Continuous circulation reduces NPT

Katrina Ridley and Bill Portas, Shell; Jeff Robbie and Henry Pinkstone, Managed Pressure Operations

As operators attempt to tap increasingly challenging reservoirs, narrow pore pressure/fracture gradient windows can make it rather difficult to drill a well conventionally. Managed pressure drilling (MPD) has proven to be a robust method for maintaining constant bottomhole pressure (BHP) and, thus, remaining within these narrow drilling margins. Managing BHP via a continuous circulation system provides other benefits as well, including reduction of stuck pipe incidents, the ability to rely on rig mud pumps rather than third-party equipment, and—when drilling with air or foam—time/cost savings on connections.

Two operators performed field trials using a new continuous circulation system from Managed Pressure Operations (MPO): Oil Search in Papua New Guinea in an air-foam drilling application, and Shell in South Texas using oil-based mud (OBM). These trials demonstrated the system’s ability to maintain circulation and, thus, BHP during connections, greatly reducing a major source of drilling nonproductive time.

Fig. 1. The control manifold with valves labeled according to their configuration in the connection procedure.

SYSTEM COMPONENTS AND OPERATION

MPO’s Non Stop Driller system is composed of two major components. The first component, a control manifold, is used to divert mud flow from the top drive to the side entry valve on the second component, the circulating sub.

A circulating sub is made up on the top of each stand of drill pipe. Each sub contains a side entry valve and a ball valve (also called a kelly valve). The side entry valve is spring loaded and non-returning, and it can be opened from the connector head once its protective cap is removed. The protective cap guards the valve from downhole conditions while drilling and prevents annular pressure from infiltrating the drillstring. The side entry valve is rated to 10,000 psi and can handle flowrates up to 600 gal/min. The ball valve in the circulating sub isolates the drillstring volume when in the closed position, in order to break the connection with the top drive when a new stand of drill pipe is picked up.

Each sub is made up on top of the new stand with the ball valve in the open position, so as to allow flow through the top drive.

A typical connection would commence as follows:

• Drill down stand A with circulating sub A made up on top and the ball valve in the open position, and set the slips.

• Remove the protective cap from the side entry valve.

• Make up the connector head to the side entry valve.

• Open valve 1 while leaving valve 5 (Fig. 1) in the open position on the control manifold, so a portion of the flow is now running through the top drive and the other portion is running through the side entry valve.

• Wait for the pressure across the ball valve to equalize, as determined via the pressure gauges on the manifold.

• Close the ball valve in the circulating sub.

• Close valve 5 on the control manifold, so no flow is diverted through the kelly hose/top drive.

• Bleed off the pressure in the kelly hose to the trip tank via pipe work from the rig floor by opening and subsequently closing valve 6.

• Back off the top drive and pick up stand B and circulating sub B.

• Make up stand B to the top of circulating sub A, which was previously drilled down.

• Open valve  1 on the control manifold, so a portion of the flow fills the new stand of drill pipe via the top drive and a portion of the flow is still running through the side entry valve of sub A and down the drillstring.

• Wait for the pressure across the ball valve to equalize by once again observing the pressure gauges on the control manifold.

• Orient the ball valve such that it is in the open position, so flow may run into the drillstring from the top drive.

• Close valve 1 in the control manifold, so no flow is diverted to the side entry valve in sub A via the manifold hose.

• Bleed off the manifold hose to the trip tank.

• Check that pressure is no longer on the manifold hose via the telltale on the connector head.

• Break out the connector head and replace the protective cap over the side entry valve of sub A.

• Remove the slips and drill down stand B with circulating sub B.

The process would repeat for each stand of drill pipe used to drill through the desired interval, Fig. 2. In the case that one of the valves on the manifold becomes washed out, it should be noted that valves 2 and 4 are redundant to valves 1 and 3. The control manifold is also equipped with a pressure relief valve (PRV) that will activate if the flowing pressure exceeds that set by the operator. This PRV may be set at a rating just below the PRV rating for the rig pumps, so as to ensure that the PRV for the rig pumps is not inadvertently activated.

