2009Completing the WellNovember/December

Monobore completion system provides simple, low-cost option for short-life expectancy wells

Figure 1: Compared with other completion options, the cement-thru single-trip system (right) can provide value for the cost while also maximizing well productivity.
Figure 1: Compared with other completion options, the cement-thru single-trip system (right) can provide value for the cost while also maximizing well productivity.

By Don Ingvardsen and Jim Kritzler, Baker Hughes

Many wells completed today can be classified as short-life or harvest wells. Some of these would not be economically feasible using high-end completion components and methods. Monobore wells can be a solution to this dilemma.

This article will discuss several methods in which monobore well design can save considerable time while lowering the overall completion cost. Results of a pilot program with live gas lift valves in place during cement operations instead of dummy valves are also provided.


Wells with a single production tubing size from the pay zone all the way to the surface of the completion are categorized as a “monobore” completion. Although there are certain limitations to this type of completion, there are also many advantages, including drilling cost and a reduced equipment list (packers, sliding sleeves, etc).

Many wells are not feasible using more traditional completion techniques. But with monobore systems that can reduce rig time and cost while still safely completing the well, these wells can move from the category of unfeasible or marginal to profitable or, in some cases, highly profitable.

One early method involved simply cementing the completion in the wellbore. Later options include staging the cement process to include equipment that would increase the life of the well and ensure its safe operation.

Significant time and effort have been expended to develop a more reliable system for completing these wells and increasing their productivity. Specially designed cement-thru components, including safety valves and gas lift equipment, can be credited with moving these monobore completions to the next level.

Including a reliable safety valve inherently improves production safety, but introducing the gas lift alternative from the beginning has significantly increased overall production capability. Wells that were estimated to produce 500-600 bbl/day were improved to 1,200-1,400 bbl/day. The majority of these completions have been completed in the Gulf of Thailand, but other fields around the world are candidates for this system as well.

This article will explore the components and methods of what have been known in the past as “disposable monobore completions.” For this article, we will refer to them as “mono-trip cement-thru completion” systems, or simply “cement-thru.”

The cement-thru system:

  • Is a true monobore system.
  • Comprises cement-friendly components.
  • Is designed for one-trip deployment.
  • Uses a staged cementing system.
  • Includes pressure cycles throughout the process to verify component integrity.

Figure 1 shows the typical completion that has been used and the estimated cost for each completion type. The conventional completion includes a fully cased wellbore, zonal isolation, conventional (non-cement through) gas lift side pocket mandrels (SPMs) and a safety valve. This is a proven system but is also substantially more costly than any of the other options.

The monobore completion in Figure 1 represents the most basic disposable well completion. It consists of only tubing, cemented in place, and a safety valve. Due to its simplicity, it is the most economical. However, it gives no options to either facilitate unloading the well or maximize the production of the well. Also, the absence of a packer in this design does not allow for remedial work to install any equipment to prolong the life of a well.

When looking at the two-trip gas lift completion, which was used before the creation of the cement-thru system, you see some additional jewelry incorporated in the assembly, including gas lift mandrels. However, the addition of a second trip to complete makes this less appealing in marginal wells. Basically, the lower section is run and cemented, then the upper completion is run and stabbed into the lower section.

Finally, the last illustration shows the cement-thru single-trip system, which maximizes the productivity of the well while providing value for the cost. The equipment from top to bottom in this example includes a CementSafe safety valve, Cement-Thru SPM, HP Defender hydrostatic closed circulating valve (HCCV), hydraulic ZXP packer, and landing collar/shoe track. This kit is designed to tolerate the cementing process without degrading its performance and can be run in half the time of the two-trip system.

Figure 2: Simulations of fluid dynamics were used during the design of the cement-thru system in order to find areas where residual cement could be left behind.
Figure 2: Simulations of fluid dynamics were used during the design of the cement-thru system in order to find areas where residual cement could be left behind.

The design process included extensive fluid dynamic simulations to document the fluid characteristics throughout the completion process (Figure 2). It was critical to know what areas existed where residual cement could be left behind after the cementing process. One of the most critical of those areas was the SPM. Residual cement in certain areas of the SPM could have made it difficult, if not impossible, to change out a gas lift valve or replace a dummy valve with a gas lift valve.

