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Coiled tubing applications
There are numerous well-intervention applications that are performed using coiled tubing (CT) services.
Advantages of using CT for well intervention
The advantages of CT include:
- Deployment and retrievability while continuously circulating fluids.
- Ability to work with surface pressure present (no need to kill the well).
- Minimized formation damage when operation is performed without killing the well.
- Reduced service time as compared to jointed tubing rigs because the CT string has no connections to make or break.
- Increased personnel safety because of reduced pipe handling needs.
- Highly mobile and compact. Fewer service personnel are needed.
- Existing completion tubulars remaining in place, minimizing replacement expense for tubing and components.
- Ability to perform continuous well-control operations, especially while pipe is in motion. However, there are several disadvantages to CT operations.
- CT is subjected to plastic deformation during bend-cycling operations, causing it to accumulate fatigue damage and reduce service life of the tubing string.
- Only a limited length of CT can be spooled onto a given service reel because of reel transport limitations of height and weight.
- High pressure losses are typical when pumping fluids through CT because of small diameters and long string lengths. Allowable circulation rates through CT are typically low when compared to similar sizes of jointed tubing.
- CT cannot be rotated at the surface to date. However, interest in rotating CT has been high in recent years, and several companies are actively designing equipment that will allow rotating of CT.
Cleaning sand or solids put of a wellbore
The most common CT well-intervention and drilling applications involve issues related to sand cleanouts or solids-transport efficiency. The process of cleaning sand or solids out of a wellbore requires pumping a fluid down into the well, entraining the solids into the wash fluid, and subsequently carrying the solids to the surface. In most cases, the wash fluids and solids are captured in surface return tanks with sufficient volume to allow the solids to settle out of the fluid. Where practical, the cleanout fluids are recirculated in the wellbore, thereby optimizing the cleanout program economics. One of the most important concerns in designing a solids cleanout program is the correct selection of the circulated fluid system. An overview of the two types of cleanout fluids used in CT services, categorized as “compressible” and “incompressible,” is offered next.
Incompressible cleanout fluids
Incompressible cleanout fluids are, for this discussion, limited to aqueous and hydrocarbon liquids. This type of cleanout program is the less complicated of the two categories. The cleanout fluid selected should be one that provides for solids removal in a “piston displacement” manner.
The desired cleanout fluid is one that adequately transports solids out of the annulus. If circulation pump rates achieve annular velocities sufficient to exceed the terminal particle settling velocity, then Newtonian fluids can be used. Depending on the CT outside diameter (OD) size, Newtonian fluids are generally adequate when performing a cleanout inside of production tubing. However, when circulating cleanout fluids within large-inside diameter (ID) bore tubing or casing, the reduced annular velocities are typically insufficient to transport the solids out of the wellbore. In these cases, the cleanout fluid should be gelled to a higher viscosity. The non-Newtonian fluids used in this situation are generally sheared biopolymer gels or gelled oil systems.
Compressible cleanout fluids
Compressible fluid cleanout programs are more difficult to design and implement than incompressible fluid cleanout programs. Compressible fluids incorporate various fractions of gas in their composition and are selected to compensate for underpressured formations or where liquid cleanout fluid annular velocities are insufficient to lift solids. Fluid volumes change relative to temperature and pressure in a compressible system; therefore, the annular velocities of these fluid returns do not travel at the same rates throughout the length of the annulus.
Once circulation is established in a compressible fluid cleanout program, unit volumes of fluid are pumped down the CT at pressures needed to overcome the total system friction pressure losses. In this condition, the compressible fluid is experiencing high pressure and occupies minimal volume. As the unit volume of compressible fluid exits the end of the CT, it begins its rise in the annulus. The decreasing hydrostatic pressure of the fluid in the annulus, coupled with a reduction in system friction pressure loss, allows the gas within the fluid to expand. The expanding gas within the fluid causes the velocity of the unit volume to increase. The expansion of the compressible fluid and subsequent increase in unit volume velocity creates an environment of high frictional pressure losses.
