CLOSED-LOOP CIRCULATING-2: Manual pressure management enhances safety, efficiency

Jan. 3, 2011
Manual pressure management in a closed-loop mud circulating system enhances safety and efficiency of drilling and completion operations.

David Pavel
Brian Grayson
Weatherford International Ltd.
Houston

Manual pressure management in a closed-loop mud circulating system enhances safety and efficiency of drilling and completion operations.

This is the second of a four-part series of articles on the benefits of closed-loop circulating systems. The previous article (OGJ, Dec. 6, 2010, p. 84) discussed the system fundamentals, the data acquired with a closed-loop system, and how the system helps in early kick and loss detection during conventional drilling operations.

The two remaining parts will cover automatic control for managing the mass flow balance across the entire wellbore and ways in which companies use closed-loop pressure data for optimizing the drilling and completion plan.

The change to a pressurizable, closed-loop system marks a transition from reactive, wait-and-see well control to active pressure management. In both conventional drilling processes and managed pressure drilling (MPD) applications, a closed-loop system is the basis for real time, high-resolution kick and loss detection, advanced wellbore pressure management, and faster well control.

These capabilities have safety advantages for personnel, the environment, and the rig, and they improve efficiency with less unproductive time and faster penetrations rates.

The data acquired by these systems also contribute to wellsite pore-pressure predictions that enhance well planning and hydrocarbon analysis.

Pressure at both ends

In a closed-loop system, incompressible drilling mud serves as a sensitive instrument for understanding and managing wellbore pressure and flow.

These screen captures show a reaction to loss on the right and wellbore ballooning-breathing on the left (Fig. 1).

As discussed in Part 1, this capability allows for early kick and loss detection because one can detect very small downhole influxes or losses within seconds at the surface-in terms of gallons rather than barrels-to provide a much greater understanding of annular conditions.

This information enhances the speed and effectiveness of pressure control methods. An event once detected can be addressed with changes in mud weights and chemistries as well as blowout preventer procedures. The characteristics that make a closed-loop system a highly effective listening tool allows fast, precise control of wellbore pressure using MPD techniques.

Pressure travels both ways in this system. Initiated downhole by the formation, it signals an influx. Initiated at the surface, it is a medium for managing downhole annular pressure. The application of annular pressure at the surface controls the pressure (Fig. 1).

In an MPD application consisting of a contained, pressurizable circulation system filled with incompressible fluid, the addition or reduction in surface pressure yields nearly instantaneous changes in annular conditions.

The benefits in safety and efficiency are considerable. With subtle changes in surface pressure (backpressure), a driller can actively manage small variations in the wellbore pressure profile to suppress events that could otherwise escalate into well-control situations. Kick-loss cycles that persist are costly risks managed by preventing them from developing.

In addition, the fast refresh rate and fidelity of data are further enhanced in a pressurized MPD application. The improved flow and pressure feedback provides an even more comprehensive understanding of wellbore dynamics.

During these MPD operations, conventional blowout preventer and mud systems remain in place and ready for use. But in an MPD wellbore application, these tools are the last line of defense, not the first. Through timely response to minute anomalies in the mass balance, the system reduces the chance of any influx or loss developing into a well control event.

Adding MPD control

The addition of a rotating control device (RCD) above the BOP to contain the annular returns and divert them away from the rig floor creates a closed-loop system (Fig. 2). The diversion is itself a safety feature that has led to the broad use of RCDs.

With the introduction of instrumentation and data acquisition capabilities, this closed-loop system becomes a very effective tool for early kick and loss detection. This configuration of RCD, instrumentation, and analysis capabilities is the most basic application for such systems as Weatherford's Microflux control technology. The system monitors and analyzes very small wellbore influxes and losses in real-time with specialized software that applies proprietary algorithms to flow and pressure data.

This information provides data for conventional well control method or for MPD methods that allow for an advanced level of active control that defines pressure management. The driller gains control in an MPD system by applying surface pressure with a choke manifold (in either a manual or automated configuration) and perhaps an annular pump.

The shift to MPD advanced drilling safety and efficiency. The International Association of Drilling Contractors defines MPD as "an adaptive drilling process to more precisely control the annular pressure profile throughout the wellbore" (IADC UOB & MPD Committee glossary, January 2008). A risk-assessment study done in conjunction with the Drilling Engineering Association (DEA 155 JIP) determined that, properly applied, MPD has a high probability of mitigating most, if not all, drilling-related risks.

"Managed Pressure Drilling continues to demonstrate its bright future," the DEA study observed. "This is not to say that there have been no problems," the report stated. "Sometimes pipe gets stuck and lost circulation problems still exist, but not with the same magnitude as in conventional drilling."

One beneficial aspect of MPD, noted the DEA study, is its effectiveness in enhancing safety as well as mitigating drilling hazards. These safety advantages extend beyond drilling. While MPD operations typically are discussed in drilling terms, they also are used when casing or completion tubulars are run in an openhole where surging or swabbing might occur. Up to 7-in. casing can be run through MPD system that can provide a controlled environment while circulating out a riser with drill pipe in the hole.

Manual pressure manipulation

In many applications, manual manipulation of surface pressure is sufficient. Typically concerned with addressing unforeseen kicks or losses, these manual configurations may consist of only a choke manifold or can include an auxiliary pump (Fig. 2).

Drilling with nominal surface pressure can suppress influxes quickly and losses can be managed, minimized, or cured gradually. More specifically, a surface choke automatically closes to apply surface pressure and opens to relieve it, thereby increasing or decreasing hydrostatic pressure. With losses, drillers can also use conventional mitigation techniques.

