2015Innovating While Drilling®March/April

Going full DGD: New system offers alternative well control approach

Dual-gradient drilling system uses gas in top of riser, heavier mud in well to manage downhole pressures

By Katie Mazerov, Contributing Editor

Figure 1 depicts single-gradient vs basic dual-gradient drilling (DGD). In this illustration, the inflection in the pressure gradient is at the interface, or mud line, between the two fluids.
Figure 1 depicts single-gradient vs basic dual-gradient drilling (DGD). In this illustration, the inflection in the pressure gradient is at the interface, or mud line, between the two fluids.

Dual gradient drilling (DGD), a technique long studied by the offshore drilling industry for downhole pressure management, is no longer defined simply by the use of two fluid gradients in the wellbore or riser. As water and well depths continue to increase, advances in DGD technology need to keep up at a fast pace to address the growing challenges E&P companies face in this high-stakes sector.

DGD has the potential to provide significant economic benefits in deepwater wells, minimizing the need to increase the number of casing strings to reach total depth (TD). As each casing string is added, the borehole becomes smaller, often to the point that the well cannot be produced economically. By better matching the pressure gradient in the well to the natural pore and fracture pressure gradients in the formation, DGD allows each section of the well to be drilled deeper, often enabling operators to drill wells otherwise undrillable.

There are complications with this approach, however. “When drilling in dual-gradient mode, it is possible to extend the open-hole sections and drill past a ‘point of no return,’ where conventional well control methods cannot be used anymore,” explained John H. Cohen, Technology Manager for Enhanced Drilling, developer of the Riserless Mud Recovery (RMR) technology and the EC-Drill managed pressure drilling (MPD) system. “This is because the wellbore can no longer support a column of the heavier-than-conventional DGD fluid back to the surface, a phenomenon that can cause the formation to fracture.”

Whereas in a conventional well control operation, the BOP is closed and the well is circulated out via the choke, in a DGD situation, the drilling fluid may have to be pumped from below the BOP to the surface, he explained. “This complicates the well control process, making early influx/loss detection critically important to keep wellbore pressures low enough to circulate through the subsea pump.”

To address this limitation, Enhanced Drilling is developing a DGD system that offers a new way of dealing with well control. This is being done under a joint industry project with three major operators and the Research Council of Norway’s Demo 2000 program, which provides research support to Norwegian businesses. A field trial was undertaken to determine the functionality of the system to detect early influx/losses, circulate a gas kick from a well in well-control mode and determine how the system performs as gas passes through the pump and choke. Results are expected to be presented at the 2015 IADC/SPE Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition, 13-14 April in Dubai.

The new system, Controlled Mud Pressure (CMP), represents what Mr Cohen calls “full DGD.” It utilizes an improved pump that can withstand higher pressures, along with the ability to tap into the choke line to gain access to the well annulus when the BOP is closed. A line is run from below the BOP to the suction point of the pump on the riser to bring fluids out from below the BOP. A choke on the mud return line at surface controls stand pipe pressure and hence bottomhole pressure as the wellbore fluid starts to expand once the fluid – particularly the gas portion, which expands as the pressure is reduced – is above the pump.

Rather than using two liquid gradients, this approach controls the pressures in the wellbore using gas in the top of the riser and a heavier-than-conventional mud in the well to manage the downhole pressures. The system is an outgrowth of RMR, or a pre-BOP DGD system, meaning it is placed on the well before the BOP is used, Mr Cohen explained.

For the field trial, Enhanced Drilling deployed the EC-Drill system to drill a well on the Troll Field on the Norwegian Continental Shelf in May 2014. The well was then plugged and prepared for a 48-hr controlled testing program, during which five detection and circulation tests were conducted for simulated well control events.

