Options for Coiled Tubing Lift

Coiled tubing is an alternative for artificial lift of aging & problem wells.

by Bert Leniek and Robert Lannom, Zeitecs

Coiled tubing (CT) has been used in oil and gas operations for many years and has proven to be an efficient, reliable and economic tool. The coiled tubing technology has been utilized for drilling, completions, workover, stimulation, and plugging and abandonment work for decades, with considerable success. Coiled tubing for use in artificial lift operations has been somewhat limited, but in the economic environment that exists today, new opportunities have been recognized.

This article focuses on three main segments:

• CT-lift in normal, rod-pumped wells in which sand and scale may be problematic
• CT-lift in monobore wells or where damaged casing may preclude other options
• CT-Lift in gas well deliquification, where the coiled tubing essentially provides lift options both as a velocity string and as a reciprocating pump string to lift liquids that accumulate at the bottom of a well

History and Evolution of CT-Lift Technology

CT-Lift as a form of coiled tubing usage began in 1994 when the idea to use CT as a production string was seen as a possible option to replace sucker rods in oil wells.

At that time, the only known application using CT in artificial lift was to dewater gas wells, using CT for velocity strings.

While developing the idea of using CT as a static production string by the use of hydraulic pulses, the idea developed to use CT reciprocating axially as hollow sucker rods. Both CT applications, one static and one dynamic, have been tested since the late 1990s. While most of the tests showed encouraging results, market conditions delayed further applications. Additional testing and the rising prices of oil during the last couple years have made the commercial application of CT-lift in gas and oil wells attractive.

Lessons Learned

Fatigue analysis based on reciprocating motion, yield of CT material and cross sectional areas, makes it possible to predetermine the life of CT string in given well conditions.

It is also important to maintain compatibility between the internal diameter (ID) of the coiled tubing string and the pump plunger outside diameter (OD). A recent test showed that a minimum difference needs to be observed between the ID and OD, especially in deeper applications.

Transferring fluid from the pump to surface through the ID of the coiled tubing requires compression forces that induce "buckling," especially on the pumping units down stroke.

The buckling effect can be severe and depend on pump plunger diameter, ID of coiled tubing and pump depth.

Experience shows that the most common combination is using 1-¼-inch or 1-1/2-inch OD CT inside 2-7/8-inch production tubing (or 2-7/8-inch casing in the case of slim hole/monobore). Throughout the years, CT-lift has been tested using a wide range of pumping units on surface, ranging from a small D-25 to 114, 456, 640, Rotaflex, to modern hydraulic pumping units.

With existing technologies and materials, CT-lift can be safely deployed to depths up to 6,500 feet. Further testing might increase the limits of the technology. Data regarding CT's ability to remove solids to surface versus standard configuration sucker rods inside production tubing are shown in Figures 1 and 2.

Figure 1. Settling velocity for 2-3/8-inch tubing

 

Figure 2. Settling velocity for 2-7/8-inch tubing

Figures 1 and 2 are developed from the following force balance equation:

Where:
g = 32.2 ft/s^2
gc = 32.2 lbm-ft/ (lbf-ft^2)
  = fluid density
Ad = the area of the tubing/annulus open to flow
V = the settling velocity of the solids in the tubing liquids
CD = the drag coefficient of the solids in the liquids as a function of Reynolds number (The relationship of the CD to Reynolds number is available from fluid dynamics.)

Example

Using Figure 1 and checking for 2-3/8-inch tubing and ¾-inch rods, the settling rate is about 78 barrels per day (bpd) for 30-sieve-size solids. If an end user is pumping below this rate, the solids will not come up the tubing/rod annulus and will stay above the pump, contributing to early failure. Suppose then that, instead, an end user is trying to pump 50 bpd with 2-3/8-inch tubing and 7/8-inch rods, which is below the solids settling velocity or settling rate.  If CT were used with an approximate ID of 1 inch, the velocity required for the 2-3/8-inch tubing and 7/8-inch rods would be:

