supply Hose

2. 3/16 I.D. Pilot Hose

3. Outer Protective Jacket

Shuttle ValveThe shuttle valves isolate the control fluid system between the selected pod and the redundant pod.

The power fluid from the selected pod will shift the shuttle valve.Power Fluid to Bops FunctionsPower Fluid port isolated from Blue PodPower Fluid from Yellow Pod

Closing Sequences- Close BOP,s from remote panel.- Activate solenoid valve.- Shift 3 position 4 way valve.- Send pilot signal to the close SPM valve on both pod with 3000 psi.- Close SPM valve shift on the selected blue pod.- Power fluid from Subsea bottles is able to flow and close function on BOP.- The fluid from opening chamber is vented to the sea through the open SPM valve.- Accumulator pumps pressure up all accumulator and BOPs bottles to 3000 psi.

Opening Sequences- Open BOP,s from remote panel.- Activate solenoid valve.- Shift 3 position 4 way valve.- Send pilot signal to the open SPM valve on both pod with 3000 psi.- Open SPM valve shift on selected blue pod.- Power fluid from Subsea bottles is able to flow and open function on BOP.- The fluid from closing chamber is vented to the sea through the close SPM valve.- Accumulator pumps pressure up all accumulator and BOPs bottles to 3000 psi.

Block Sequences- Block BOP,s from remote panel.- Activate solenoid valves.- Shift 3 position 4 way valve in block.- Release pressure on pilot lines, pilot fluid is vented back to the reservoir. - SPM valve on selected blue pod shift to close position.- Allowing the pressure from BOPs function to be released, the power fluid is vented to the sea through the SPM valve.

Changing Pod Sequences- Select yellow pod from remote panel.- Activate solenoid valve.- Shift 3 position 4 way valve on yellow pod.- Close BOP,s from remote panel.- Activate solenoid valve.- Shift 3 position 4 way valve.- Send pilot signal to the close SPM valve on both pod with 3000 psi.- Close SPM valve on selected yellow pod shift.- The power fluid from Subsea bottles can flow and the shuttle valve can shift allowing the power fluid to pressure up the close function on BOP.- Accumulator pumps pressure up all accumulator and BOPs bottles to 3000 psi.

Subsea Animation

The subsea accumulator bottles capacity calculations should compensate the hydrostatic pressure gradient at the rate of .445 psi/ft of water depth.

Subsea Accumulator Bottles

Precharge pressure with water depth

Response time between activation and complete operation of a function is based on BOP closure and seal off.BOP Response TimeRemote valves should not exceed the minimum observed ram BOP18 3/4

30 sec.SUBSEASURFACE18 3/4

45 sec.30 sec.60 sec.45 sec.Time to unlatch the lower marine riser package should not exceed 45 seconds

Hydril GL Secondary Chamber OPENING PRESSURE Requires lowest hydraulic closing pressureThis allows to balance the opening force on the piston created by the drilling fluid H. P. in the marine riser

Vetco H-4 Connector0 to 2o Drilling

2o to 4o Stand by & Prepare to disconnect

4o to 6o Disconnection

- Choke Line Friction

Choke Line Friction Losses: There are four recognized methods of recording choke line friction losses at slow circulating rates of 1- 5 bbls / min If SICP is held constant until kill rate is achieved, BHP will be increased by an amount equal to CLFL.To accomplish constant BHP, a method must be used while bringing the mud pump to kill rateChoke Line Friction Losses

500First MethodRECORD THE PRESSURE REQUIRED TO CIRCULATE THE WELL THROUGH THE MARINE RISER WITH THE BOP OPEN500 PSI IN THIS CASE

700RECORD THE PRESSURE REQUIRED TO CIRCULATE THROUGH A FULL OPEN CHOKE:700 PSI IN THIS CASECHOKE LINE FRICTION LOSSES = 700 - 500 = 200 PSIFirst Method

200Second MethodCIRCULATE THE WELL THROUGH A FULL OPEN CHOKE WITH THE BOP CLOSED AND RECORDING THE PRESSURE ON THE (STATIC) KILL LINE. THE KILL LINE PRESSURE WILL REFLECT THE CHOKE LINE PRESSURE LOSS.200 PSI IN THIS CASE

200Third MethodCIRCULATE DOWN THE CHOKE LINE AND UP THE MARINE RISER WITH THE BOP OPEN.THE PRESSURE REQUIRED FOR CIRCULATION IS A DIRECT REFLECTION OF THE CHOKE LINE FRICTION LOSS.200 PSI IN THIS CASE

Fourth MethodCIRCULATE DOWN THE KILL LINE TAKING RETURNS THROUGH A FULL OPEN CHOKE WITH THE WELL BORE AND RISER ISOLATED BY CLOSING THE BOPs.PRESSURE OBSERVED IS DOUBLE THE CLFL:IN THIS CASE 400 PSI / 2CLFL = 200 PSI400

