Concentric riser will reduce mud weight margins, improve gas-handling safety

John M. Shaughnessy
Amoco Corp. Houston

Robert P. Herrmann
Consultant Houston

A high-pressure concentric riser, consisting of a surface casing string run within the riser, will have the potential to use a dual-density mud system to reduce mud weight margins, allowing operators to set fewer casing strings in deepwater environments.

An additional benefit includes improved gas-handling safety above the seafloor.

In comparison with the concentric riser system, conventional marine risers are not designed to contain pressure; instead, the serve primarily as a conduit between the seafloor blowout preventer (BOP) and the rig floor.

Issues with well control, gas handling, and well testing are much more easily handled with a pressure riser and a surface BOP. Furthermore, such a setup allows underbalanced or near-balanced drilling from a deepwater floater, which until now, has been restricted by the lack of reliable subsea rotating BOPs (RBOP).

Underbalanced drilling can be used to address the typical deepwater problems arising from low pore-pressure/fracture-gradient margins. Unfortunately, requirements on riser diameter size, rig-time expense, and emergency-disconnect safety issues all work to prevent a straightforward solution to this need.

A proposed solution is to prerun the casing string inside the marine riser and land it in the subsea BOP. The casing temporarily acts as a marine riser. When a surface BOP is rigged up on top of the internal casing "riser," the rig can benefit from some of the advantages enjoyed by fixed rigs.

Developments

The concentric riser arrangement (patent pending) is possible with the latest generation of drillships that have the space and equipment to handle this arrangement. ¹ The greater capacities of the new deepwater rigs enable a high-pressure concentric riser to be deployed without sacrifice of cost or safety.

Transocean's Discoverer Enterprise is an example where advances in design and capacity allow operations normally too slow and costly to execute.²

The rig's 4.8 million lb of tension capacity, 60-ft high substructure, ability to makeup and stand back 125-ft stands of casing, 15,000 bbl of mud storage, and four 2,200-hp mud pumps allow a high-pressure-rated riser (casing string) to be run within the standard 21-in. marine riser without compromising rig performance or safety.

The drilling systems utilized on Shell Offshore Inc.'s tension leg platforms in the Gulf of Mexico also take advantage of a high-pressure riser and surface BOP.³

A low-pressure riser and 3,000-psi-rated surface BOP is used to drill the top hole sections. For deeper drilling, a 10,000-psi surface BOP is rigged up on 113/4-in. casing risers.

The inner riser reduces the pressure requirement for the outer riser, making it lighter and less expensive. The inner riser is replaced on each well. This system results in well control hardware similar to that used on typical platform rigs.

Configuration

Fig. 1 [125,199 bytes] shows the moon pool arrangement of a high-pressure concentric riser. The outer riser consists of a conventional marine riser. The inner string is a standard well casing sized for the bottom-hole assembly.

This internal string is tied back with a pressure connection at the lower marine riser package (LMRP) and provides high-pressure communication directly to the BOP. At the top, in the moonpool, the inner string sticks up through the collapsed slip joint and is rigged with a surface BOP.

The weight of the BOP and internal string is transferred to the outer riser by a load sleeve acting on the top of the collapsed slip-joint inner barrel. Thus, the riser tensioners carry the weight of both inner and outer risers and the surface BOP.

Depending on the mud weight maintained in the annulus between the strings, the tensioners need to develop an excess capacity of up to 700 kips (700,000 lb) above normal operating tension. The inner string is tensioned so that the effective tension is neutral just above the LMRP.

The internal casing is landed in the LMRP by the compensator as shown in Fig. 2 [125,555 bytes]. The bottom is connected to the LMRP, and the compensator load is increased to stretch the string (typically 80 kip/ft of stretch). The top casing joint is outfitted with a load ring. A load shim is placed between this load ring and the top of the slip joint and shimmed as necessary.

The motion compensator then slacks off the load until the load ring reacts with the sleeve, transferring the string tension to the marine riser. At the same time, the riser tension is increased to compensate for this load. Ideally, the tension is such that the neutral point is just above the BOP stack.

At this point, the casing is sticking up through the top of the collapsed slip joint, and the surface BOP can be nippled up. The stick-up length must be long enough to give enough clearance between the stack to the tensioner lines and short enough so that the surface BOP does not hit the bottom of the rig floor when the tensioners retract during a disconnect.

A blooey line is hooked up with a drape hose from the surface stack, and if needed, a mud-return line can be rigged above the stack with a short bell nipple. A low-pressure rotating head atop the bell nipple is required to lift the mud to the return line.

Choke-and-kill lines for the surface BOP would have to utilize 180° hookup points in the substructure in much the same manner as those for the subsea BOP. The substructure height and the excess tensioner capacity for the new 10,000 ft water-depth rigs allow a short BOP to be rigged up on the slip joint without limiting operations resulting from vessel heave.

The concentric riser will be run with seawater in the marine riser. After the hole is displaced with mud, the annular differential will assist in keeping the annulus closed. The top riser tension in 10,000 ft of water with an inner string of 135/8-in. is estimated to be 2.8 million lb. It should be noted that the riser connectors will only encounter 1.9 million lb of tension owing to the compressive load from the inner string reacting on the top of the outer riser.

