Larry S. Adams
Chevron U.S.A. Production Co.
Midland, Tex.
Coiled tubing, set at record depth, significantly reduced costs and posed lower mechanical failure risk for recompleting a gas well in the Delaware basin of West Texas.
Alternative completions such as replacing the existing tubing string with smaller diameter conventional API production tubing was deemed less economical and effective.
The gas well, George M. Shelton No. 2, was recompleted on July 18, 1991, by Chevron U.S.A. Production Co. The gas is produced from the deep, low-pressure Ellenburger formation in the Gomez field (Fig. 1).
The hang-off depth of 20,500 ft set a world record for the deepest permanently installed coiled tubing. The 1-1/2 in. coiled tubing velocity string, run within the existing 4-1/2 and 4 in. tapered production tubing string, consists of seven segments that vary in wall thickness from 0.687 to 0.136 in.
VELOCITY STRINGS
Placing coiled tubing inside a gas well's existing production string reduces flow area, increases flow velocity, and improves the well's ability to unload liquids. These strings provide an economic avenue for continuing production and recovering more reserves from gas wells with liquid loading problems.
Because of improvements in coiled tubing manufacturing, wellhead and downhole accessories, and running equipment, these strings can now be placed at lower depths.
The new wellhead design allows installation of the coiled tubing without shutting in well bore flow. This is done by placing a master control valve between the flow spool and coiled tubing hanger (Fig. 2). The G.M. Shelton No. 2 workover was the first time that the master control valve was used in the lower 48 states.
Pressure through the needle valve in the master control valve forces the element in the master control valve to close on the coiled tubing, much like an annular blowout preventer.
A downhole profile nipple, double check valve, and jetting nozzle were also placed in the string. This downhole equipment permits initial wellhead installation and pulling the coiled tubing in the future without using kill fluids.
The segmented, 1-1/4 in. coiled tubing string has a minimum yield strength of 77,500 to 80,000 lb. The string was reviewed for worst case burst and collapse pressure exposure. The metallurgy was determined to be suitable for the well's downhole environment.
Based on well bore inclination angles and associated azimuths, additional analysis included spring buckling, helical buckling, and pickup and slack-off loading.
G.M. SHELTON NO. 2
The G.M. Shelton No. 2 was completed during 1967 with an absolute open flow potential of 31 MMcfd.
The well produced at a rate of 4.7 MMcfd without showing a major production decline, except for allowable effects.
The well was acidized for the first time since initial completion in October 1989. Production dropped to an average 100 Mcfd. With the aid of a surface intermitter, the well produced only 2 hr/day.
At this marginally economic production rate, about 1.6 bcf of potential gas reserves could be lost.
Test indicated that the well's shut-in bottom hole pressure was approximately 2,200 psi with a 3,500-ft liquid column under flowing conditions.
Production and pressure history from the area indicated that the liquid loading was probably from induced liquids from chemical or other well treatments, or liquid condensation from the gas. Water-influx was probably not a cause.
To remove the liquids, analysis indicated that a continuous production rate of at least 5.3 MMscfd was needed with the existing tubing size.
This critical production rate had not been achieved at any point during the well's productive life.
A review of historical production for the G.M. Shelton No. 2 and immediate offset wells indicated that the average water/gas ratio would stabilize at 1.5 bbl/MMcf after the liquid column and accumulated fluid around the well bore were removed.
ALTERNATIVES
Several alternative solutions for increasing production were analyzed. Adding a compressor to reduce wellhead pressure from 550 psi to 300 psi would generate steady-state flow but in or near a density dominated flow regime. Under this condition, unsteady-state flow would develop again very quickly.
Also, installing a compressor would not help unload the existing liquid column or clean out the sludge in the well bore.
The second alternative of installing a smaller tubing size was eliminated because the estimated cost of $260,000-300,000 was high compared to the $115,000 estimate for using a coiled tubing velocity string. The coiled tubing could also effectively clean out the sludge build-up.
A computer simulation was used to determine:
- The most effective coiled tubing size
- Optimum setting depth
- Incremental production response
- Effects of installing compression in conjunction with coiled tubing.
From this analysis, 1-1/4 in. coiled tubing set at 20,500 ft was selected. It was also determined that upon reaching a flow rate of 800 Mcfd, the well should be produced up the coiled tubing instead of the coiled tubing-tubing annulus. This would maintain continuous liquid unloading.
Analysis also indicated that an incremental 300 Mcfd could be added by reducing flowing wellhead pressure from 530 psi to 250 psi with compression.
WORKOVER
The recompletion consisted of installing the coiled tubing and removing the fluid column and sludge.
Design criteria for the 22,000 ft coiled tubing string allowed for an available overpull above string weight of 10,000 lb and/or a minimum axial loading at or above 60% of each wall segment's load yield.
Post manufacturing specifications for drifting, hydrotesting, nitrogen purging and entrapment, depth marker banding, and spooling were also supplied. A quality assurance inspector verified that all manufacturing and post manufacturing criteria were met.
The wellhead equipment was installed and tested 2 days prior to the arrival of the coiled tubing and running equipment. To prevent scale or rust fouling the check valves, nitrogen was circulated through the coiled tubing.
Next the landing nipple, double check valve, and jet nozzle were installed on the coiled tubing and checked on the surface for proper operation.
Part of the running configuration is an access window (Fig. 3) that allows the placing of slip and packoff assemblies around the coiled tubing.
While running in the hole with the coiled tubing (Fig. 4), N2 at 250-300 scf/min was pumped through the coiled tubing. The N2 ensured that the double check valve was operating properly.
Also, overpull checks, at various depths, ensured that designed overpull limitations were not being reached.
The checks also generated a data base for comparing simulated values to actual values.
From 17,000 to 20,500 ft, the N2 pumping rate ranged from 650 to 950 scf/min. The coiled tubing running speed was set at 26 fpm.
The well was jetted for 13 hr at 20,500 ft with an N2 rate of 650 scf/min. A flare was established at surface, and liquid was unloaded at 7-10 bbl/hr.
Sludge cleanout operations were then initiated by pumping 5 gpm of diesel/600 scf of N2. Build-up was encountered at 21,000 ft and cleaned out to 21,632 ft. Tests found that the most effective coiled tubing setting depth for jetting was at 20,500 ft.
Jetting was maintained for 14 hr with an N2 rate decreasing from 650 to 250 scf/min.
Liquid unloading decreased from 7-10 bbl/hr to 1-3 bbl/hr.
Tests indicated that the well with N2 assistance could produce 1.1 MMcfd while unloading 3 bw/hr. A 5 hr test without N2 indicated an unloading rate of 1.1 Mcfd and 0.4 bw/hr. The backpressure was 80 psi.
After the coiled tubing was hung off, the check valve was blown off (Fig. 5).
Because of wellhead valve failures, the well was shut-in for 36 hr.
After replacing the valves, the well was jetted into production, producing up the coiled tubing against a line pressure of 480 psi.
Since the recompletion, the well has continued to produce at 390 Mcfd, unloading 3-4 bw/d.
ACKNOWLEDGMENTS
The author appreciates the help of Quality Tubing Inc., Precision Tube Technology Inc., Specialty Wellhead & Tool Co., Nowcam Services, and Cudd Pressure Control.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
