Offshore Drilling. Deep Water Challenges

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Marsha Hamilton
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1 Offshore Drilling Deep Water Challenges

2 Well Control Old movies sometimes had an oil rig where rig workers are running away from the derrick, excitedly yelling We hit a gusher! That is not an acceptable way to discover oil now, from an environmental or safety standpoint. On an offshore rig, the only escape is by lifeboat.

That is not an acceptable way to discover oil now, from an

4 Offshore Drilling Rigs In the late 1800 s the first offshore well was drilled in a lake in Ohio In 1896 drilling was performed from a pier extended into the Santa Barbara Channel first well in the Caspian Sea 1937 first well in the Gulf of Mexico As drilling move to deeper waters, Jack Up drilling rigs were built. The most recent generation rigs are limited to feet.

1923 first well in the Caspian Sea 1937 first well in the Gulf of Mexico As drilling move to

6 Drill Ships Later, drill ships and semi submersible rigs were developed for deeper water. Initially they were anchored, until in 1970 the first Dynamically Positioned (DP) ship was built.

8 Semi submersibles Semi submersibles, also known as column stabilized drilling units, don t have the storage capacity of drill ships but are better able to operate in areas severe sea states. The first DP semi was built by the Halifax Shipyard and launched in It was also the last of 7 drilling rigs built in Halifax. The newest generation rigs, Semis and drillships, can be operated in 12,000 feet of water and drill to depths of 40,000 feet. Currently there are approximately 60 floating drilling rigs under construction in shipyards, almost entirely in Singapore, Korea and China. Semi submersibles, also known as column stabilized drilling units, don t have the storage capacity of drill ships but are better able to operate in areas with severe sea states.

The newest generation rigs, Semis and drillships, can be operated in 12,000 feet of water and drill to depths of 40,000 feet.

10 Blow Out Prevention There are two means to prevent a gusher when drilling for oil and gas. The primary means is hydrostatic pressure with drilling mud, primarily using the mineral barite as a weight component. The secondary means is the BOP, or blow out preventer. The BOP is an arrangement of valves, rams preventers, annular preventers, connectors and control system. BOPs for land rigs and jack ups are a fairly simple system, as shown. Because they are on the surface and accessible at all times the control system is not complex.

The secondary means is the BOP, or blow out preventer.

12 Subsea BOPs A typical subsea BOP weighs in a range from ,000 lbs. They have more complex control systems and usually additional ram and annular preventers. Typical deepwater BOPs today have an internal diameter of 18 3/4 and are rated to 15,000 psi maximum wellbore pressure. The BOP is run subsea after the surface well has been drilled and a wellhead has been landed and cemented in the seabed.

Typical deepwater BOPs today have an internal diameter of 18 3/4 and are rated to 15,000 psi maximum

14 Choke and Kill Valves Valves called choke and kill valves on the BOP allow for high pressure gas and oil to be transmitted to the drilling rig to bring a well under control.

16 Lower Marine Riser Package The BOP has two sections, the Lower Marine Riser Package (LMRP)and lower stack. The LMRP usually has one annular, one connector to attach to lower BOP, the control system, gas bleed valves and a flex joint.

The LMRP usually has one annular, one connector to attach

18 Marine Riser and Telescopic Joint The BOP is run to the wellhead with Marine Riser pipe. This provides a means to return drilling fluids to the surface. Auxiliary lines on the riser provide hydraulic supply fluid (95% water, 5% soluble oil. Up to 50% glycol in cold weather areas.) High pressure choke and kill lines provide a means to bring any gas or other high pressure influx to the surface safely. Because floating rigs move, there is a motion compensation system, a telescopic joint and a flex joints on the top and bottom of the riser string. A telescopic joint can have a stroke from 55 to 70.

20 Marine Riser Tensioning System The marine riser is kept in tension with large pistons operated with an air/oil system at pressures up to 3,000 psi. The riser may be connected via a tensioning ring to wire rope which is reeved over sheaves on the pistons or the pistons may be connected directly to the riser tensioner ring.

The riser may be connected via a tensioning ring to wire rope which is reeved

23 Buoyancy As drilling progressed to deeper water, buoyancy modules were added to the marine riser to reduce the supported load.

25 Connectors Special hydraulically operated connectors, supplied by several manufacturers, are used to connect the LMRP to the lower BOP and to connect the BOP stack to the wellhead.

28 Flex joints To allow for rig movement away from the well center, there are flex joints located at the top and bottom of the marine riser string. Some drill ship also install and intermediate flex joint. Flex joints have typically have a maximum range of 10 degrees but the rig would disconnect the LMRP from the lower BOP before the angle reached 5 degrees.