A typical MPD application holds surface pressure when connections are made. This is often a critical period, even in conventional operations, because kicks are more likely due to frictional pressure losses and more difficult to control considering the inability to pump down the disconnected drill string.

In MPD operations, continuous flow through the choke manifold or a shut in of the well to trap surface pressure and maintain annular conditions allows the operator to apply surface pressure to deal with difficult kick-loss cycles during pipe connections. The latter tactic requires synchronous and gradual closing of the choke as the speed of the mud pumps decreases and flow into the well ultimately stops.

When performed successfully, this tactic contains or traps surface pressure, which maintains constant annular conditions as the connection is made. It is a fairly simple approach that can be very effective. It relies, however, on experienced and skilled operators as well as on the efficiency of the choke manifold to maintain the trapped pressure. Optimal equipment upkeep is imperative to minimize occurrence of pressure leaks.

An easier approach involves the use of an auxiliary pump for circulating through a strategic flow-path that bypasses the well but not the choke manifold; thereby, enabling it to build and maintain surface pressure during pipe connections. This strategy enables mass balance monitoring for early kick and loss detection.

When the wellbore is closed in, the de facto absence of return flow relegates early kick-loss detection to surface pressure measurements, impairing overall effectiveness. On the contrary, auxiliary flow through the choke manifold, and specifically through the flowmeter, enables mass balance monitoring. The signature of gains and losses remains the same, enabling operators to increase surface pressure to suppress kicks or relieve the same to cure losses.

Coordinating a response

An early kick-detection configuration includes most of the control system components for expanded operations. With these components already on the rig, shifting into other operating modes is largely a matter of what is done with the information.

This involves a degree of sophistication that comes with the skill set of the people who are managing the operations, from the service and operator engineers to the rig crew. The service MPD operator works closely with the driller and the company man. It is critical that everyone involved in the drilling operation have a clear understanding about the job's objectives and parameters and what to do when there is a well control event. Contingency plans are always important.

An important requirement of this dynamic is to understand when to move from MPD to a well control mode, using conventional well control techniques. By design, MPD equipment has a lower pressure rating than BOP systems.

If surface pressure cannot suppress a high-pressure kick and therefore prevent it from being circulated out the well safely, a viable alternative must be implemented. Nonetheless, even in this situation an RCD provides additional time to actuate the BOP by diverting flow away from the rig floor.

Global examples

Managing the pressure profile of the wellbore with surface pressure has enhanced the safety and improved the efficiency of many wells in which it was difficult to control influxes and losses.

For instance, on a well in South America, a rig took a large kick while in the MPD mode. An attempt to close the BOP failed, and pressures at the surface reached 4,800 psi but stayed within the RCD operating limits, allowing the kick to be brought under control with the MPD system.

On recent MPD wells in the Haynesville shale in northwest Louisiana, better control in gas prone sections resulted in several improvements. The MPD enabled the use of lighter mud weight that increased penetration rates to 40 fph compared with 15 fph with 16.5 ppg mud.

Better drilling rates and less non-productive time associated with well control has cut drilling days in half. The system also has enhanced safety because it can hold gas influxes to small volumes through the application of backpressure and the circulation of gas out of the system in a matter of hours.

Offshore Egypt, the use of a choke manifold to manage surface pressure and the annular pressure profile minimized wellbore ballooning in a well with a tight operational window. In addition, the MPD system allowed pipe movement and stripping out of the hole should a well control event occur. The rig drilled to the targeted section without incident, avoiding the risk and cost of difficult kick-loss scenarios that commonly add many days to the drilling schedule.

In another Middle East application, MPD methods enhanced safety and efficiency despite kick-loss events involving high pressure H2S gas. Constant flow measurement allowed kicks to be distinguished from simple flow variations.

East Texas gas wells drilled with the MPD control system reliably have identified high pressure kicks, allowing the rig to shut in wells safely to avoid an event. In one instance, an overbalanced well lost 200 psi when the pumps were stopped. When flow declined as expected and then unexpectedly began to increase, the rig shut in the well.

The 3 min from stopping the pump to shutting in the well resulted in a 35-bbl kick. Without the ability to see the flow immediately and knowledge to close the BOP, the kick could have caused a major well control event and loss of the rig, an all too common outcome in the area.

In the Asia-Pacific region, where operators have drilled more than 100 MPD wells since 2005, MPD is the preferred technology for mitigating severe lost circulation associated with fractured carbonate formations. Using MPD, rigs now drill safely and efficiently wells that experience kick-loss and near or total-loss scenarios.

For instance, a recent MPD application off India cut the time lost to downhole problems to only 1 day vs. an average of 10 days in offset wells. The Reliance Industries Ltd. well was a vertical high-temperature well drilled to produce a Late Oligocene fractured limestone and carbonate at 7,113-14,193 ft. Reliance decreased the lost time by reducing loss-kick cycles and other flat time associated with narrow pore pressure-fracture gradient margins and increasing penetration rates. The operation minimized fluid losses to 290 bbl of synthetic oil-based mud compared to previous losses of up to 4,000 bbl.

Rigs also are drilling fractured carbonate reservoirs off Africa with MPD control. In one well, a low bottomhole pressure and H2S gas contributed to mud losses of 1,400 bbl/hr and a low penetration rate. In the well, MPD methods eliminated expensive mud losses, prevented sour gas from reaching the surface, and increased the penetration rate to 220 from 40 ft/day. OGJ

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