The simulations highlighted the areas where design enhancements were warranted to induce turbulence and allow for self-cleaning of these critical components. Similar design concepts have been used in safety valves to prohibit the accumulation of sand in the valves, and this demonstrated the need for turbulent flow throughout the SPM body.

Rounding out the completion was a packer that could handle the high circulating rates without affecting the element. It uses a zero-extrusion element and no-slip system. Finally, to finish out the completion, a safety valve that is cement-tolerant was added to the system. However, in certain applications, a safety valve may not be required.

Possibly the most important part of this design is the HCCV, whose purpose is to clean excess cement from the annulus, allowing the gas lift portion of the well to be used. Here is a typical completion procedure:

  • Install entire completion into wellbore.
  • Pump cement to approximately 300 ft above packer.
  • Chase wiper plug down to landing collar.
  • Increase pressure to 3,000 psi to set packer.
  • Increase pressure to 4,000 psi to burst rupture disc in HCCV; annulus and tubing are now communicated.
  • Keep circulating until annulus is clean of excess cement.
  • Close in the annulus.
  • Increase pressure to 4,900 psi to shift outer sleeve on HCCV valve closed; annulus and tubing are now isolated.
  • Use running tool to shift up inner sleeve in HCCV, providing secondary seal for annulus and tubing isolation, if desired.
  • Run gas lift valves in appropriate SPM, if desired.
  • Perforate and produce well.

This true monobore single-trip completion can reduce the completion time from approximately 60 hrs to an average of 17 hrs per completion (Figure 3).

The system can provide the following benefits when applied in a true monobore completion:

  • Cemented monobore wells offer an economically viable method of completing wells with life expectancies of three to five years.
  • A significant reduction in rig time and nonproductive time is possible.
  • Adapting this technology can provide completion solutions for enhanced productivity and safety.
  • It can reduce labor hours on the rig floor.
  • Fewer accessory tools and trips can reduce the risk of fishing operations, which can be costly and time-consuming.
  • Life and productivity of the well can be extended with the use of a gas lift system.

Figure 3: Time required per completion can be reduced from 60 hrs to an average of 17 hrs, reducing overall costs to make unfeasible wells feasible.
Figure 3: Time required per completion can be reduced from 60 hrs to an average of 17 hrs, reducing overall costs to make unfeasible wells feasible.


Advances in monobore applications indicate that injectors can benefit from this technology as well. To reduce rig time to complete water injector wells, a true monobore concept has been developed. In particular, the North Sea has adopted a completion method that uses a minimal amount of completion components and uses cement to strengthen the annulus.

An inherent problem in these wells is formation subsidence, which, in many cases, has damaged the casing and rendered the well inoperable. The ability to cement through the tubing string of a true monobore completion can serve as a method to preserve the integrity of the well tubulars but also reduce the amount of rig time required to complete these wells by as many as four days. Typical equipment needed for these wells includes a permanent packer, circulating device and surface-controlled subsurface safety valve.

Gone are the possible leak paths of the polished bore receptacles and seal assemblies that used to be required. Depending on the longevity requirements, this equipment could have been manufactured from exotic material to deliver long-term service in harsh environments. A few things to consider when contemplating this completion style:

  • Formation characteristics: Will the formation support a successful cement program?
  • Completion and cementing procedure that will support the integrity and capabilities of the completion components.
  • Potential longevity of the well based on inherent harsh environments.


Operators continue to strive for a simple low-cost solution for completing these three- to five-year life expectancy wells. Simple tubing-only monobore wells continue to be the mainstay in many areas. Success rates continue to run around 90%, mainly due to the reduced numbers of components in the completion and a simple repeatable completion procedure.

This is not to say that there have not been any issues in the life of this approach to well completions, but they have contributed to our lessons learned and ultimately helped improve the reliability of the system.

The one-trip monobore completion is still the preferred method of completions in the Gulf of Thailand. More than 300 wells have been completed in 2 7/8-in. and 3 ½-in. tubing.

The authors wish to thank Baker Hughes for the permission to publish and present this article.

This article is based on SPE 124797, “Monobore Completion System Provides Low-Cost Completion Option,” copyrighted by SPE and presented at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, La., 4–7 October.

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