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CROSCO CASE STUDY

SUBSEA WELL CONTROL EQUIPMENT ADJUSTMENT TO COMPLY WITH

HPHT CONDITIONS

THE FIRST CENTRAL AND EASTERN EUROPEAN INTERNATIONAL OIL AND GAS CONFERENCE AND

EXHIBITION

September 14-16 2011, HUNGARY, Siófok

HPHT STANDARDS FOR SUBSEA WELL CONTROL EQUIPMENT

New challenges which are facing operators and contractors when we are talking about drilling of HPHT wells brought minimal conditions which need to be fulfilled prior to start of drilling operations. Well Control Equipment needs to comply to new HPHT standards for all HPHT wells.

HP wells are deep high pressure wells deeper than 4000 meters and a bottom hole pressure greater or equal to 10000 psi.

HT wells are wells that have temperatures above 180⁰ C.

The following procedure was developed to adjust the subsea well control equipment for an upcoming client on HPHT well.

PROCEDURE-RAM TYPE PREVENTERS

Ram type preventers For high temperature subsea stacks (ram type preventers) the

only elastomer that requires changing for the high temperature variety are the ram packers and top seals.


Beside requirements for replacement of rubber goods/elastomers in well control equipment to comply with HPHT conditions there is other equipment requirement /procedures that has to be followed. Those requirements are related to following and are shown as check lists.


Ram type preventers HPHT conditions check list

ITEM DESCRIPTION YES/

NO

1 Is BOP rated to 15M

2 BOP should have at least 4 ram preventers.

3 The shear ram should have sufficient power to cut the strongest

grade drill pipe which is used, with 10M wellbore pressure

4 Check the certification of the BOP

5 Are the front packers installed in the ram blocks HT

6 The BOP should be H2S trim

7 Are the top seals installed in the ram blocks HT

8 The BOP should be tested to 250 psi for 5 minutes and 15,000 psi

for 15 minutes

9 Test the rams locking system with full working pressure and full

bore pressure

10

Only stainless steel or cadmium plated gaskets are allowed to be

used for the LMRP, wellhead and kill and choke hydraulic

connectors. Hycar ring gaskets must be replaced

11 The BOP stack must have dual purpose kill and choke lines

PROCEDURE-ANNULAR PREVENTERS

Annular preventers

In case of expected HT conditions standard packer and donut in

annulars has to be replaced with CAMULAR severe service elastomers for temperatures greater than 121ºC( 250ºF).

PROCEDURE-ANNULAR PREVENTERS

Annular Preventers HPHT conditions check list


NO

1 Is a 10M annular available

2 Are two 10M annular preventers available

3 What type of element is installed in the annular preventer (Natural

rubber has the highest temperature resistance, but does not perform

adequate when oil-base mud is used)

4 Is a HT element and donut installed in the CIW type D annular

preventer

PROCEDURE-BOP GATE VALVES

Bop gate valves

Standard seals can be used in HT conditions on subsea application.

BOP gate valves HPHT conditions check list


NO

1 Are HT seals installed on the kill and choke stabs

2 Are the gate valves on the (Subsea) BOP only fail-safe assist close,

or are the close sides connected with the hydraulic system

3 Ensure two choke lines and two kill lines are installed on the BOP

4 The outlets of the BOP should have a minimum of 3-1/16" bore

5 Ensure two choke lines and two kill lines are installed on the BOP

6 Sequenced closing of subsea fail-safe valves (outer valves close

first) to limit the effect of cutting out the gates

PROCEDURE-RISER KILL AND CHOKE LINES

Riser Kill and Choke Lines

All riser kill and choke seals have to be replaced with high temperature seals. Same is applicable for seals in kill/choke/booster goosenecks.