As a result, annular velocities and solids removal capabilities require complex mathematical calculations to predict. In these cases, it is recommended to obtain computer-generated cleanout-program predictions from the CT service companies to evaluate the performance of a compressible fluid procedure. The fluids that fall under the compressible fluid category are dry nitrogen and foam (aqueous or oil-based).
Nitrogen is an inert gas and, therefore, cannot react with hydrocarbons to form a combustible mixture. In addition, nitrogen is only slightly soluble in water and other liquids that allow it to remain in bubble form when commingled with wash liquids. Nitrogen is a nontoxic, colorless, and odorless gas that is typically brought to location in liquid form in cryogenic bottles at temperatures below –320°F.
The liquid nitrogen is pumped through a triple-stage cryogenic pump at a specified rate into an expansion chamber that allows the nitrogen to absorb heat from the environment and vaporize into a dry gas. The gas is then displaced out of the expansion chamber and into the treatment piping at the required surface pressure to perform the prescribed job.
Although crogenic nitrogen does not contain oxygen, several other nitrogen sources such as pulse swing adsorption or membrane units can contain significant percentages of oxygen. This oxygen content can exceed 3% and represents a potential corrosion problem in some applications such as CT drilling.
In completed wellbores that are critically underpressured or liquid-sensitive, nitrogen pumped at high rates can be used to transport solids up the annulus and out of the wellbore. The solids-removal mechanism within the wellbore is directly dependent upon the annular velocity of the nitrogen returns. If the nitrogen pump rate is interrupted during the cleanout program, all solids being transported up the annulus will immediately fall back. Of equal concern are the tremendous erosional effects on the production tube, CT, and surface flow tee or flow cross that will occur at the rates needed to maintain solids transport up the annulus. Because of the difficulty to safely execute this type of cleanout program, solids removal programs using nitrogen should be considered as a “last resort” option.
Foam may be defined as a fluid that is an emulsion of gas and liquid. For this discussion, the liquid can be aqueous or oil-based, but the gas will always be nitrogen. In a stable foam, the liquid is the continuous phase, and the nitrogen is the discontinuous phase. In order to homogeneously disperse the nitrogen gas into the cleanout liquid, a small amount of surfactant is used to reduce the surface tension and create a “wet” liquid phase. The surfactant is usually mixed into the liquid phase in concentrations ranging from 1 to 5% of liquid volume. The “wet” liquid is then pumped down the treatment line and commingled with nitrogen in a “foam generating tee.” The turbulent action created by the nitrogen intermixing with the “wet” liquid provides sufficient dispersion for the formation of a homogeneous, emulsified fluid.
Foam is generally selected as the preferred fluid media when performing solids removal programs in underpressured wellbores. Foam can be generated in hydrostatic pressure gradients ranging from 0.350 psi/ft through 0.057 psi/ft, depending upon the wellbore pressures and temperatures. The rheology of stable foam most closely resembles that of a Bingham plastic fluid, where the yield stress must be overcome to initiate movement of the fluid.
The industry-accepted term for describing the volumetric gas content of a foam fluid regime is “quality,” which is arithmetically defined as
A stable foam regime possesses two significantly unique wash-fluid properties. The first is a solids suspension capability as high as 10 times that of liquids or gels. The second is the ability to act as a diverting system, withstanding up to 1,000 psig applied pressure with a minimal loss of wash fluids to the completion. However, if the foam quality exceeds the stable regime limits, the solids-suspension characteristics of the foam are reduced. At this point, the gas in the foam has expanded significantly, and the velocity of the gas in the annulus is maintaining suspension of the solids particles.
Note that because foam is compressible, the quality of this fluid regime is temperature- and pressure-dependent. As a result, the quality of the system is not uniform throughout the entire wellbore annulus. At surface treatment temperatures and pressures, the foam regime occupies a specific volume, thus defining the initial quality of the system. As the unit volume of foam is pumped down the CT and back up the annulus, the total frictional pressure loss acting against this unit volume decreases. Along with the reduction in annular hydrostatic pressure, the nitrogen gas in the foam expands as it approaches the surface. The result is a dynamic profile of foam quality in which the effects of friction pressure losses, viscosity, and fluid velocity are in constant flux.
