Dual-gradient drilling methods have been proposed as a means to provide simpler, safer, more economic well designs and therefore increase the ultimate development and utilization of deepwater gas resources. Two dual-density drilling concepts — riser dilution
with a low-density liquid and riser gas lift — were investigated as potential means to implement a dual-gradient system. The overall objective was to establish whether further research concerning dual-density drilling systems based on use of low-density fluids, either liquid or gas, is justified. The investigation focused on several critical questions:
• What is the probable cost-benefit relationship for each?
• Can effective well control methods can be defined?
• Can the low-density and high-density components of the mixed fluid that returns to the surface in the riser be separated for reuse?

The cost reduction when using a riser gas lift approach was estimated to be at least 9%, and

Well pressure with riser gas lift using 16 ppg mud at 5,000 ft (1,524 m) water depth.
most likely 17% to 24%, vs. estimated trouble-free costs for conventional drilling of three example wells selected to represent future deepwater Gulf of Mexico operations. In addition, riser gas lift also increased the feasibility of drilling deep wells in deep water that might otherwise be impossible. Well control with a riser gas lift system also was found to be feasible when using methods generally analogous to conventional operations. Riser dilution using liquids was estimated to reduce costs vs. conventional operations by 7% for the example studied. The practicality of separating and reusing mud returning from the riser for a liquid dilution system was only partially investigated. However, results from this work and that done by de Boer (2003) indicate mud separation and reuse in a riser dilution system is possible.

Even though wells have been drilled in water as deep as 10,000 ft (3,048 m), the riser inside diameter can severely limit the number of casing strings that can be used and consequently the maximum practical well depth when conventional well designs are used. These limits become more severe with increasing water depth. An example of a conventional well design for a 24,000-ft (7,135-m) well in 10,000 ft of water is shown in Figure 1. Use of a single mud density from the well bottom to the surface results in wellbore pressures that can only be contained over a short distance of drilling without setting casing and increasing the mud density. An example interval is labeled “constant mud weight from surface” in Figure 1. The result in this case is that eight casing strings ranging in size from 20 in. to 3 1/2 in. are required to reach and set casing at the total depth of 24,000 ft.

Specific geologic conditions such as long salt intervals or more costly well equipment such as expandable tubulars can offset the limitations on maximum practical depth or casing size at total depth (TD). Nevertheless, some deepwater resources will be left unexplored or undeveloped because the current well design technology is too limited or costly to be economically feasible.

A simpler, potentially more cost-effective well design would use a moderate density fluid in the annulus of the riser and a higher density fluid in the well bore to provide a pressure profile in the well closer to what naturally exists in the subsurface formations. The drilling system that would allow these two different fluid gradients in the well has been called the dual-density or dual-gradient system. An example of how the fluid gradients and casing points in this kind of well design would correspond with formation pressure gradients is provided in Figure 2.

The water depth, well depth, pore pressures and fracture pressures in Figure 2 are the same as in Figure 1. However, use of a higher density fluid in the well bore and a lower fluid density in the riser give wellbore pressures that only require three casing strings to reach and set casing at TD. In this case, the casing at TD could easily be 9.625 in., which would allow economic well production rates that would be impossible with the 3 1/2-in. casing in the conventional design. Ultimately, the dual-density well design has the advantages of fewer casing strings for lower well cost, larger mud weight margins for improved safety, a larger production casing size for increased production and reduced riser tension requirements that would allow longer risers to be used with existing tensioning systems.

Several industry projects have been conducted to address the potential of the dual-gradient concept. However, none of these systems has reached commercial application, and the riser gas lift and liquid dilution methods have received less attention than the pump-based systems even though they potentially require less rig modification and initial investment to put into service.

Project description

The overall objective of this project was to establish whether more comprehensive research concerning dual-density drilling systems based on use of low-density fluids, either liquid or gas, is justified. The project was intended to continue the research initiated by Louisiana State University and Petrobras on the riser gas lift method and begin assessing injection of unweighted liquid into the riser as another alternative. These methods are intended to offer alternative methods of achieving a dual-gradient deepwater drilling system that use more standard equipment than the separate industry projects focused on the use of seafloor pumps to achieve the advantages of a dual-gradient method.

