Hydrocarbon Compression

Archive for the ‘Well Site Troubleshooting’ Category

Wellhead Tagging Bottom

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Rapidly opening the wellhead valves on a high pressure well flowing into a low pressure collection system is a good way to ruin a well when the following two criteria are met:
• The wellhead choke is large.
• The well has been shut-in for a while.

The surge of gas flow resulting from following this procedure may, depending on the producing formation, suck sand out of the formation, through the casing perforations and into the tubing. To determine if sand is indeed covering the perforations, a weighted wire line is lowered through the tubing through a device called a “lubricator”. When the wire line loses tension, the operating personnel at the surface surmise that the weight has “tagged bottoms”. This tagged depth is compared to the well’s completion record to determine if any or all of the casing perforations are submerged in sand. If more than 20% to 30% of the perforations are covered, it is a good idea to wash the well out with a “coil tubing unit”.

The cost to tag bottoms with a wire line unit is only a few thousand dollars. Washing a well clear of sand with a coil tubing unit can cost ten times as much. A coil of tubing — perhaps 10,000 feet long, is lowered into the well. Water and high pressure nitrogen are employed to force the sand out of the bottom of the well and up through the annular space between the tubing and the outside of the coil tubing. It is not uncommon to see gas flow triple, after a well has been relieved of it’s load of accumulated sand.

Prior to placing a compressor on a partially depleted well, it is a good idea to obtain at least a qualitative idea of difference between the shut-in and the flowing wellhead pressure. If this difference is large, then it is far better to check for sand in the tubing than to blindly install the wellhead compressor. Certainly, if sand is covering the casing perforations, it is a waste of time and money to install a wellhead compressor.

Of course, the presence of sand in a relatively young well is indicative of a sloppy operation at some previous occasion. This is especially true if the material being pulled into the tubing is frac sand rather than formation sand. There is no sense pumping frac sand into a formation and then crushing the sand and sucking it out of the formation by over-rapid natural gas production.

The sun, having burned the last trace of moisture from the already parched hills, dipped below the horizon. Mr. Howlaway stared out the window at the reddening sky. “What about the black cow. Is the cow still relevant”.

“Of course. The cow is part of the story too”, I explained. “Men have been shot for leaving gas field gates open. Driving cattle back onto a lease is always relevant to troubleshooting gas production. As for the black cow, when it saw that I meant business; when it understood that I wasn’t leaving until it went back through the gate; it just naturally marched back onto the lease. It was only a matter of time and determination. Sure, the cow is part of the story too”, I concluded.

Written by Jack

October 4th, 2009 at 7:41 pm

Posted in Well Site Troubleshooting

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Why Has Gas Flow Dropped ?

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We are assuming that the reservoir pressure and porosity are adequate — that is, there is a plentiful supply of gas in the ground for the well to draw on. Also, we are assuming that the permeability of the reservoir is sufficient to allow a relatively free flow of gas to the perforations in the casing. (Porosity and pressure are a measure of the amount of gas trapped in the sand formation; permeability is a measure of the resistance of the sand formation to gas flow).

We are concerned in this chapter with factors that interfere with gas flow from the sand formation immediately surrounding the casing perforations up through and into the gas collection header. In this regard then, what is the physical meaning of equation (1) above in the context of our everyday experience?

When the flowing tube pressure (i.e. the wellhead pressure during normal operation) is close to the shut-in pressure, a small reduction in the collection header pressure (with a concurrent drop in the wellhead pressure) causes a substantial increase in gas flow. On the other hand, when the flowing tube pressure at the wellhead is much less than the shut-in pressure, a small reduction in the wellhead pressure will not effect gas flow significantly.

To emphasize this critical concept, note that when wellhead flow is restricted by back pressure from the collection header piping, the shutin and flowing tube pressures will be similar. On the other hand, if gas flow is restricted by a discarded tool stuck 8,000 feet down in the tubing string, then the shut-in and flowing tube pressures will be far apart. Why is this? Because, if the errant tool was removed from the tubing, the shut-in pressure will not be effected, but the wellhead flowing tube pressure would greatly increase (assuming that flow from the well was choked back to maintain constant production).

This leads to an important troubleshooting principal: The first point to establish in troubleshooting a well for lost production is whether the problem is above or below the surface.

Written by Jack

October 3rd, 2009 at 6:38 am

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Increasing Gas Flow at Wellhead

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There are three basic problems which reduce the flow of gas from a well which has a sufficient gas pressure, porosity and permeability in the surrounding sand formation to sustain a much higher production rate:
1. Restriction to flow down hole such as occurs when sand covers the perforations in the casing.
2. Liquid loading of the production tubing with water and natural gasoline condensate.
3. Back-pressure on the wellhead tree caused by such factors as high pressure in the gas collection header piping.

These points can best be understood by referring to Figure 1-1. Simply observing the operation of a well does little to help differentiate the causes of diminished gas production. One of the questions asked by lease operators is how to calculate the incremental gas flow that can be expected from a well due to reduced lateral collection header pressure. The formula used to estimate this increase is:

 Increasing Gas Flow at Wellhead

While P1 and Q1 are known from the current operating data, and the lease operator will be able to estimate P2, (the final wellhead pressure) determining a reasonable value for the shut-in pressure  (P3) and the slope of the wellhead performance curve (n) can be a challenge. After a well has been blocked-in, the pressure on the wellhead will increase for several hours, or even days. The reading  on the wellhead tree pressure gauge after this pressure has stabilized, is termed the shut-in pressure.

There are several problems which interfere with obtaining a true wellhead shut-in pressure. One difficulty is that while one is waiting for the wellhead pressure to stabilize, the lease operator can lose one to three days of production. Or, liquids may be accumulating in the mile or two of tubing between the perforations and the wellhead. If a well accumulates 4,000 feet of condensate in the tubing during a shut-in test, then the wellhead pressure will be surpressed by 1,000 psig. For this case, the observed wellhead shut-in pressure is meaningless. When the well is put back on-line and resumes gas flow, the wellhead pressure will probably increase, rather than decrease! In many instances, the only practical way to determine a shut-in pressure is to search back over production records and find a time when the well was blocked-in for maintenance. Next, check the reported wellhead pressure immediately after  flow from the well was resumed. If the flowing tube (i.e. wellhead) pressure is somewhat lower than the shut-in wellhead pressure, one may assume that a reasonable value for the shut-in pressure has been determined.

The numerical value for (n), the slope of the wellhead performance curve, can often be obtained from the initial performance test run on the well made immediately after completion. Usually (n) varies from .65 to .95. For troubleshooting type approximations, assuming that n = .8 will not introduce much of an error into the predicated increment of gas flow due to a reduction in collection header pressure.

 Increasing Gas Flow at Wellhead

Written by Jack

September 27th, 2009 at 10:46 am

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