If CLFL is not accounted for, casing pressure varies from SICP at pump start up to SICP + CLFL with the pump at kill rate.This results in BHP increasing by an amount equal to CLFL.5007007001200BHP : 5000 psi200Increase to 5200 psiBringing Pump to Kill Rate Speed

Reduced Choke Pressure = SICP - CLFL = 700 - 200 = 500 psiCreate a chart where CLFL and pump rates are divided by 3:

5007005001000BHP : 5000 psi200Bringing Pump to Kill Rate Speed: First Method

700keeping the Kill Line gauge constant while bringing the pump up to speed eliminates the effect of CLFL.No pre calculated CLFL information is required.It would be advisable to rig a remote kill pressure gauge which could be seen by the choke operator. Bringing Pump to Kill Rate Speed: Second Method

Riser Loss/Riser MarginRiser CollapseOverburden Pressure

Riser Loss/Riser marginIn case of a riser loss (emergency drive off, anchor chain breaks, ship drift), there will be a reduction in hydrostatic pressure.

This drop in hydrostatic pressure on the well bore: is equal to the hydrostatic differential between fluid in the riser and sea waterThe hydrostatic from the air gap is lostRiser Loss

Example:Calculate the reduction in BHP is the riser is torn off:1- hydrostatic from air gap is lost:65 x 12.9 x . 052 = 43.6 psi2- hydrostatic differential in riser:2,150 x (12.9 - 8.6) x .052 = 480.7 psi3- reduction in BHP:43.6 + 480.7 = 524.3 psi

2,1504,450652,950MW: 12.9 ppgSW: 8.6 ppg Riser Loss/Riser Margin

Example: To calculate the riser margin:Riser margin=HP reduction/ (TVD-Riser length)X0.052524.3/(7400-2215)x0.052 = 1.94 ppgMW plus riser margin 12.9ppg+1.94ppg =14.84

2,1504,450652,950MW: 12.9 ppgSW: 8.6 ppg Riser Loss/Riser Margin

In deep water, the potential for riser collapse exists if the level of drilling fluid in the riser drops due to gas unloading the riser or in case of heavy losses.Riser collapse

Assuming the worst case to be during an emergency or accidental line disconnection, the pressure at the bottom of the riser would equal the seawater hydrostatic.The fluid level in the riser would fall until the equilibrium is reached.Riser collapse

Example:If a riser has a collapse pressure of 500 psi, how far could the mud level fall before sea water collapses the riser?500 / .445 = 11231123 + 60 = 1183 feetA riser fill up valve should be used if the collapse pressure could exceed the collapse pressure rating of the riser.

SW: .445 psi/ft2,150 60Riser collapse (vacuum inside )

Example:If a riser has a collapse pressure of 500 psi,and is filled with 0.1psi/ft of gas how far could the mud level fall before sea water collapses the riser?SW: .445 psi/ft2,150 60Riser collapse (gas inside riser ) Riser collapse =water depth x SW gradient-(Airgap+water depth)x riser fluid gradient500=yx0.445-(60+y)x0.1500=0.445y-(6+0.1y)500=0.445y-6-0.1y506=0.345yY=1466ftLevel drop to collapse point=1466+60=1526ft

Example:If a riser has a collapse pressure of 500 psi,and is filled with 0.1psi/ft of gas how far could the mud level fall before sea water collapses the riser?SW: .445 psi/ft2,150 60Riser collapse (gas inside riser ) Level drop from sea level before riser collapsesCollapse press + Air gap x Riser fluid grad SW gradient Riser fluid Gradient

=1466 ftAdd Airgap 60 ft ?= 1466 +60= 1526

Overburden Pressure is the pressure exerted at any given depth by the weight of the sediments, or rocks, and the weight of the fluids that fill pore spaces in the rock.Generally considered to be 1 psi / ft on land while offshore part of this overburden is replaced by about .65 psi/ft.Overburden Pressure

Example:Calculate the MAMW:1- calculate formation depth:600 - 220 - 80 = 300 ft2- calculate overburden pressure:300 x .65 = 195 psi3- calculate SW pressure:220 x .455 = 100 psi4- calculate the pressure at shoe:195 + 100 = 295 psi5- convert this pressure to a MW:295 / ( 600x .052) = 9.4 ppg80220600SW: .455 psi/ftOverburden: .65 psi/ftMaximum press at the shoe

Dynamic MAASPDynamic MAASP is the MAASP while killing a well on a subsea stack

Dynamic MAASP =Static MAASP -CLF

Stop rotation Pick up the drill string to hang off position Stop the pump Flow check If the well flows Close BOP Open remote control choke line valves (Fail safe valves) Notify Tool Pusher and OIM Record time, SIDPP, SICP and pit gain Check Space out Hang off and lock pipe ramsShut- in Procedure: HARD SHUT-IN