Area for flow for a 1-inch ID CT = 0.785 square inch

Area for flow between 2-3/8-inch and 7/8-inch rods = 2.533 square inches

V settling = 78 bpd (Area between tubing and rods) in bpd per square inch from Figure 1

V needed = 78 bpd/2.533 bpd per square inch = 30.8 bpd per square inch

V with 58 bpd in 2-3/8-inch tubing and 7/8-inch rods = 58 bpd/2.533 bpd per square inch = 22.98 bpd per square inch

V with 58 bpd in 1-in. CT = 58/0. 785 bpd per square inch = 73.8 bpd per square inch

The velocity in the 1-inch string exceeds the calculated settling velocity. Therefore, the use of CT with 1-inch ID will lift 30-sieve solids up the tubing/rod annulus.

CT-lift with Global Hydraulic system

CT-lift with Weatherford hydraulic pumping unit

CT Lift Three-in-One Solution

The use of CT as pumping string has proven to be a viable solution in artificial lift of fluids in pumping wells. Tests for different applications, such as recovering old wells by converting them into slim holes to be pumped with CT, or dewatering gas wells, proved that CT is suitable to work as a hollow sucker rod string. More recently, an innovation called three-in-one solution presents a new option in the artificial lift field. The idea consists of installing a port at the bottom of CT string that will allow the field operator to treat the well as means of preventive maintenance.

The industry is well aware of the problems caused by sand content, scale and corrosion in rod pumping wells. A stuck pump—caused either by sand or scale—will force downtime and will require the use of an expansive pulling unit to remove and change the pump more frequently.

The use of the pulling unit is the minimum solution to the problem. A more costly solution, in the case of scale or corrosion, will require pulling and replacing the production tubing. When dealing with corrosion, the only possible treatment in a rod pumping well is batch treatment, during which inhibitors are poured downhole arbitrarily.

As explained in Case 1 (see Figure 3), using CT as pumping string with a port at the bottom end of the string, provides the ability to circulate solvents, inhibitors, hot oil or any fluid suitable to treat the well all the way to the top of the pump. A suitable preventive maintenance program will avoid, or at least minimize, downtimes and will extend the life of downhole pumps and tubulars.

Another advantage of this type CT application is the ability to produce fluids to the surface, either as shown in Case 2 (see Figure 4), or through the annular space between CT and the production tubing shown in Case 3 (see Figure 5). Applying either Case 2 or 3, by opening and closing valves on surface, will produce a wash effect, which also contributes to the prevention of premature pump failures and solids settlings.

Figure 3. Case 1.

 

Figure 4. Case 2

 

Figure 5. Case 3

Summary and Conclusions

The use of CT lift offers several options available to operators in today's oil and gas operations, including:

• Use in producing sand and scale particles in pumped fluid, due to increased fluid velocities, reducing particle buildup and the sanding-up of rod-pumped wells
• Options for wells with damaged casing or frequent workovers due to rod problems, pump problems, worn tubing issues, etc.
• Options for alternative well cleanout, chemical circulation and preventive maintenance
• Deliquification of liquid-loaded gas wells, as a pumping method and as a velocity string method to remove fluids from the well and improve production rates and ultimate recovery

About the author:

Bert Leniek has many years of experience in the coiled tubing and oil & gas industry.  He started his career in Argentina with Amoco and worked for many years there before coming to the U.S. with Baker Hughes.  He holds several patents on coiled tubing technology, especially in the area of coiled tubing lift and production operations.  Leniek presently works at Zeitecs, Inc., a Shell Technology Company, and is based in Houston. He can be reached at bert.leniek@zeitecs.com.

Robert Lannom has many years of experience in artificial lift technology and oil & gas industry. He previously held the position of product line manager for Artificial Lift Systems at Baker Hughes-Centrilift and has operator experience from his many years at Chevron. Lannom presently manages sales for U.S. and Canada at Zeitecs, Inc He can be reached at Robert.lannom@zeitecs.com. 

For more information on the CT lift operations discussed in this article, visit www.zeitecs.com.