AIR/FOAM APPLICATION

Drilling through the Darai Limestone in Papua New Guinea in air/foam drilling fluid applications has presented challenges such as deteriorating hole conditions, dynamic BHPs and lengthy connection times when shutting down the rig pumps to make up a new stand of drill pipe. The continuous circulation system has helped to overcome these challenges by enabling operator Oil Search to perform MPD via continuously circulating drilling fluid through the well.

Deteriorating hole conditions. Previously, drilling through the Darai Limestone required making a connection while 30 ft off bottom, in order to allow the operator to jar the drillstring free after making the connection. Upon shutting down the rig pumps, circulation in the annulus would cease, and differential pressure between the annulus and the formation would cause the drillstring to become stuck.

By continuing to circulate drilling fluid through the well, the new system has prevented the development of differential pressure between the formation and the annulus that would be great enough to cause stuck drillstring. Thus, jarring is no longer necessary, and the operator is able to make a connection with the drillstring on bottom.

Dynamic BHPs. High break-over pressures were often observed as the foam column was being reestablished in the annulus after a connection. This high break-over pressure was required to force the formation water ingress out of the hole, and could exceed drilling pressure by as much as 1,000 psi. This high pressure was believed to cause wellbore damage as the near-wellbore zone was pressure cycled. By maintaining constant downhole conditions during connections, the new system allowed for continuous foam injection, reducing water ingress into the wellbore and eliminating the problems caused by wellbore pressure cycling.

Lengthy connection times. Connections can take up to 45 min. when drilling the Darai Limestone with air/foam, which includes the time required to circulate the wellbore clean and to completely depressurize the string prior to the connection. Once the connection is made, stable foam-circulating conditions must be reestablished before drilling ahead.

By allowing constant foam circulation over each connection, average connection times were reduced from 45 min. to 10 min. by eliminating the need to circulate the wellbore clean, depressurize the drill pipe, and reestablish circulation. The time saved was utilized making up the next stand, resulting in considerable rig time savings on a high-spread-rate operation.

Fig. 2. Continuous circulation system flow diagram.

OIL-BASED APPLICATION: EROSION TESTING

Given the high concentration of lost-circulation material (LCM) being used to drill wells with tight pore pressure/fracture gradient margins, an erosion testing program was created during the field trial in Shell’s high-pressure, high-temperature (HPHT) asset in South Texas. Through the third quarter of 2010, the only drilling fluid medium used when testing the continuous circulation system in the field was air/foam; however, the application in South Texas was for an OBM system.

Erosion testing was performed on three continuous circulation system valves before the well’s intermediate section was drilled. Three tests were conducted using three different flowrates: 300, 450 and 600 gal/min. Each test consisted of one hour of pumping a 12-lb/gal OBM through the side entry valve, followed by a 10-bbl, 20-bbl and finally 30-bbl sweep of 45-lb/bbl LCM.

Advanced testing revealed wear to the side entry valve following the LCM sweeps, but no wear was seen during the initial tests with the 12-lb/gal OBM. The valves held pressure throughout the trials, indicating that breakdown only occurred during the LCM sweeps, which would normally be pumped down the drill pipe and not typically through the NSD valve.

Based on this testing, MPO redesigned the internal structure with the aid of finite-element analysis (FEA). Minor changes to the geometry of the internal components have resulted in significant reduction in erosion caused by cavitation. All subsequent valves have been manufactured with the new geometry.

OIL-BASED APPLICATION: DRILLING TRIALS

After erosion testing, the continuous circulation system was used to drill the final section of an intermediate hole from 6,620 ft to 8,776 ft. Twenty valves, consisting of 18 subs and two joints of subs integrated with drill pipe, were used. One of the continuous circulation subs was installed on top of the first stand of drill pipe just above the BHA in order to monitor how it would hold up against the harsh drilling conditions of the entire 8¾-in. section. This sub was in open hole while drilling vertically for 6,346 ft. Upon pulling it from the drillstring, it was observed that the protective cap was intact and that both the side entry valve and the ball valve were in working order.