Assessing Risks, Benefits

Figure 2: The “full DGD” system uses Enhanced Drilling’s EC-Drill and Controlled Mud Pressure (CMP) equipment, including a subsea pump module (1) and a modified riser joint (2) with an outlet to the subsea pump module suction. Pressure sensors monitor the riser fluid level and provide input for the control system. The mud return line (4) runs to the rig mud system incorporated in the riser. The CMP bypass line (7) is mounted on a modified riser joint going from a stab-in connection to the riser joint below. The line includes an EC-Drill-controlled valve operated through the control system.
Figure 2: The “full DGD” system uses Enhanced Drilling’s EC-Drill and Controlled Mud Pressure (CMP) equipment, including a subsea pump module (1) and a modified riser joint (2) with an outlet to the subsea pump module suction. Pressure sensors monitor the riser fluid level and provide input for the control system. The mud return line (4) runs to the rig mud system incorporated in the riser. The CMP bypass line (7) is mounted on a modified riser joint going from a stab-in connection to the riser joint below. The line includes an EC-Drill-controlled valve operated through the control system.

The process enabled the multidisciplinary team to determine the capabilities of the system in a controlled environment. It also provided opportunities to assess the benefits and risks of various well control methodologies using DGD. For example, the initial design of the CMP called for implementing a dynamic kill method, whereby the rig pumps are not shut off. The subsea pump speed is reduced to increase the bottomhole pressure to stop the influx. Flow to the pump suction is diverted from above the BOP to below the BOP while the well is closed in as flow continues. The influx is then pumped through the CMP pump.

However, a risk assessment determined that the change from conventional well control to dynamic kill would be a too significant and rapid departure from accepted practices to deploy on a rig and would not meet regulatory requirements. Therefore, the team devised a well control approach closer to the Driller’s Method, whereby the well is shut in and the wellbore pressure is allowed to stabilize. The influx is circulated out using the subsea pump and a choke to control the pressure, Mr Cohen said. “Once the influx is out of the well, we can circulate in a new mud weight that is heavier than the old mud to keep the higher-pressure fluids out of the well.”

Using that basic approach, the team then devised new well control procedures for use with a DGD system, taking into account the complications that result from the drilling fluid in the drill pipe: a column of fluid back to the surface that cannot be allowed to exert a pressure on the wellbore that is too high. To overcome this obstacle, a well control scenario was developed using a drill string control valve to support some of the drilling fluid in the drill string to reduce pressure on the formation. The rig pumps are stopped upon confirmation of an influx, and the BOP is closed to allow the well to achieve equilibrium more quickly, limiting the influx size.

Upon confirmation of a kick and subsequent kick circulation, the subsea CMP pump is changed from constant inlet pressure/variable speed control to constant speed/pressure boost to support the heavy fluid column back to the surface at the end of the circulation process. As in conventional well control, a surface choke controls the standpipe pressure. Along with this primary well control method, the CMP team developed several contingency well control measures in the event of equipment failure or a large influx.

The team devised five tests, each involving the injection of liquids and gases and the detection of influxes and losses. The tests were designed to prove the system’s capability to quickly detect a gas or liquid influx or loss, circulate the influx from the well while holding constant bottomhole pressure, handle background gas and provide a comparison against conventional well control.

“We had to know the system was capable of detecting influxes very quickly,” Mr Cohen said. “Smaller kicks are much easier to circulate out of the well when the pressures are still low and more reasonable to handle. Our first tests were designed to show how quickly we could detect an influx so we could react and keep it small. The same is true for losses, which can be just as problematic.”

Simulating Influxes/Losses

Figure 3: A liquid influx detection test using constant riser pressure showed that the system was able to detect and signal liquid influxes/losses to the CMP operator in less than two minutes. In the case where the influx was not detected, the system had not allowed enough time between tests.
Figure 3: A liquid influx detection test using constant riser pressure showed that the system was able to detect and signal liquid influxes/losses to the CMP operator in less than two minutes. In the case where the influx was not detected, the system had not allowed enough time between tests.

To detect influxes and losses quickly, CMP uses a variety of parameters, including a change in pump performance. When more fluid enters the well, the pump must work harder to handle the additional fluid volume; in the event of losses, the pump does not need to work as hard to return the reduced fluid to the drilling vessel. The riser pressure sensor at the pump suction point also can serve as an early influx/loss detector, as the level in the riser changes until the control system can respond and adjust the pump performance to account for the influx or loss. The CMP control system also measures flow into and out of the well, with the difference in those measurements indicating an influx or loss.

