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De-Watering Technologies
Showcased
by
Karl Lang, Hart/IRI Fuels Information Services
Excerpts in PTTC
Network News, 1st Quarter 2003
De-watering gas wells was the topic of a workshop held March 3-4 in Denver. Nearly 250 attendees listened to 33 presentations focused on various approaches to the problem of economically optimizing production from gas wells by minimizing the effects of liquid loading. The "Gas Well De-Watering Workshop" was organized and implemented by the Artificial Lift R&D Council
(ALRDC), together with the American Society of Mechanical Engineers
(ASME), the Southwestern Petroleum Short Course (SWPSC) and Texas Tech University - Dept. of Petroleum Engineering
(TTU). While space limitations do not permit us to discuss all of the papers individually, we have selected three topics on which to comment from the wealth of excellent material presented. The complete list of papers is available at
www.wellanalysis.com. Copies of the actual presentations, currently available online for attendees only, may be made available to the general public at a later date at a cost.
Plunger Lift with the Pacemaker Plunger
Plunger lift, a technology widely used to remove liquids from gas wells, was the subject of six papers. Two of these dealt with the Pacemaker plunger, a new approach to this traditional method of artificial lift. Traditional plunger lift requires shut-in time for the plunger to fall back to the bottom of the tubing and then for the buildup of pressure to drive the plunger back to the surface.
This shut-in time results both in lost production and in the forcing of liquids back into the formation. The Pacemaker plunger operates as two interdependent pieces (a piston and a ball), each of which fall separately and are designed to do so against a significant rate of upward gas flow
(Figure 1). Once on bottom, the ball seals off in a cavity in the piston. Once the gas flow has driven both back to the surface a rod in the lubricator separates the ball from the piston, enabling the next cycle to begin. The result is that only 5-10 seconds of shut-in time per cycle is required and liquids are not forced back into the formation.
Figure 1—Different Size and Materials Pacemaker Plungers
A presentation by ChevronTexaco's Robert Lestz described the results of Pacemaker installations in a variety of Texas locations. In West Texas, a group of ten wells showed a total increment of 1200 Mcfd after conversion to the Pacemaker plunger
(Figure 2). Eight of these wells were
converted from standard plungers and two had been converted from flowing. East and South Texas examples showed even more dramatic results, with some wells showing more than 200% improvement in gas flow rate after installation of the Pacemaker plunger. In cases where soap was being used to improve liquid lifting there were also substantial savings in monthly chemical costs.
Figure 2—Pacemaker Field Test
Normalized Production from All Wells
ChevronTexaco has employed the Pacemaker in a wide variety of well configurations, including: tubing packer completions, open ended tubing, monobore completions (no annulus), and as a replacement for capillary strings and standard plunger lift. These applications have been in sandy environments, in conjunction with single well compression, and even on both sides of a dual completion.
The primary benefit recognized by Lestz is the fact that there is practically no shut-in time. This minimizes production fluctuations and means less interference for wells sharing the same facilities or compression. The longer flow period means more production and production is not squeezed back into the formation. Stabilized production makes reservoir analysis possible.
There are some limitations with this technology. It works best with low line pressure and at gas rates below ~150-200 Mcfd at FTP~ 80+
psia. Very high liquid rates impede the ability of the ball to fall and some problems can be presented if the tubing is set too high, if there are shallow restrictions such as nipples in the tubing string, or if sand production is excessive. Finally, and this is true for any new technology, people must understand that the critical parameters are different than those for a conventional plunger lift installation and be trained to properly set the controller, troubleshoot and optimize.
For vendor information go to
www.mgmwellservice.com
Gas Auger
Plunger lift, a technology widely used to remove liquids from gas wells, was the subject of six papers. Two of these dealt with the Pacemaker plunger, a new approach to this traditional method of artificial lift. Traditional plunger lift requires shut-in time for the plunger to fall back to the bottom
of the tubing and then for the buildup of pressure to drive the plunger back to the surface.
Marathon presented the results of their field testing of their "gas auger" in the Indian Basin field of Eddy County, New Mexico. The gas auger was developed to combat operational difficulties associated with producing free gas with submersible pumping equipment. The primary productive interval at Indian Basin is the U. Pennsylvanian Canyon & Cisco at a depth of 7500'. The reservoir consists of 400-600' of carbonate. There is 6500 ppm H2S in the produced fluids.
Historically, wells in this field exhibit a dramatic increase in water production and an associated sharp decrease in gas production when they start to water out. Many wells flow 3-4 MMcfd before the water encroachment and continue to flow 1-2 MMcfd with only 100-200 Bwpd afterwards. Subsurface electrical pumps are used to produce the wells.
