Hydrocarbon Compression

Archive for the ‘Liquid Loading’ Category

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

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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

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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

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Sustaining Entrainment Velocity

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When I first started troubleshooting partially depleted natural gas wells, I often wondered why so many of the hundred odd wells I visited were averaging 200-300 MSCFD. I had expected a more linear distribution between the minimum gas production per well (20 MSCFD). Actually, 30 to 40% of the wells I observed clustered around an average production rate of 250 MSCFD.

Wells with average production rates below 150 MSCFD, all had one factor in common – low wellhead pressure. The lower the wellhead pressure, the greater the velocity developed in the tubing with a given volume of gas. For example, 150 MSCFD of gas flowing at a pressure of 600 psig develops the same velocity as 240 MSCFD flowing at a pressure of 1000 psig. For those readers familiar with Stokes Law:

 Sustaining Entrainment Velocity

One can see that as the density of the liquid droplets decreases, the gas velocity necessary to entrain the droplets also decreases. Hence, one would anticipate that entraining condenate would require a lower velocity than that required to entrain water. Also, dispersing the liquid (i.e. reducing V in equation (4) such as by forming an aerated foam) would also lower the minimum velocity required to entrain liquids. I have observed the flowing gas volume and corresponding wellhead pressure for a dozen odd wells just as they reached their minimum entrainment velocity. That is, the point in time when I could hear repeated slugs of liquid passing through the wellhead tree. Using the tubing inside diameter (see Table 1), I then calculated the minimum or incipient velocity needed to unload liquids from each well. This data was then correlated using the standard relationship for liquid entrainment employed in the chemical process industry:

 Sustaining Entrainment Velocity

Of course, my objective was to derive a value for “K” which I could use to predict with confidence VE for hundreds of other wells. For my data base, I calculated values for “K” ranging from 0.85 to 1.10. The density of brine is about 63 lbs./ft. and condensate is about 42 Ibs./ft. .The gas density is calculated at the wellhead temperature and pressure.

 Sustaining Entrainment Velocity

Equation 5 and the corresponding “K” values were developed for 8-10,000 ft. wells, with wellhead pressures varying between 100 to 500 psig. The liquid phase was always brine and 18 molecular weight natural gas was being produced. The tubing strings were either  2 7/8″ or 2 3/8″ O.D. I do not suggest that one should use any particular “K” value for an individual gas field. The idea is to get out of the office and play with the wells. Then, using Equation 5 as a basis, develop “K” values applicable to one’s own gas field. “VE” is also referred to as the “flowpoint”, and a rather detailed review of this subject has been published.

Written by Jack

October 3rd, 2009 at 7:53 am

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Entrainment Velocity

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A well that produces 100,000 SCFD of gas as a minimum, but periodically reaches a peak production rate of 300,000 SCFD once a day, is continuously loading and unloading liquids. The sequence of events are:

• The velocity of gas flowing up through the tubing is insufficient to entrain liquids out of the tubing to the surface.
• Liquids accumulate (load) in the tubing.
• The weight of liquid increases the pressure differential between the wellhead tree and the bottom of the hole, as per equation 2.
• The gas flow from the well drops, as per equation 3.
• Gas flow continues to bubble-up through the tubing; but at a rate insufficient to entrain liquids out of the tubing.
• The gas pressure inside the tubing at the bottom of the well, and also in the sand formation surrounding the perforations continues to build as the gas flow diminishes.
• At some point, the well reaches a condition of instability. For example, a small reduction in the wellhead pressure due to a downstream pressure reduction causes a small increase in gas flow. This promotes a small amount of liquid unloading from the tubing. The resulting decrease in average fluid density in the tubing drops the bottom hole pressure. Gas is now sucked out of the sand formation, and through the perforations, at an accelerated rate.
• A chain reaction has been set in motion. Accelerated gas flow speeds liquid unloading; which in turn drops the bottom hole pressure, and progressively increases the rate of gas production.

An atomic bomb is detonated by creating a critical mass of plutonium. A gas well is unloaded by reaching the well’s entrainment velocity; a point encountered suddenly and in a dramatic fashion. The sound of slugs of brine and condensate blasting through the wellhead tree and surface equipment is quite audible. Typically, both the wellhead pressure and the gas flow will increase as the slugs of liquid “hit” the surface piping with increasing frequency.

Once the liquid is cleared out of the tubing (this takes 30 minutes to a few hours), the flow stabilizes for several hours and then slips away as the pressure in the sand formation around the casing perforations is dissipated. Once the velocity through the tubing drops below that needed to continue entraining the liquids, gas production drops rapidly, and the cycle, as shown in Figure 1—2 is repeated.

 Entrainment Velocity

Written by Jack

October 3rd, 2009 at 6:58 am

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Well Site Liquid Loading

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Although we have been talking about wellhead pressure (both shut-in and flowing tube), the wellhead pressure is just an indirect indication of the really important parameter-that is, the bottom hole pressure. It is the pressure inside the casing at the level of the perforations that determines gas flow. By lowering a pressure sensing instrument suspended on a wire-line to the proper depth, bottom hole pressures can be directly measured. But this is an expensive and time consuming procedure, and beyond the scope of the options available to the field troubleshooter.

So we do not usually know the actual bottom hole pressure. If we knew the density of the column of fluids (i.e. the mixture of gas, condensate and brine) inside the tubing, we could calculate the bottom pressure as follows:

 Well Site Liquid Loading

It is the difference between the bottom hole pressure (Pp) and the pressure in the surrounding sand formation that determines the rate of gas flow from a well. From equation (2) we can see that the bottom hole pressure will increase as the density (SG) in the tubing rises. This increase in Pp reduces the gas production from the well according to the formula:

 Well Site Liquid Loading

The main point that the troubleshooter must absorb from the preceeding paragraphs is that any increase in the average fluid density in the tubing will surpress gas flow. An increase in this density is always due to the accumulation of condensate and/or brine in the tubing. Unfortunately, there is no way to measure this accumulation. Hence, the troubleshooter cannot really make direct use of equation (3). However, with a little experience, it is possible to determine the approximate effect of liquid loading on many wells.

Written by Jack

October 3rd, 2009 at 6:44 am

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