Hydrocarbon Compression

Archive for the ‘Enhance Gas Flow’ Category

Gas Well Birth and Dead

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When a well is completed, it must be cleared of sand before it’s production can be lined up to the collection laterals. This is accomplished by “flowing-back”, or “flaring”, the well. For a typical gas well, this requires venting the tubing to the atmosphere for 3 or 4 days at a typical rate of 5 MMSCFD. To avoid wasting $50,000 worth of natural gas, a portable sand separator may be installed between the wellhead tree and the permanent production equipment. While portable sand separator skids may be rented, a sketch has been provided in figures 2-3A and 2-3B for those producers who may wish to build their own unit.

 Gas Well Birth and Dead

Towards the end of a well’s life, it should probably be placed on an intermittent type operation as described in the previous chapter. This will keep the well from loading up with liquids. As time goes by, the back-pressure from the collection lateral will be too high to permit the entrainment velocity (or flow point) to be achieved when the well is opened-up, even though it has been shut-in for many days. Under such circumstances, the well must be flowed-back to the atmosphere. Addition of a few soap sticks through the wellhead cap twenty minutes prior to venting the well to the atmosphere (really to a pit to contain the brine that will be blown out) is a good procedure. Figure 2-4 illustrates the piping configuration at wellhead required to routinely acomplish the above. It may take 15-30 minutes to successfully blow the brine out of a tubing string. If the procedure is working, the wellhead pressure will climb as the slugs of brine pass up through the flow-back connection. Of course, once a well has declined to this point, installation of wellhead compressor or downhole corrective measures are appropriate.

 Gas Well Birth and Dead

 

Written by Jack

October 10th, 2009 at 5:13 am

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Gas Flow Jet Enjectors

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Figure 2—2 shows how high pressure gas from the tubing side of dual completion can be employed to compress the low pressure casing gas. An ejector, an apparatus in common use in process plants, acts as a compressor without moving parts. The installed cost of the apparatus pictured in figure 2-2, is less than $10,000, and there are no operating costs. Use of an ejector in this service requires that both the tubing pressure and flowing gas volume be much higher than the collection header pressure and the casing gas flow, respectively. Note also, that the ejector must be protected against the errosive sand produced form the well.

Gas leaking into, and pressuring up, the casing of a partially depleted well must be bled down periodically. A W line connecting the casing to the tubing will permit this gas which slowly accumulates  in the annulus to be recovered for sales instead of being vented to the atmosphere.

 Gas Flow Jet Enjectors

Written by Jack

October 4th, 2009 at 9:37 pm

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Dual Completion Gas Wells

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By perforating the casing both below and above the packer, as shown in figure 2-1, a lease operator can produce natural gas from two different zones simultaneously. Thus, a dual completion can double the intiial gas flow from a well. If, as often happens, the formation being drained by the tubing is depleted first, a serious problem arises. If the casing pressure substantially exceeds the tubing pressure, the tubing can collapse and gas flow to the tubing side of the wellhead tree will be restricted. If the casing side formation is first to depressure, an attractive opportunity may develop. A small hole, the size of a button, may be shot into the tubing string just above the packer. The flow of high pressure gas from the tubing into the annular space inside the casing, will act as lift gas. This lift gas will prevent the casing from loading up with liquids and thus surpress gas production. If this “button hole”, is made too large, a restrictive choke may be required on the casing’s gas production. This will probably negate the effect of the lift gas, as the restrictive choke will raise the pressure at the perforations above the packer in the same way as would liquid loading.

 Dual Completion Gas Wells

Written by Jack

October 4th, 2009 at 8:51 pm

Coning Water Into Gas Well

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“Mendoza, this meter is broken”, I complained. “Every time we increase the compressors speed to pull-down the wellhead pressure, the recorded gas flow drops. I just raised the rpm from 375 to 425, and the wellhead pressure fell from 220 PSIG to 15 PSIG. But the metered flow decreased from 180 MSCFD to 150 MSCFD. That’s impossible; the meter must be broken”.

“Yes Sir”, responded Mendoza, “you mentioned the same thing last week about that old well down near the river. But when we checked it out, the flow meter was okay”.

“So you think it’s water again”, I ventured.
Mendoza settled himself comfortably on the trucks tailgate and explained. “Yes Sir, it looks like we’re just sucking water into the well. The harder we suck with the compressor, the more water we bring up”.

“I can see that, but why don’t we increase our gas make too”.
“You know more about these things than I do Sir. But what I’ve been told is that the gas in the reservoir is floating on top of a pool of brine. Once the gas pressure in the reservoir is pretty much reduced, the brine starts working it’s way towards the casing perforations. The lower the pressure at the perforations, the more easily the brine flows up into the gas formation and into the well. That’s called “coning”, because the water is supposed to be flowing up at an angle to the perforations. Once the water enters the production tubing, gas flow from the wellhead always drops off’. “Yes Mendoza, the water rising to the surface interfers with gas production. This happens because of the following:

1. The average density of the fluid inside the subsurface tubing increases.
2. The downhole pressure increases relative to the surface pressure.
3. The pressure difference between the reservoir and the casing is diminished and hence the flow of gas from the sand formation through the casing perforations slows”.

“After all”, I continued, “the rate of natural gas production is really not a direct function of the wellhead pressure. Rather, the controlling variables are really the reservoir pressure and the downhole pressure:

 Coning Water Into Gas Well

“Mr. Lieberman”, interrupted Mendoza, “aren’t you getting off the subject again. What I want to know is what do we do now”. “Suppose we get a sample of water from the high pressure separator”, I answered. “We could get it analyzed for salt. If the salt content of the water is a lot lower than that of the brine produced when the well was first put on line, we can assume that water is leaking around the outside of the casing. A “squeeze-job” (i.e. forcing more cement around the casing) is supposed to correct this problem. But if, as you say, we are promoting water flow (i.e. coneing) from a water zone below the gas bearing sand formation, we had better just slow the wellhead compressor back down to 375 rpm. After all, the flowing water is probably promoting the formation of channels that will make future coneing of brine into the well even worse”.

Written by Jack

October 4th, 2009 at 8:48 pm

Ideas To Enhance Gas Flow

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One of the more puzzling phenomenon I have observed in gas field production happened during my tenure as an operator of wellhead compressors. One would intuitively assume that the faster the wellhead compressor ran, the more gas would be delivered through the sales meter. Normally, as the compressor speed was increased by manually screwing open the governor speed control valve, the compressor suction pressure fell. Of course, this also reduced the wellhead pressure and the gas flow would be expected to increase according to the formula:

 Ideas To Enhance Gas Flow

The above equation is really of little use to the field troubleshooter because C,n and PR are unknown for partially depleted wells. But,the equation does positively indicate that gas flow will never decrease as the wellhead pressure is dropped. Much to my surprise, I began to observe that as I dropped the wellhead pressure by speeding-up the wellhead compressors that:
• 30% of the wells did not exhibit any observable increase in gas flow.
• An additional 10% of the wells actually lost production as the wellhead pressure dropped.

If the reader will consult equation 1, of the previous article, he will note that when wells have relatively high stabilized shut-in pressures, as compared to their flowing wellhead pressure, that the incremental gas flow obtained from a further reduction in the flowing wellhead pressure may be quite small. It transpires that there is another factor which tends to negate the effects of decreased wellhead pressure. This factor is water.

Written by Jack

October 4th, 2009 at 7:46 pm

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