Gas interference is a problem with ESPs for a number of reasons: poor cooling qualities, diminished efficiency and down time. Because gas is produced up the casing-tubing annulus Marathon is forced to run shrouded units and land the pump intakes below the bottom perforations. When gas is the cooling medium between the shroud and motor the motors see higher temperatures and this shortens the life of the motors and seal
components. In the case of some wells the problem was so severe that it was nearly impossible to keep the pumps running much less achieve optimum drawdown. Free gas greatly diminishes pump efficiency. This decreased efficiency means extra HP and more pump stages are required to "pump" the gas. Down time associated with underloads also results from gas interference, leading to lost production. Also, as the gas passes through the pumps the stages, seal, and motor can go into
upthrust. This can destroy pump stages over time and can lead to sudden failure in the seal section.
Marathon tried a number of conventional approaches to dealing with this problem, including shrouds, rotary gas separators, gas anchors, tapered ESP's, and others, before developing the gas auger. The gas auger consists of a section of concentric tubing coupled with a series of external blades that are run below the perforated interval. The blades facilitate the separation of gas from the liquid and the concentric tubing string enables the gas to bypass the ESP more efficiently
(Figure 3).
Figure 3—Gas Auger Installation
Augers have been installed in 13 wells to date: Ten 7" models and three 9 5/8" models. Before and after tubing tests indicate a 75% separation efficiency. Marathon has successfully pulled and rerun 8 auger assemblies (and made some improvements to the installation/pulling procedure along the way). Total BOEPD increase for auger installations is 3393
BOEPD, excluding proactive installations in new drill wells. On two wells, incremental production has totaled 1900 BOEPD from a $16,000 investment. On those two wells alone Marathon recognized savings of $3200/month from decreased HP requirements. The savings from decreased failure frequency is yet to be determined but could be significant.
Chemical Treatments
Chemical treatments have been used to combat liquid loading in gas wells, along with scaling and/or salting problems, for many years. Chemical foaming is used to lighten the hydrostatic load, enabling the water to be lifted out by gas pressure. James Archer of
Multi-Chem Group, LLC out of Sonora, TX presented a paper that outlined the critical parameters that should be analyzed before a decision is made to employ, or not to employ, chemical foaming additives.
Application of foaming chemicals has progressed from batch treatments to constant application via concentric capillary tubing. By allowing the chemical injection to take place at the bottom of a well, other problems such as scaling can also be treated. Evaluating the well is crucial to the solution. Selection of a foaming agent is dependent upon condensate ratio, required foam quality and bubble size, presence or lack of an emulsion, and water chemistry. Testing of live fluids is necessary, particularly if additional chemical components are to be included to help prevent corrosion, scale, and salt deposition.
Archer provided three case histories of successful chemical de-watering. The first, a Wilcox well in Webb County, Texas, was producing up tubing at 450 psig making 5 barrels of total fluid per day but not responding well to foaming agents. Sampling and analysis showed that the well was actually producing about 25 to 30% condensate. The well was subsequently batch treated with 5 gallons H2O, and 7 gallons foaming agent, down tubing and casing. An injection pump was then used to pump 8 gallons per day of the selected foaming agent until the
well unloaded. Well went from 90 mcf to 400 mcfd. The pump rate was reduced to 2 gallons per day and a rate of 375 to 400 mcfd was maintained.
A Cotton Valley well in Bienville, Louisiana was flowing up tubing under a packer at 50 mcfd and had to be routinely shut in for pressure buildup and intermittently blown to a tank to unload, losing 2 to 3 days production per week. After analysis, the tubing was perforated just above packer and a foaming agent injected in a 40% solution with 2% KCL water at a rate of 15 gallons per day. Within two days after the foamer was started, the rate was up to 385
mcfd. The injection rate was cut back to 8 gallons per day, while the gas rate continued to climb to 1200
mcfd.
A Wilcox well in DeWitt Co., Texas produced 120
mcfd, 6 barrels of condensate and 8 barrels of brine per day but became plugged with salt every 2 weeks and had to be
treated with fresh water and shut-in for two days in order to return production. After analysis, a continuous injection of a 20% solution of foamer in fresh water down hole through a ¼" capillary string was established at a rate of 1.5 barrels per day. The well responded with a production increase to 720
mcfd. Four months later, it continued to produce approximately 720 mcfd while salting has been non-existent.
The variance in production fluids, condensate ratios, and water make-up, causes various foaming agents to act with varying results. Where complete studies of water, foam testing, and evaluation of fluid dynamics have been conducted, favorable results can be achieved. Using foaming agents to enhance gas well production provides a very cost-effective lift method, often greater than a 6:1 return on investment in equipment and
chemicals.
Author: Author:
Karl Lang, HART Publications. For further information, contact Lance Cole at
lcole@pttc.org.
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