PROCEDURE-COFLEXIP HOSES AND ITS LIMITS

Coflexip hoses on LMRP (lower marine riser

package) and surface coflexip hoses

The inner lining of these flexible lines is made from COFLON (fluorinated thermoplastic)

Continuous service

High temperature rated flexible pipes are designed for -20°C to +130°C (-4°F to +266°F) continuous service, with no time limit (within the lifetime of the whole line).

Survival conditions

All Coflexip flexible lines are designed to resist to +160°C (+320°F) maximum inner temperature of the contained fluid for duration in excess of one hour.

PROCEDURE-COFLEXIP HOSES

Coflexip hoses on LMRP (lower marine riser

package) and surface coflexip hoses

PROCEDURE-CHOKE AND KILL MANIFOLD

Choke and kill manifold To comply with HT requirements all choke manifold valves have to

be fitted with high temperature seals on positions 11 (stem packing), 21 (assembly OD face seal) , 22 (assembly ID face seal). Beside it is good practice to install temperature sensors. Temperature sensors must be fitted on the choke line and upstream the chokes with readout in drillers cabin with alarm settings.


Choke and kill manifold


Choke and kill manifold HPHT conditions check list

ITEM DESCRIPTION YES/NO

1 Have the Coflexip hoses on the BOP and the moon pool been pressure tested and was the bore internally

inspected lately? (Yearly testing and inspections are required at a qualified machine shop)

2 Are the Coflexip hoses in use of HT grade and have they "Coflon" lining installed?

3 Are the stem packers of the kill and choke man. fitted with HT seals?

4 There should be at least two adjustable chokes and one manual operated choke installed

5 Are the valves upstream the chokes on the manifold all 15M?

6

.

What is the pressure rating of the valves down stream the chokes? (Minimum 5000 psi, preferred

10000 psi)

7 What is the size of the buffer tank overboard line?- minimum 3" ID lines are required

8 Is a glycol injection system available? If the injection system is air operated, back-up air needs to be

available. Operating pressure of the injection system should be 15M with an air pressure of 75 psi

9 The glycol injection system is to be installed upstream the chokes. The glycol unit is to be kept away

from the drill floor vicinity.

10

The glycol reservoir with the pump should have 500 gallons minimum. Spare barrels of glycol should

be installed next to the pump unit as reserve, and means of transferring glycol to the pump unit should

be available.

11 The first valve down-stream the chokes should be rated to 15M


Choke an kill manifold HPHT conditions check list


12 The first valve up-stream the chokes should be hydraulic operated

13 Check the low temperature rating of the lines down stream the choke from buffer manifolds to

the mud gas separator (should be arctic or stainless steel)

14 Are temperature sensors fitted: on the choke line, on the BOP, upstream the chokes, on both

the choke line and flow line and on the poorboy degasser?

15 Are the high temperature alarms fitted and is it possible to read the mud temperatures on the

drillers console?

16 Are the temperature sensors properly protected from the environmental influences?

17 All temperature sensors should be approved explosion proof units

18 Sensor replacement should be possible while the lines are under pressure

19 Buffer tanks should be divided in at least two sections, isolated by a valve

20 Is a kill hose available with a working pressure of 15M ?

21 Chiksan type choke lines are not allowed

PROCEDURE-MUD GAS SEPARATOR

Mud gas separator (poor boy degasser) Usually a mud gas separator doesn’t have any elastomers installed

so there is no concern about this equipment (as far as rubber goods are concerned) but it is good practice to install temperature sensors in the line to the poor boy degasser with reading in drillers cabin.


Mud gas separator HPHT condition check list


1 The MGS should have a minimum throughput capacity of 10 MMscfd, not limited by blowdown

capacity

2 Check the length of the mud seal, minimum 10 ft; 20 ft recommended by HSE

3 What is the size of the vent line in the derrick, minimal ID = 8", preferable 12".

4 The line design should be as straight as possible. Bends, if any, should be as smooth as possible

5

For closed bottom type separators: a sipon breaker (secondary vent) of preferable 6" ID should be

fitted at the highest point of the mud return line. To prevent siphoning of mud from the mud

separator to the mud tanks (This line should NOT be connected to the mud gas separator vent line

6 Is it possible to by-pass the poorboy degasser and vent gas direct into the vent line in the derrick?

7 Can the well fluid in case of an emergency be discharged directly overboard via the high pressure

line and not the diverter line ?

