2012Global and Regional MarketsInnovating While Drilling®July/August

Continuous circulation system keeps ECD steady on Kvitebjørn

Statoil uses system in conjunction with MPDto enhance drilling of pressure-sensitive formation

By Neil Ross, Tim Scaife and Robin Macmillan, National Oilwell Varco; Per Cato Berg, Statoil; James Jenner, Coupler Developments

Figure 1: In the Kristin S-2-H subsea well offshore Norway, a high-pressure zone below a depleted reservoir was drilled using the CCS to maintain uninterrupted circulation and a steady ECD to stay within the pore pressure/fracture pressure gradient window.

To construct new wells and continue production, Statoil decided to include the Continuous Circulation System (CCS) on the Kvitebjørn field of the North Sea. The CCS allows drill pipe connections to be made up or broken out without stopping drilling fluid circulation to the drill string. Uninterrupted circulation is particularly beneficial when drilling pressure-sensitive formations where adding or removing the dynamic component of the circulating pressure destabilizes pressure conditions in the wellbore, causing hole problems, lost time and additional costs.

What is the CCS?

The core of the CCS is a pressure vessel constructed from three blowout preventer (BOP) bodies surmounted by a snubbing device, which can apply sufficient torque to make or break drill pipe connections and control the vertical movement of the disconnected drill pipe against the circulating pressure. The pressure vessel (Main Unit) contains three sets of rams, blind in the center and pipe rams top and bottom, the lower set being upside-down to contain pressure from above. When in use, the Main Unit is located on the rotary table with the drill string passing through it. To make or break a connection while continuing to circulate, the drill string is landed in slips connected to the Main Unit, and the pipe rams are closed, isolating the tooljoint before filling the cavity between the rams with drilling fluid at circulating pressure.

The snubber then breaks the connection and allows the pin to rise under control before closing the blind rams. Circulation continues through the open drill pipe box below the blind rams and is closed to the top drive before bleeding off the pressure above the blind rams and opening the upper pipe rams to allow the next stand/joint of pipe to be picked up. The procedure is reversed to make the new connection.

The principle attributes of the CCS are:

• Only one modification to the rig is required to install the system;

• No changes or additions to the drill string are needed;

• All connection operations are safely confined within a pressure container constructed from conventional blowout preventer components; and

• The connection process is “hands off.”

The CCS can be used on any rig equipped with a top drive and with sufficient height clearance within the derrick to allow a drill pipe stand to be raised 3 meters above the rotary table for access into or withdrawal from the Main Unit.

It can be used to drill with open annulus returns or in conjunction with managed pressure drilling (MPD) rotating BOP, closed annulus systems.

The earliest commercial application of the CCS was the successful re-entry and deepening of a high-pressure gas discovery well offshore Egypt in 2005, (SPE 102859). Since then it has found application in re-entering and deepening high-pressure, high-temperature (HPHT) gas wells offshore Norway for two major operators and is being introduced to drilling operations offshore Brazil.

Figure 2: The main components of the CCS – the Main Unit, the mud diverter skid, the control container and the control panel – are essentially standard for all installations. The top drive interface is another essential component and is picked up and installed when the CCS is located on the rig floor over the well.

The Kvitebjørn Field

The gas/condensate field is located in the Norwegian sector of the northern North Sea, southeast of the Gullfaks field. It has been developed from a platform in a water depth of 190 meters. The HPHT reservoir comprises Mid-Jurassic Brent and lower Jurassic Cook sandstones with the top at approximately 4,070 meters TVD. The initial reservoir pore pressure was 775 bar (11,237 psi) and formation fracture pressure 875 bar (12,685 psi), but pressure depletion induced by early production resulted in the convergence of pore and fracture pressure gradients.

After drilling nine development wells, a pressure reduction of more than 140 bar (2,030 psi) had occurred, and circulation could not be maintained when drilling through the reservoir. Massive losses were experienced while drilling the 34/11-A-2 well, and further drilling was suspended as it was no longer possible to safely drill the reservoir.