Pick up the drill string to hang off position Stop rotation Stop the pump Flow check If the well flows Open remote control choke line valves (Fail safe valves) Close BOP Close choke Notify Tool Pusher and OIM Record time, SIDPP, SICP and pit gain Check Space out Hang off and lock pipe ramsShut- in Procedure: SOFT SHUT-IN

Subsea kill sheet (differences with surface)

Inclusion of choke line friction calculations Casing set depth vs length of casing in the holeInclusion of Riser displacement volumesDynamic Casing Pressure

Removing trapped gas from the BOP

Removing trapped gas from the BOP It is quite likely that some gas will have accumulated under the closed BOP during displacement of the influx.The gas must be removed from the stack before the BOP is opened.The volume of the trapped gas depends on the volume between the preventer in use and the choke line outlet in use.

Removing trapped gas from the BOPStep # 1:- Isolate the well with the lower rams.- Displace the kill line with kill weight mud taking returns up the choke line.- Continue to circulate until the kill and choke line are full of uncontaminated kill weight mud.

Removing trapped gas from the BOPStep # 2:- Displace choke line to water or base oil to BOP stack taking returns up the kill line.- Do not over displace.- Close the fail safe valves on the kill line.

Removing trapped gas from the BOPStep # 3:- Vent the choke line to the MGS.This will unload the water or the base oil and depressurized gas.

Removing trapped gas from the BOPStep # 4:- Open the annular preventer and allow the mud to U-tube from the riser into the choke line.- Continuously fill the riser with mud.

Removing trapped gas from the BOPStep # 5:- Close the annular preventer and displace the choke line with kill weight mud through the kill line.

Removing trapped gas from the BOPStep # 6:- Close the Diverter and line up the flow return to the MGS (if possible).- Open the annular and pump down into the choke line or use the booster line (if available) to displace the riser to kill weight mud.

Removing trapped gas from the BOPStep # 7:- Close the annular preventer- Open the pipe rams and monitor the well for flow.- If the well is dead, open the annular.- Circulate and condition the mud.

CALCULATING TRAPPED GAS VOLUME AT SURFACE EXAMPLE4 bbls trapped below stack Riser/choke line length is 1000ftMw in riser 12 ppgKill mud weight is 14 ppgAtmospheric pressure is 14.6psiWhat is the volume of the gas at surface?

Using Boyles law P1V1=P2V2= ((14 x0.052x1000)+14.6)x4)/14.6=203.45 bbls

HydratesHydrates

What are hydrates?

Hydrates are a solid mixture of water and natural gas (commonly methane). Once formed, hydrates are similar to dirty ice .Hydrates

Why are they important?

Hydrates can cause severe problems by forming a plug in Well Control equipment, and may completely blocking flow path. One cubic foot of hydrate can contain as much as 170 cubic feet of gas. Hydrates could also form on the outside of the BOP stack in deepwater.

Hydrates

Where do they form?

In deepwater Drilling High Wellhead Pressure Low Wellhead temperature

Hydrates

How to prevent hydrates? Good primary well control = no gas in well bore Composition of Drilling Fluid by using OBM or Chloride (Salt) in WBM. Well bore temperature as high as possible Select proper Mud Weight to minimize wellhead pressure. injecting methanol or glycol at a rate of 0.5 - 1 gal per minutes on the upstream side of a chokeHydrates

Hydrates

Riserless Surface Hole DrillingInvolves drilling directly on the seabed without a riser Returns are deposited on the sea bed and are not allowed to get to the rig floor Gives the rig flexibility in the event of abandonment

Floating rig mud monitoringRig HeavePitch and RollCrane Operations

________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Hydraulic Hose Bundle

The hose are constructed with a polyester core tube, reinforced with aramid fibers or polyester fibers, and are sheathed in a smooth, salt water resistant polyurethane cover.

Hoses for either hydraulic or electrohydraulic service are available and meet the exacting specifications for subsea service.SPM and Shuttle ValvesAll SPM and regulating functions are piped and manifolded in a control pod with a tapered male round seal surface on the bottom. The male is mechanically indexed and compressed into a lower spring mounted female that is bolted to the main portion of the stack. Koomey packer seals are used on all tapered surfaces to maintain high-pressure flow integrity. Functions located above the riser connector exit through radial port outlets on the mounting flange of the upper female of each pod and to individual shuttle valves that isolate and separate yellow and blue pods. Flow exits at the bottom of the lower female for all functions below riser connector on the stack and goes directly to the shuttle valve. Access for some straight through functions, supplied only from the surface manifold unit, is provided for each pod. Either pod can be retrieved without disrupting drilling operations should it be necessary.Shuttle valves are usually mounted directly on function ports or pilot operated check valves. As previously mentioned, the shuttle valves isolate one pod from the other so both are independent from one another.

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Subsea Presentation