8 Under no circumstances should it be possible to blow through the oil burner itself. (Because of the

risk of plugging).


Mud gas separator HPHT condition check list

ITEM DESCRIPTION YES/N

O

9 Mud gas separators must be sufficiently anchored in place and properly braced to

prevent movement of both separator and line during kick controls

10

The lines from the buffer manifold to the poor boy degasser shall be from arctic steel

(H2S) or stainless steel which has a greater resistance than the minimum possible

temperature -170°C

11 The separator should be hydrostatic pressure tested to 180 psi, to give 150 psi WP.

12 Check if it is possible to monitor the separator pressure from the remote choke panel or

drillers panel

13 The separator should have a pressure gauge fitted which can be seen while operating the

manual choke. (0-20 psi range)

14 A "Hot loop" system should be available to allow continuous circulation of fresh mud

from the pits to help maintain the seal

PROCEDURE-OTHER EQUIPMENT

Beside well control equipment other equipment has to fullfill

some recommendations shown through check lists

Mud system HPHT conditions check list


NO

1 Barite mixing systems to have at least two mixing hoppers.

2 Check mud pit agitation to minimise barite settling from high weight muds.

3 Check the horsepower of the centrifugal mixing pumps. (Min 75-100 HP)

4 What is the maximum mixing capacity when mixing barite with low mud

weights? (> 1 ton/min is recommended)

5 Check the minimum bentonite capacity

6 Check the minimum barite capacity. (300 MT)

7 Check the minimum cement capacity. ( 300 MT Class G )

8 Ensure that the mud capacity is sufficient (should be at least 350 m3 or 2200

bbl).

9 Check the capacity of the trip tank pump. (1000l/min with 2.3 sd mud

10 Bulk material feed rate should be a minimum of 500 kg/min. regardless of

the mud specifications.


Cement unit HPHT condition check list


NO

1 The cement pumps and lines should be rated to 15 M working

pressure

2 Check the certification of the pumps and high pressure piping. (Not

smaller than 3"; WP 15M)

3 The kill manifold from the cement unit should divert to a 15M rated

circulation hose (40 ft) kill line and choke manifold

4 The cement unit should have a remote control manifold outside the

cement/mixing room. (From the rig floor or the choke manifold)

5 Ensure that there are 15M wp relief valves installed at the discharge

lines of the cement unit. They must be tested and certified


General requirements


NO

1

Variable deck load should be cross checked against the

requirements. A site specific survey should be made. Deckload

capacity should be in excess of 2500 ton

2 Two 15K IBOP, one remote and one manual for top drive, (plus

spares) are required

3

One non return valve rated to 15K psi (Gray valve), one dart sub

including dart spares with connections to all contracted drill pipe

sizes are required.

CONCLUSION

This case study was inspired with preparations for drilling campaign on HT wells. Equipment adjustment to comply with HT standards was devided in two groups of works;

-rubber goods replacement

-replacement and installation of new equipment (coflexip hoses, temperature sensors..)

Since delivery time of new equipment was quite long proper planning (through out check lists) in this case was essential. Installation of new equipment that comply with HT conditions is good benefit (upgrade) for the rig and is advantage for the future projects regardless if there will be a requirement for HT condition or no.

CONCLUSION

On this way time required for adjust the rig for HT conditions will be much shorter since rubber goods delivery time is not critical.

Check lists shown through this case study can be very helpful while preparing a rig for project with HPHT requirements. Off course there could be additional requirement that are a matter of world region (location), operators experience in the past or a matter of precaution.

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