Production was reduced by 50% in December 2006 and completely shut down in May 2007 when depletion reached nearly 200 bar (2,900 psi).

Remedial Action Plan

To construct new wells and continue production from the field, a Statoil drilling team reviewed the situation and established an MPD program to safely drill the reservoir. As a member of the joint industry project that supported the development of the CCS, Statoil decided to include the system in the MPD “toolbox” that resulted, together with pressure control while drilling (PCWD) equipment (rotating BOP, automatic annulus choke control), hydraulic flow modeling, designer mud system, etc (SPE/IADC 114484).

Including the CCS would enable two important parameters to be controlled by maintaining uninterrupted circulation during connections. Having established the dynamic circulating pressure or equivalent circulating density (ECD) required to achieve the bottomhole pressure (BHP) required to safely drill in the reduced pore pressure/fracture pressure gradient window, maintaining it during connections would be critical to avoid loss of circulation and/or high-pressure gas influx.

The downhole hydraulic stability would also maintain a stable circulating fluid temperature profile, which was expected to improve the monitoring and detection of trends in other drilling fluid circulation parameters. Continuous circulation would also eliminate the negative and positive pressure surges generated when stopping/starting circulation to make connections conventionally. These pressure surges can create BHP fluctuations and hole problems in HPHT wells.

After drilling the reservoir section in MPD mode, tripping out of the hole could be safely managed only if an overbalance on the BHP could be maintained. A caesium/potassium (Cs/K) formate mud pill (BMP) was developed to support a weighted mud column placed above the lighter drilling fluid. The drill string could be circulated approximately two-thirds of the way out of the hole using the CCS, before displacing this isolation pill and then circulating heavier mud into position above it to maintain the necessary safe BHP.

After displacing the heavier mud to the well, the CCS could be down rigged, and normal tripping operations can be resumed. The reverse routine would apply when running in with a new BHA.


Following the successful re-entry of the Port Fouad Marine Deep well offshore Egypt, the CCS was used by Statoil to re-enter and deepen the Kristin S-2-H subsea well offshore Norway in March/April 2006 using the Scarabeo 5 semisubmersible. A high-pressure zone below a depleted reservoir was drilled using only the CCS to maintain uninterrupted circulation and a steady ECD to stay within the pore pressure/fracture pressure gradient window (Figure 1). With a mud weight of 1.98 sg, an ECD of 2.06 to 2.13 sg was maintained while circulating at 250-380 gals/min (950-1,440 L/min) and 3,000-3,800 psi (207-262 bar) with no annulus control.

Some 216 meters of 8 ½-in. hole were drilled to a TD of 5,362-meters MD. During the drilling operation, 151 connections were made while drilling and reaming without interrupting the circulation of fluid to the wellbore. The success of this operation and the experience gained helped to establish the CCS with Statoil as a viable and reliable drilling tool.

Figure 3: Mud weight and circulating profile for well Kvitebjørn 34/11-A-13 were based on known pressure data from previously drilled wells where the pressure gradient declined from 1.92 sg at the top of the reservoir to 1.82 sg at the base.

The next stage was the inclusion of the CCS in the MPD planning for the Kvitebjørn wells. This occupied approximately two years, during which engineering studies and extensive testing of the MPD package were carried out to ensure the compatibility of all the technologies involved. Hazard identification and hazard operability studies were also conducted together with regular meetings with Norway’s Petroleum Safety Authority to keep it advised and gain its support.

Trials of the BMP and the CCS were carried out at the Ullrig facility in Stavanger prior to offshore operations.

Installation of the MPD package on the small, automated Kvitebjørn platform required careful planning, and considerable effort was expended on commissioning and testing the systems. For the CCS, the main components were as shown in Figure 2 and are essentially standard for all installations. The main items are:

• The Main Unit, which is located over the rotary table when in use. When offline, a set-back, servicing and testing area is required, which must be accessible by a rig crane;

• The mud diverter manifold (MDM), which can be located anywhere convenient for connection to the high-pressure mud delivery line between the mud pumps and the standpipe manifold. An isolation manifold in the high-pressure mud line for connection to the MDM is the main modification to the rig required for the CCS. High-pressure flexible hoses connect the MDM to the CCS;

• Control container and high-pressure power unit. This houses the computer control system and the hydraulic fluid power supply for the system and can be located anywhere from which the hydraulic hoses and fibre-optic cables can be safely run to the rig floor; and

• Control panel located at the driller’s position, from where the CCS is operated.