Safety

The biggest safety issues with pressure risers concerns securing the well in the event of an emergency disconnect. A dynamic positioning (DP) operation requires the capability for the well to be immediately secured and the LMRP disconnected during a drive-off.

Although rare, this can occur at any time. By terminating the high-pressure riser in the LMRP, it is possible to use all of the existing safety procedures for such an emergency disconnect. The inner riser simply becomes an internal part of the marine riser, both acting together when the LMRP is unlatched. This is because the inner riser is positioned above the BOP.

There is nothing inside the stack to interfere with the normal emergency disconnect sequence. The casing string is tied back to the LMRP either by closing the annular preventer, located on a shoe at the bottom of the string, or by using a standard production riser tie-back connector. In the event of an emergency disconnect, the concentric riser will remain latched in the LMRP.

The subsea stack is fully functional and can be used at anytime if the pressure at the surface becomes too great or there is a leak from the inner riser. The subsea choke-and-kill valves could be left open with the rig floor autochoke set at a prescribed level so that pressure within the inner riser remains manageable.

Initially, the time lost in running and retrieving the inner string appears to be a disadvantage of this system. This is especially true if it is necessary to run a full-bore seal-assembly downhole. A liner could of course be set through the inner riser without first recovering the string with commencement of drilling after cementing.

However, because new drilling rigs such as the Discoverer Enterprise can makeup and stand back casing stands out of the critical drilling path, some of this lost time can be avoided.

Moreover, it is possible to eliminate the lost rig time by using the same casing as the next downhole casing string. In this instance, after underreaming to TD, the surface BOP is nippled down, the inner string released, pipe added or removed as needed, and the seal assembly made up.

The casing string is then run to bottom and cemented using a special plug. The high-capacity mud pumps on new deepwater rigs should allow drilling and underreaming at the same time without any problems.

Example application

To illustrate the potential benefits of a concentric riser, consider a well in 6,500 ft of water. After setting 1,500 ft of 20 in. conductor casing and landing the subsea BOP, a 16-in. casing string is run inside the riser.

A 143/4-in. bit and 20-in. underreamer are run together to drill the next interval. A boost pump may not be needed in this case because the annular velocity has increased 180% in the 16-in. casing as compared to the marine riser.

While simultaneously drilling and underreaming, the mud weight is gradually increased to within 0.4 ppg of the shoe test. Drilling parameters are monitored until the pore pressure increases. The high-pressure riser and surface BOP provide many advantages in this situation compared to standard deepwater operations and allow a smaller kick margin.

Some of these advantages include:

• An improved ability to handle gas.
• The ability to circulate out kicks in a conventional manner. This is faster, more efficient, and less complicated than going through a subsea BOP and choke-and-kill lines.
• The absence of gas trapped in the subsea BOP which otherwise would require removal.
• Less potential to form hydrates in the subsea BOP.
• The ability to work pipe while shut-in at the surface BOP. Thus, leaks can be immediately detected and worn elements easily replaced.

After reaching a casing point at 10,000 ft, 3,000 ft of the high-pressure casing riser can be pulled to the surface. At that point, a subsea hanger and seal assembly is made up on to the remaining casing.

Next, the remaining 3,500 ft of casing can be run to TD. It is not necessary to pull and stand back the entire casing string. The shoe joints are designed with landing shoulders to latch on to a cement wiper plug.

The above example results in casing being cemented on bottom faster than conventional floating drilling rigs.

Dual-density gradients

One of the primary advantages of the riserless drilling system is the creation of dual-hydrostatic gradients. During this situation, the hole encounters a seawater gradient above the seafloor and a higher gradient caused by the drilling mud below the sea floor.

The well is actually drilled with a mud weight in excess of formation pore and fracture pressure, yet the dual gradients result in less equivalent hydrostatic pressure being applied to the casing shoe than what is being applied to the bottom of the hole. The fracture pressure at the previous casing shoe is the limiting mud-weight factor allowed in conventional drilling applications.

The high-pressure riser is advantageous for use with a dual density system proposed by Lopes and Bourgoyne.⁴ The authors proposed to inject nitrogen into the mud at the seafloor to reduce the hydrostatic pressure on the formation.

Due to the dual-density gradient, the effective mud gradient at the shoe is less than the effective gradient at the bottom of the hole. A major disadvantage of this method is identifying and controlling a kick. By using a high-pressure riser, kick control is significantly improved because the riser can be controlled at any time.

The effort of utilizing a dual density system may only be justified where an economic incentive exists, such as reserves not being developed without the technology. To illustrate the potential, consider a pore-pressure plot including mud weight and fracture gradient for a deepwater well (Fig. 3 [121,219 bytes]).

A 0.5 ppg margin was assumed between the mud weight at the next casing point and the fracture pressure at the previous shoe. If the high-pressure concentric riser were utilized to allow drilling the top hole clays with little margin, the casing program would be revised. Table 1 [32,297 bytes] summarizes an example well plan.

