Hydrocarbon Compression

Archive for the ‘Well Site’ tag

Well Site Soap Sticks

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Equation 5 implies that the lower the density of the liquid accumulating in the tubing, the lower the entrainment velocity. This means that less gas flow is required to keep a well unloaded of liquids, when the liquid density is reduced. Addition of soap sticks to a well is a simple method to reduce the density of liquids in the tubing. Adding soap sticks achieves this objective by causing the water to turn to froth. The soap sticks are approximately 18 in. long by 1 1/2 in. in diameter and consist simply of soap. They are dropped down the well by placing them into the wellhead tree between the two master valves on the vertical section of the tree. A typical rate of soap-stick addition is two sticks every four days.

Two different types of soap sticks are available: A hydrocarbon soluble stick for removing naphtha-i.e., natural gas condensate from the tubing and a corresponding water-soluble stick. Using both types in conjunction is often an effective means of stimulating gas flow. Note: Hydrocarbon-soluble sticks may create an emulsion in the naphtha that may subsequently have to be chemically treated in order to sell the condensate.

Improper and excessive use of soap sticks can damage the gas bearing sand formation. Dropping sticks into a shut-in well and permitting the soapy solution to permeate back through the perforations in the casing should be avoided. Also, the froth carried out of a well after soap sticking may over-load the high pressure separator and result in the entrainment of liquid to down stream equipment. This can be an especially troublesome problem when compressors are located downstream of wells being soap sticked.

Often the most cost effective method to unload wells is to increase the velocity of gas flowing through the tubing by reducing the wellhead pressure. For example, if the wellhead pressure is reduced from 315 psig (i.e. 330 psig) down to 150 psig (i.e. 165 psig), the velocity in the tubing string will double. However, according to Equation 5. VE, the entrainment velocity, will also increase by 41%. This occurs because halving the pressure also halves Pv, the vapor density, and this increases VE by the [math]sqrt{2}[/math] The sum of these effects is to reduce the SCFD of natural gas required to exceed the entrainment velocity by 30%, when the wellhead pressure is halved. The most cost effective method to cut the wellhead pressure is to install a small, reciprocating, gas engine driven compressor at the well-site down stream of the high pressure separator.

Written by Jack

October 4th, 2009 at 6:37 am

Posted in Liquid Loading

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Well Site Problem With Use Of Intermitters

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The valve trim on the intermitter should be at least twice the diameter of the choke. When the intermitter valve opens it should not restrict gas flow from the well. Unfortunately, if the wellhead pressure builds to an excessive level, the sudden surge in gas flow when the intermitter opens may have two detrimental effects:

1. The flow recorder may be over-ranged to such an extent that it is damaged.
2. The high pressure separator may fill with liquid so rapidly that the dump valve may not be able to drain liquid down fast enough to prevent liquid carry-over into the instrument gas bottle shown in
Figure 1-3.

Ordinarily, the intermitter motor valve is controlled by a timer (Electronic digital timers with a variety of built-in. computer features are now available). The well may be set to flow on a 24 hour open/12 hour shut-in cycle. To prevent the problems described above, a highpressure over-ride is set to open the motor valve when the pressure build-up is more rapid than anticipated. The electronic timer mentioned above already incorporates this pressure over-ride feature.

 Well Site Problem With Use Of Intermitters

The optimum time intervals for cycling between opening and closing the motor valve are learned from experimenting on individual wells. Once experience has shown that a well begins to load up with liquids after free flowing for 28 hours, the intermitter controller should be set to shut the well in for pressure build up after 30 hours of production.

Written by Jack

October 4th, 2009 at 6:28 am

Posted in Liquid Loading

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Keeping Gas Wells Unloaded

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Mr. Howlaway eyed my equations suspiciously, “I can see that you have developed a method to predict the combination of the gas production rate and wellhead pressure necessary to keep my wells from loading -up with liquid. But suppose the production rate that the reservoir can support is too low, or the wellhead pressure is too high to achieve the minimum entrainment velocity. What should I do about that?”

Of course, there were a wide variety of answers to Mr. Howlaway’s question. Major industries have been created to assist gas producers to keep wells from loading up with liquids. Gas lift Mandrels and plunger lift systems are just two of the many gas lift downhole methods commonly employed to remove liquids from gas wells. However, as far as retrofitting low pressure wells at the surface is concerned, the simplest most cost effective means to remove accumulated liquids from a well is an “Intermitter.”

Figure 1-3 illustrates a typical Intermitter installation. A motor on-off valve located downstream of the high pressure separator alternately shuts-in and opens-up flow from the well. Wellhead pressure is allowed to build to several hundred psig above the pressure in the gas collection lateral. When the intermitter motor valve springs open, the sudden release in pressure creates a surge in gas flow through the tubing string. The accelerating gas flow reaches and surpasses the entrainment velocity, and the well is thus unloaded.

 Keeping Gas Wells Unloaded

Written by Jack

October 3rd, 2009 at 8:24 am

Posted in Liquid Loading

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