Underbalance and overbalance pressure conditions
Where CT solids-cleanout services are performed to re-establish communication with an open completion interval, it is a common practice to underbalance the pressure within the annular fluid system relative to the bottomhole pressure. This minimizes the loss of circulated cleanout fluids to the formation and the damage associated with deposited solids. As the annular fluid velocities increase, the frictional pressure loss and equivalent hydrostatic pressure acting against the open formation correspondingly increase. If the formation is open to take fluids, then the volume of cleanout fluids returning to the surface decreases to a rate that maintains the proper balance of friction pressure and annular hydrostatic pressure acting on the open completion.
If the cleanout fluid was designed to hydrostatically balance the bottomhole completion pressure, then any additional pressure applied to the circulating system will cause an overbalance condition to occur. If the formation is highly permeable, then it is likely that a portion of the circulated cleanout fluids will be lost to the open completion once communication with the wash system is established. In effect, if the wellbore circulating system is balanced at a specific rate, the incremental increase in surface pump rate intended to increase circulation rates will most likely be diverted into the completion.
Note that the annular pressure losses because of friction for the circulating system are for “clean” circulated fluids. If the solids concentration within the cleanout fluids are maintained below 2 ppg, the effect of frictional pressure loss because of an increase in solids concentration in the annular wash fluids is considered to be minimal. However, a cleanout-fluid solids concentration in excess of 2 ppg is likely to cause a change in fluid rheology and a noticeable increase in annular friction pressure loss.
The rate of penetration of CT into a column of packed solids (wellbore cleanout) or drilled hole, coupled with a constant circulated fluid annular velocity, directly determines the concentration of solids captured within the cleanout fluid. The dispersion of the solids in the fluid media causes an increase in effective weight of the annular returns fluid. As a result, the hydrostatic pressure differential increases between the “clean” fluids pumped down the CT and the “dirty” fluids circulated up the annulus.
Further criteria for selecting a cleanout fluid system
The type of formation fluids produced can also determine the effectiveness of the solids-removal program. In a liquid-producing wellbore (oil and water), the fluids in the wellbore are slightly compressible and can, therefore, support a “piston”-type displacement of the captured solids back up the annulus. If the produced fluid is a gas, then caution must be taken to prepare for “gas influx surges” or lost returns when breaking through sand bridges or drilled gas pockets. In addition, the difference in fluid densities between gas and liquids causes the gas to override the circulated cleanout fluid. When in communication with a permeable gas zone or completion interval, liquids are likely to be lost to the gas zone, regardless of the bottomhole pressure.
When performing a solids removal program in an underpressured oil-producing wellbore with an aqueous foam, precautions must be taken for foam degradation when commingled into the oil. The oil rapidly destabilizes the foam regime at the contact interface and breaks down into a gasified, oil/water emulsion. As this gasified oil/water emulsion continues to degenerate and move up the annulus, the solids-laden foam in the returns becomes compromised, and fallback of the solids can occur.
For wellbore cleanout applications, the selection of a wash tool should define the hydrodynamic action of the cleanout program. In other words, the wash tool should provide additional downhole turbulent action as needed. Several wash tools available within the industry are designed with ported jet nozzles for imparting hydraulic energy on packed solids or mechanical assistance in breaking up bridged solids. Many times, these wash tools can be constructed to serve as mandrel bypass tools, further extending their utility. Depending on the number and size of nozzle ports, along with the cleanout fluid system selected, frictional pressure losses can be significant.
Implementing the cleanout program
With the evaluation of the aforementioned criteria for selecting a cleanout fluid system completed, the cleanout program can be implemented using either the “conventional-circulation” or “reverse-circulation” techniques. These two techniques are discussed next.
Conventional circulation is the process of pumping a fluid down the CT and allowing the fluid to travel back up the wellbore annulus to the surface. Conventional circulation is by far the most common CT service technique used for removing solids out of wellbores. Along with all of the aforementioned criteria used to determine the cleanout fluid system, the maximum tensile stress loads to be placed on the CT string should be estimated to ensure that the loads do not approach the minimum yield rating of the tube.