The other essential components – the extension saver sub and top drive interface – are picked up and installed when the CCS is located on the rig floor over the well.

Prior to commencing an operation with the CCS, it is essential that a survey of the rig/platform is carried out before planning the layout of the components and where hydraulic control hoses, cables and high-pressure mud hoses can be safely positioned to minimize tripping hazards, pinch points, etc. This was particularly important because of the small size of the Kvitebjørn platform and the space required for the PCWD equipment. After installation and testing, time was allocated to familiarize and train the drilling crew on operations with the PCWD and CCS equipment.

In addition to the equipment, four/five personnel were required to service and operate the CCS on a two per 12-hr shift rotation, plus supervisor. This had an impact on the available rig accommodation.


After completing the tests at the Ullrig facility, Kvitebjørn 34/11-A-13 was the first well on which MPD was used (SPE/IADC 114484). After being synchronized with the rig operating systems, the CCS performed reliably as part of the MPD package. Considerable time was devoted to training the drilling crews on operations with the combined MPD installation and CCS before starting drilling. This included rigging up the CCS over the well and making and breaking connections with no circulation; dry connections, before starting circulation and repeating the process with live drilling fluid in the system. The CCS was finally employed once the BHA had been run and washed to bottom in open hole and the MPD drilling parameters had been established while circulating the Cs/K drilling fluid. The mud weight and circulating profile were based on the known pressure data from the previously drilled wells where the pressure gradient declined from 1.92 sg at the top of the reservoir to 1.82 sg at the base (Figure 3). The objective was to start drilling with an ECD of 1.94 sg and maintain this 0.02-sg margin over the measured pore pressure as the reservoir was penetrated.

To enable this, formation pressure while drilling and ECD measurement were included in the MWD suite in the BHA.

The reservoir was successfully drilled from 6,101-meters MD to 6,351-meters MD. With the combination of MPD and MWD tools, the ECD was accurately measured, allowing the mud weight to be reduced from 1.84 sg to 1.81 sg and still maintain the margin of 0.02 sg over the reservoir pressure.

Figure 4: Throughout the operation on well Kvitebjørn 34/11-A-13, 222 connections were made with the CCS in an average of 32 min, including connections made for training. Without training times, operational connections were approximately 20 to 25 min.

While drilling the reservoir, a wash-out was detected, and the drill string parted while being pulled under MPD conditions. With the CCS in place, it was possible to continue circulating and control the well while displacing a 2.12-sg BMP at approximately 1,800 meters to establish hydrostatic balance while conducting fishing operations.

After recovering the fish, drilling resumed and TD was reached without further incident while maintaining an ECD of 1.92 sg with a combination of PCWD and the CCS. The average drilling parameters were 1,000 L/min (265 gal/min) circulating rate and 100 RPM with a rotary torque of 45-58 KNm (33,000-43,000 ft-lbs). The annulus choke pressure was 14-16 bar (200-230 psi) with a circulating rate of 580 L/min (150 gal/min) from the auxiliary pump.

Formation pressures varied throughout the reservoir, with a maximum depletion of 124 bar (1,800 psi) in the lower Ness Formation. At TD, an overbalanced mud system was circulated into place to control the well prior to completion activities, including running a liner.

CCS Performance

As an integral part of the MPD package, the CCS performed well throughout the section and made connections without interrupting circulation. A tapered drill string of 4 ½-in. and 5-in. OD drill pipe was used in anticipation of encountering high rotary torque. The CCS only operated on the 5-in. OD pipe and routinely made up and broke out connections with up to 63 KNm (46,000 ft-lbs) of torque. During the connection process, the standpipe pressure fluctuated by around 6 bar (85 psi), mainly due to repressurizing the fluid in the upper chamber of the Main Unit from the standpipe after making a connection. This was reflected in a variation downhole of less than 2 bar (30 psi).