The focus of the project has been to evaluate and develop the operational concepts for two dual-density methods that can be applied using current riser-supported subsea drilling systems: riser gas lift and injection of an unweighted liquid into the base of the riser to dilute the wellbore fluids entering the riser. The results are intended to provide a first step toward answering critical questions about the practical feasibility and commerciality of these systems.

The primary business question is what the probable cost-benefit relationship would be for
Simulation of bottomhole pressure and formation flow rate during well control.
each of the two alternative concepts if applied to deepwater Gulf of Mexico development and exploratory wells. This question was addressed by applying dual-density design concepts to three representative deepwater well designs and considering the cost impacts of the different designs and rig equipment requirements. The principle technical question is whether an effective well control method can be defined for a system containing so many different density fluids and flow paths. This question was addressed primarily by simulating well control operations for representative situations using a transient multiphase flow simulator. An additional concern is the practicality of separating the mixed fluid that returns to the surface into low-density and high-density flow streams for reuse. This concern was addressed by studying lab formulations of candidate mud systems as well as using a lab centrifuge and a hydroclone to separate a riser mud into low-density and high-density flow streams to be used as dilution fluid and wellbore fluid respectively.

Riser gas lift

The conceptual feasibility of riser gas lift is dependent on achieving a significantly lower effective density in the riser than in the well. Figure 3 shows the result of one study demonstrating the feasibility of achieving a wellhead pressure equivalent to the seawater hydrostatic pressure over a range of circulating rates with 16 ppg mud in a 19 1/4-in. inside-diameter riser in 5,000 ft (1,524 m) of water.

A primary concern was whether an effective well control method could be defined for a system containing the many different density fluids and different flow paths inherent with a riser gas-lift system. The specific concerns addressed were kick detection, cessation of formation feed-in and removal of kick fluids with a constant bottomhole pressure method. These concerns were studied using a transient multiphase simulator. The validity of using the simulator to study this system was confirmed by comparison to transient multiphase flow data from a test well.

Conventional kick detection methods relying on the pit gain and return flow rate were concluded to be effective. However, a flow check to determine if a kick is in progress is not possible. Two alternatives for stopping formation flow were considered, a “load-up” method of reducing the nitrogen rate vs. closing a subsea blowout preventer (BOP). BOP closure was shown to be faster and more reliable for stopping flow and minimizing kick volume.

Figure 4 shows the results from an example simulation of well control with riser gas lift. In this case, the well was shut in with the BOP, and then the kick fluids were circulated out through the choke line and a surface choke using essentially conventional methods. Based on simulations like this of several different alternatives, it was concluded that methods using a choke with returns up the choke line were simpler and more effective than alternatives with returns up the riser and using nitrogen rate adjustments to control wellbore pressure.
Bottomhole pressure was maintained relatively constant, using only choke adjustments and no variation in the nitrogen injection rate, which should indicate that successful well control in the field would be relatively straightforward.

However, the variation in bottomhole pressure was larger than typically desired, for two reasons: 1) There is always a gas phase in the choke line, which makes the effect of a surface choke pressure adjustment less predictable than for a system that has liquid in the choke lines (Using a remote-controlled seafloor choke upstream of the choke line could alleviate this); and 2) The simulator runs only in a batch mode, which prevents simple or quick correction of choke pressure and requires rerunning the simulation each time a wrong adjustment in choke pressure is made. Consequently, it is difficult and time-consuming to get simulations with exactly the desired results, and those shown were deemed acceptable for the purpose of showing system feasibility.

There are some differences vs. conventional well control. Nitrogen injection into the base of the choke line lowers wellhead pressure, which alleviates the concerns relating to excessive bottomhole pressure because of choke line friction that occurs in conventional well control. One additional item of equipment vs. that in a conventional system also would be desirable. Use of a drillstring valve that has been developed for use with the subsea mudlift drilling system would prevent excessive bottomhole pressure when the well is on choke and the drillstring filled with heavy wellbore mud.

Conclusion

Riser gas lift is operationally feasible. Overall, well control with a riser gas-lift approach to dual-density drilling should be practical using essentially conventional methods.