31 Rams Pipe rams close around the drill pipe to seal off the wellbore and come in fixed sizes or variable, with variable rams having a designated range of pipe sizes they can accommodate. Shear Rams are designed to cut drill pipe and some sizes of casing. Casing is the pipe used to line the wellbore as the well gets deeper.

37 Annular Preventers Annular preventers can seal off on any dimension from open hole to the largest drill pipe or casing in the wellbore. The highest pressure rating of an annular preventer is 10,000 psi, which is below the highest pressure rating of a ram preventer, which is 15,000 psi. A 20,000 psi ram BOP is in the development stages.

40 Choke Manifold Choke manifolds are a series of gate valves and valves with variable orifices which are used to bring a well, which has had an influx of high pressure fluids into the wellbore, under control. High pressure wellbore fluid is directed to a degasser where the drilling mud is separated from the gas and the gas is vented to atmosphere.

42 Control Systems Subsea BOP have control systems that are supplied with fluid from a pump and accumulator system on the rig. Anchored rigs typically have a fully hydraulic system, with hydraulic pilot signals sent from the surface to operate the functions on the BOP subsea. Early dynamically positioned drill ships had electro hydraulic systems. With these systems an electric signal is send to a solenoid on the BOP which then sends a hydraulic pilot signal to a control valve. Multiplex (MUX) systems were developed to enable an ever increasing number of functions to be operated with just a few conductors in the MUX cable.

44 Control Systems Specifications Hydraulic control systems operate with supply pressure of 3,000 psi. MUX systems operate with supply pressure of 5,000 psi. Most functions are typically operated with 1,500 psi. Hydraulic fluid is supplied through rigid conduit pipe on the riser to accumulators in the BOP.

45 Control Panel Every rig must have a BOP control panel at the driller s station as well as one in a safe location away from the drill floor.

47 Control Pods BOPs must have completely redundant control systems on the BOP. These control systems are called pods and are designated Blue Pod and Yellow Pod in all systems, no matter which manufacturer. Some pods have redundant subsea electronic modules (SEMs) withing the pod for additional redundancy.

49 Safety Features To prevent accidental operation of critical functions, such as the BOP connectors and the shear rams, clear, pinned covers are installed on those functions.

51 Emergency Systems There can be as many as six emergency systems in a BOP to operate critical functions in the case of the loss of the primary control system. Emergency Disconnect Sequence (EDS) In a case where a DP rig has lost station keeping ability, the EDS is a one button system that allows the wellbore to be secured by closing the shear rams. The hydraulic functions to the lower BOP are then vented and the LMRP is separated from the lower BOP by unlatching the connector. An over pull is preset on the riser tensioners and the LMRP lifts from the lower BOP. A riser recoil system prevents a sling shot effect. After the EDS button is activated, the sequence takes about 55 seconds maximum.

52 Acoustic systems A limited number of emergency functions (typically shear rams and LMRP connector) can be operated from the rig using a hydrophone transmitting to transducers on the BOP. It is uncertain if these systems will work in a well control situation where considerable noise is generated from flow in the wellbore. Remote operated vehicles (ROVs) have pumps which can operate functions through a hot stab plugged into a dedicated receptacle in panel. The limitations of an ROV is the time to deploy from the rig to the sea bed and the limited flow rate of their pumps. A newly published standard by the American Petroleum Institute (API) specifies ROVs should be able to operate BOP functions in the same time as the primary control system. (rams 45 second to close)

53 Dead man systems will close the shear rams in the event all hydraulic and electric control is lost on the BOP. This would typically only happen if the riser string parted. In deepwater if the riser is lost, then the hydrostatic pressure of the drilling mud, which is needed to contain wellbore pressure, would be reduced as it is replaced by sea water. Closing the shear rams secures the well. Automatic Disconnect System (ADS) closes the shear rams when the lower flex joint reaches a preset angle. Autoshear closes the shear rams in the event the LMRP is unintentionally disconnected.

56 Locking Systems Because at certain wellbore pressures it is possible for rams to be opened by the wellbore pressure if the control system is lost, locking systems have been developed to keep the rams closed if the control system pressure is lost. Some system automatically lock the ram when it is closed but some locking systems must be operated separately.

API Std 53 - Blowout Prevention Equipment Systems for Drilling Wells Last update: August 12, 2015

API Std 53 - Blowout Prevention Equipment Systems for Drilling Wells Last update: August 12, 2015 6.1.2.12 53-03-15 Referring to Section 6.1.2.12, can a surface BOP stack arrangement with one annular, one blind shear ram, and two pipe rams, with the fifth device being optional, be considered a Class