Throughout the operation, detailed records of CCS performance were kept by the operations team, including examples of typical connection time graphs (Figure 4) and circulating pressure profiles in the standpipe and lower CCS chamber (Figure 5). In addition, each connection made or broken was logged by the CCS operator and records kept of any issues arising, actions taken and of spares and other consumables used during the operation. All this information was made available to Statoil.

During drilling operations on the A-13 well, 222 connections were made with the CCS in an average time of 32 min, which included connections made for training purposes. Discounting training times, operational connections were in the 20-25 min range. Connection time is measured from the time drilling ceases until it can be resumed. While it may seem long by conventional standards, it is partially affected by the operating speed of the rig’s pipe-handling system.

When used to drill complex HPHT wells, such as on the Kvitebjørn field, the ability to maintain the established downhole circulating pressure environment while making connections is of prime importance, not the time taken. Conventionally, with the pressure surges experienced when stopping and starting circulation and the loss of the ECD, it could take even longer to make a connection in pressure-sensitive formations or even prove impossible to safely drill such a hole section.

Further Operations

Following the success of MPD operations on A-13, the system was used to drill the A-12 well in October/November 2007. Statoil has continued to develop the Kvitebjørn field using MPD to drill the depleted reservoir in wells A-3 in 2008, A-9 in 2009, A-7 in 2010 and A-1 in 2011.

During February/March 2008, the CCS alone was again deployed by Statoil on the Scarabeo 5 semi to drill the reservoir section of the Kristin N-2H well. Drilling with continuous circulation without annulus control and using the data from MWD logging tools, the ECD was used to keep the well under control, avoiding loss of circulation to the depleted zones in the reservoir.

Typically when drilling the 8 ½-in. hole and circulating at 1,000 L/min (265 gal/min), an ECD of 2.05 sg could be maintained with a static mud weight of 1.96 sg. At TD, the drill string was pulled with continuous circulation into the last casing shoe before displacing heavier 1.98-sg mud to the casing to maintain the BHP before down-rigging the CCS and tripping normally.

Continuous circulation technology was used by ConocoPhillips on the Eldfisk B-01 well (November 2010) and Eldfisk A-27 well (June 2011). With the CCS, a stable pressure environment and constant ECD was maintained to drill and underream the reservoir section. No annulus control was used, and the wells were displaced to heavier mud at TD before running casing.


In operations over a period of more than six years, the benefits of drilling pressure-sensitive formations with uninterrupted circulation have been demonstrated. The CCS has been regularly used, both with MPD equipment and on its own, to maintain a steady ECD when drilling formations with narrow pore pressure/fracture pressure gradients. The only significant modification since its introduction was the increase in the torque capacity of the snubber to handle 5 7/8-in. XT drill pipe and the increased height of the Main Unit necessitated by the additional spaceout between the rams to accommodate the extra length of the tooljoints.

For future operations, a way must be found to reduce the time taken to install and rig-up/rig-down the system. This is essentially a planning and logistics problem, depending on the layout of the rig or platform and the other coincident activities. The control system must also be developed with the objective of automating and speeding up the sequence of operations involved in the connection process. For long-term use, integration with the rig’s control system should be investigated, which in turn should reduce the number of personnel needed to operate the system, particularly when deployed on offshore installations.

References and author acknowledgments for this article can be found online at www.DrillingContractor.org.

This article is based on SPE/IADC 156899, “Use of the Continuous Circulation System on the Kvitebjørn Field,” presented at the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, 20-21 March, Milan, Italy.

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One Comment

  1. Hello,
    i’d like to understand the mechanism how the CCS works, how we can circulate while making connections.
    does the system has any drawbacks?
    iwould liketo have an idea about the day rate cost of the CCS compared to conventional drilling.
    thanks in advance.

    Best regards.

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