Influxes were created by activating the cement pump and pumping fluid into the wellbore, while losses were simulated by running the cement pump at a specific rate, then cutting it back, Mr Cohen said. The detection tests were done with a reduced riser level and open annular to determine the capability of the system to detect volume imbalances while drilling.

Three circulation tests with increasing amounts of gas injected through the drill string were performed. After the influx was detected, the annular was closed, and the flow was routed from the well through a bypass line to the subsea pump module. A choke in the mud return line throttled the return and was used to directly control bottomhole pressure while circulating gas from the well. The final test allowed gas to migrate into the marine drilling riser with a reduced riser level and open annular.

Tests using the riser pressure sensor showed the system was able to detect and signal liquid influxes/losses to the CMP operator in less than two minutes, often less than a minute. An influx test of 80 L/min showed that both flow out of well and pump performance were early detectors (51 seconds). To prove the system could quickly detect a gas influx, the team conducted the same tests using Nitrogen injected into the standpipe manifold to displace and replace mud in the drill pipe. The influx was detected in less than 30 seconds.

With the pump running at constant speed, the liquid influx was detected using riser pressure directly in less than a minute in most cases. Loss detection with constant riser pressure and constant pump speed showed the same results as the influx tests.

Background Gas Migration

Figure 4: With the pump running at constant speed, the liquid influx was detected using riser pressure directly in less than a minute in most cases. Loss detection with constant riser pressure and constant pump speed showed the same results as the influx tests.
Figure 4: With the pump running at constant speed, the liquid influx was detected using riser pressure directly in less than a minute in most cases. Loss detection with constant riser pressure and constant pump speed showed the same results as the influx tests.

The final test compared conventional well control methods with the CMP system. The conventional approach kept bottomhole pressures at a safe level and circulated the influx from the well about an hour faster than the CMP method. Use of the small auxiliary line combined with crew inexperience are considered the major factors as to why the CMP influx circulation was slower.

The tests also addressed the issue of background gas migration when the subsea pump module is operating, to determine whether the gas would go up the riser or through the pump. Trace amounts of methane gas were injected at a low rate into the drill pipe. While pumping, no methane was detected at the top of the riser. When the fluid level was raised, a small amount of gas was flushed to the surface, and a gas-handler at the top of the riser kept the gas from the drill floor. The test indicated that when the drilling fluid contains high concentrations of methane, gas that collects in the riser needs to be flushed at rates defined by the gas content.

Small nitrogen influxes also were injected into the drill string and pumped downhole. These influxes were circulated up the riser with the BOP open and the rig in drill-ahead mode, with no problems in pump performance or changes in bottomhole pressure.

The field trial proved valuable in showing that well control is manageable with CMP DGD and that the system is capable of detecting a liquid or gas influx early, keeping it small, Mr Cohen noted. A small influx can circulate up the riser using gas-handling equipment. Larger influxes can be circulated out of the well with the BOP closed, but through the subsea pump to keep bottomhole pressures in the window between the pore and fracture pressures. The CMP choke maintains relatively constant stand pipe and bottomhole pressures during influx circulation.

The next field trial phase will involve testing the system in a live well in single-gradient mode. “We’ve shown the system can perform in a controlled environment, in a cased hole under specific circumstances,” Mr Cohen said. “Next, we want to use the system up in an actual open-hole well, but instead of circulating the influx up the choke line as is normally done, we would pump the fluid through the CMP pump. This first test was difficult to arrange as it involved the development of two new drilling technologies, EC-Drill and CMP. Future CMP development should be much simpler as it will involve incremental changes to the commercial EC-Drill system.”

Once commercialized, he said he believes the system will enable deepwater wells to be drilled less expensively and more safely. “Our hope is that this system will enable operators to drill wells that otherwise can’t be drilled in these complex environments.

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