Both compressible and incompressible fluids can be used with the conventional-circulation cleanout technique. The selection of appropriate CT size depends on the minimum pump rates needed, total circulation system pressure losses, and the minimum yield load rating required to safely retrieve pipe from the wellbore. The use of downhole flow check devices (check valves) and ported wash tools should not inhibit the intended execution of conventional circulation wash programs.
Reverse circulation is the process of pumping the “clean” circulated fluid down the concentric tube annulus and forcing the “dirty” fluids to travel up the CT ID to the surface. In general, reverse-circulating solids cleanout programs are used where annular velocities are insufficient to lift solids out of normally pressured or geopressured wellbores. The cleanout program is designed to pump the clean fluids down the tubing annulus and use the higher fluid velocities within the CT to lift the solids out of the wellbore. This technique is more complicated to plan and execute than the conventional circulation cleanout program.
The planning of a reverse-circulation cleanout program requires that a minimum effective fluid pump rate be established and the frictional pressure loss through the CT and annulus be calculated for that rate with a high degree of accuracy. Information on the particle size, geometry, adhesive tendencies, and settling velocity must be obtained to ensure that no settling or plugging of the CT string is likely to occur.
In a reverse-circulation cleanout program, the highest pump pressures act against the OD of the CT directly below the stripper assembly. Depending on the amount of differential pressure between the annulus and the CT ID, coupled with the condition of the CT (tensile forces, ovality, wall thickness, etc.), plastic collapse of the coiled tube can occur.
Reverse-circulating cleanout programs are generally limited to incompressible fluid applications. The selection of an appropriate CT string is limited to larger-ID tube sizes that minimize friction pressure losses. However, the larger OD of the CT causes higher annular pressure losses. In addition, reverse-circulating programs cannot be performed with downhole flow check devices or restrictive wash tools installed on the CT string.
In certain wells, CT may be used as the completion tubing. A common use of coiled tubing is as vent strings, especially in low-rate gas wells. In general, the guidelines for jointed tubing should be followed for coiled tubing. The primary difference between coiled tubing and jointed tubing is that coiled tubing bends because it has no jointed connections (there may be a few butt welds).
When used as the permanent well completion tubing, coiled tubing should be designed for the tension, burst, or collapse stresses that typically occur during well operation. With small sizes (< 2 3/8 in.) and relatively thin wall thickness, the overpull allowed will be low, which may be a limiting condition if the tubing becomes stuck or when a packer is used. Collapse pressures will be lowered if the tubing is oval. Care must be taken when tensile loads and collapse pressures are high. Burst rating may need to be reduced for the tubing after several cycles of spooling. Consult with the manufacturers and API RP 5C7. With tapered strings, the design is fixed during the manufacturing to meet the well conditions and, once manufactured, the coiled-tubing design cannot be changed. All coiled tubing is subject to weight-loss corrosion, and plans should be made for corrosion inhibition. (See International standards for tubing.) If thin-wall coiled tubing is used, pitting may result in an early failure of the tube. Because of spooling, which results in exceeding the body-yield strength and changing the steel properties, coiled tubing is not recommended in sour service.
- ↑ RP 5C7, Coiled Tubing Operations in Oil and Gas Well Services, first edition. 2002. Washington, DC: API.
Noteworthy papers in OnePetro
Dong, H., Shi, H., Norris, L.H. et al. 2011. A New Coiled Tubing Application To Enhance Operating Envelope for Deepwater Production. Presented at the SPE Annual Technical Conference and Exhibition, Denver, 30 October–2 November. SPE-147601-MS. http://dx.doi.org/10.2118/147601-MS
Leniek, H., Ayestaran, L., and Yang, Y.S. 2000. Pumping With Coiled Tubing—A New Coiled Tubing Application. Presented at the SPE/ICoTA Coiled Tubing Roundtable, Houston, 5–6 April. SPE-60733-MS. http://dx.doi.org/10.2118/60733-MS