Pressure-while-drilling (PWD) measurement was used throughout the intermediate section to monitor BHP. Pressure profiles from a conventional and a continuous circulation connection are plotted in Fig. 3. In the conventional connection, one can clearly see the pressure drop due to loss of equivalent circulating density and the rotational effect from the drill pipe. In the continuous circulation connection, the rotational effects of the drill pipe can be seen to decrease or increase BHP by up to 60 psi. These pressure spikes can be eliminated by increasing or decreasing the mud pumps to counteract the effects of rotation on BHP. It is also evident that the pressure trends downward throughout the connection, due to the cuttings being unloaded out of the hole. The BHP would continue to drop until all cuttings had been removed from the annulus. However, this downward trend can be controlled by varying fluid injection rates.

The slight pressure drop toward the end of the continuous circulation connection is due to the void stand being filled before equalizing and opening the isolation valve. This drop can be eliminated by filling the void stand under pressure before equalizing. On average, the pressure drop (not taking into consideration the cuttings removal from the annulus or the rotary effect) was 17–21 psi over the 20 continuous circulation connections made. Throughout the trial, no background gas was observed at surface, indicating that no influx was taken during connection. This was paramount in the trial, as drilling with tight pressure margins in tight gas formations necessitates a reduction and/or complete elimination of drill gas.

Over the course of the trial, continuous circulation connection times were on average 10 min. longer than conventional connection times. However, the additional time required for continuous circulation connections decreased from 20 min. at the beginning of the trial to 6 min. by the end, which can be attributed to improving task familiarity. While extra time was taken to perform a continuous circulation connection, this increase is more than compensated for by the elimination of the need to wipe the stand prior to the connection, to restart the pumps and to stabilize the wellbore prior to drilling after a connection.

Once the intermediate section of the well had been completed, the continuous circulation system was used to pump three stands out of the hole using the mud bucket. All three stands were pumped out of the hole with minimal effect on BHP. The mud bucket diverted the drill pipe contents to the trip tank and prevented the release of excess OBM on the rig floor.

Fig. 3. Bottomhole pressure during a connection for the continuous circulation system and for a conventionally drilled well.

FUTURE IMPLICATIONS

Through the course of the field trials in both the air/foam and OBM applications, many learnings were garnered. The system was proven to conserve time and therefore money in the air/foam application by reducing time necessary to recirculate the well. The act of continuously circulating also proves to greatly reduce the risk of stick pipe after connections. Upon erosion testing and FEA of the valves within the continuous circulation sub, some wear was found to occur when pumping high concentrations of LCM through the side entry valve. This wear will be mitigated through the change of geometry in the sub components. Finally, a greater understanding of BHP has been obtained. The continuous circulation system allowed Shell to maintain the BHP within a window of 25 psi. The knowledge of cuttings unloading, filling of each stand of drill pipe upon connection and the rotational effects of the drill pipe will further enhance this method to maintain a more constant BHP.

An extensive hazard identification process was undertaken before the Shell field trial. Training was done to ensure that rig personnel both understood and were confident with the system and the process of making connections. Also, a clear allocation of responsibilities was laid out for all involved in the process. Although the rig personnel safely performed 20 continuous circulation connections without incident, a few safety concerns persist. The greatest concerns relate to crews using a pressurized hose on the rig floor and crew exposure during connections. Due to these concerns, MPO has been working toward a fully automated version of the continuous circulation system. This new system has been designed and will be ready for commercial use by year’s end.  

Jeff Robbie is Operations and Engineering Manager for MPO. Before joining MPO, Mr. Robbie spent 15 years in the underbalanced drilling (UBD)/MPD arena, working in various locations worldwide. Since 2007, his career focus has been on project management and implementation of UBD/MPD projects.