Running the intermediate casing deeper provides a greater margin when drilling the objective horizons conventionally without the high-pressure riser. Stretching the top hole casing points has more impact in wells where the pore pressure increases more quickly.

The ability to run casing to bottom faster than a conventional floating rig and the potential to push casing to a deeper setting depth are the primary advantages of utilizing the concentric riser.

Additional advantages

There are five additional advantages of using a concentric riser. First, underbalanced drilling applications are beginning to be applied offshore. The primary advantages of this technology include minimized reservoir damage, increased penetration rates, and reduced stuck pipe.

Compared to onshore applications, intervals drilled offshore generally have higher permeability and greater flow potential. The incentive for underbalanced deepwater drilling would be to allow drilling with a reduced margin between pore pressure and the fracture pressure at the last casing shoe.

Underbalanced drilling is beneficial even if limited to nonproducing intervals. The target horizons for considering underbalanced drilling are between 1,500 and 5,000 ft below the mud line. Multiple casing strings can be required in this interval because the difference between fracture gradient and pore pressure can be less than 1 ppg.

Underbalanced drilling on land is sometimes used in cases where surface returns are not possible. A variation of this technique may directly solve the problems from the low pore-pressure/fracture-gradient margins found in deep water.

Second, gas handling at the surface will be greatly improved with a high-pressure concentric riser. Currently, gas in the marine riser must be uncontrollably diverted. A surface BOP on a high-pressure riser allows gas to be circulated out while expansion is controlled.

Third, well testing is another area where a high-pressure riser and surface BOP could improve efficiency. In the event of an emergency riser disconnect, annular pressure in the test string would allow for shut-in at the reservoir and shut-in and disconnect at the seafloor.

For surface drilling systems, a control head (tree) is run above the BOP stack to control the flow. A high-pressure concentric riser allows the well to be tested in a similar manner.

In the event of an emergency disconnect, packers and annular-pressure activated testing valves (APTV) will isolate and secure the well. Next, as the annular pressure is bled off, the APTVs will close and the subsea BOP will cut the tubing string. The subsea test tree can therefore be eliminated.

The reduced time to run the uncomplicated test string offsets the time required to run the high-pressure riser. The riser is run prior to perforating. Thus, the less complicated string reduces the critical-time interval between perforating, testing, and reservoir isolation. The high-pressure riser also reduces the risk of a tubing connection leak above the subsea BOP.

Fourth, well control in deepwater environments presents many problems. Friction losses in choke-and-kill lines aggravate the difficulties encountered with typical low margins between pore-pressure and fracture gradient.⁵ Uncontrolled gas volumes above the subsea BOP can overwhelm surface gas-handling capabilities and pose a safety problem for the rig.

Use of a high-pressure riser and surface BOP can diminish these problems. Gas inside the riser is contained, and the inner pipe can act as a super-diameter choke line, eliminating problems with high friction losses.

Finally, there are benefits of using heavy mud weights. The inner riser arrangement allows drilling with heavier mud than the limit of the marine riser. Up to 20 ppg mud can be accommodated in a 133/8-in. riser without any increase in riser tension.

The weight per foot of 133/8-in. riser filled with 20 ppg mud is less than a 21-in. riser filled with 17 ppg mud. Moreover, the 133/8-in. string also provides structural stiffness lacking in the mud only case. The smaller volume also reduces mud costs.

Operational limitations

There are some operational limitations resulting from use of a high-pressure inner riser, including reductions in allowable vessel offset and heave and undesirable riser loads caused by thermal expansion of the inner string.

In addition, it is not possible to place a high-pressure flex joint in the bottom of the inner casing string. Thus, any angular displacement of the outer string through a flex joint must be taken up by pure bending in the inner string.

For a 133/8-in. string, the lower flex joint angle is limited to around 5°. That limit is within the normal operating window of the rig's dynamic positioning system.

Nevertheless, all of these limitations are manageable and the benefits from use of the pressure riser make for a favorable tradeoff.

References

1. Herrmann, RP, et al., "Concentric Drilling Risers for Ultra Deepwater," SPE/IADC 39297 presented at the SPE/IADC Conference held in Dallas, Mar. 3-6, 1998.
2. Cole, J.C., et al., "Discoverer Enterprise: World's Most Advanced Drilling Unit," SPE/IADC 37659 presented at the SPE/IADC Conference held in Amsterdam, Mar. 4-6, 1997.
3. Denison, E.B., et al., "Mars TLP Drilling and Production Riser Systems," OTC 8514 presented at the Offshore Technology conference held in Houston, May 5-8, 1997.
4. Lopes, C.A., and Bourgoyne, A.T., "Feasibility Study of a dual Density Mud System for Deepwater Drilling Operations," OTC 8465 presented at the Offshore Technology Conference held in Houston, May 5-8, 1997.
5. Actis, Stephen C., "Evaluation of Riser Auxiliary Line Sizes for a New Build Deep Water Drill Ship," Presented at the IADC Deepwater Well Control Conference in Houston, Sept. 15-16, 1997.

The Authors