Downhole gas compression technique

Abstract

There is disclosed a gas compressor of the jet type positioned downhole in a gas producing well. The inlet of the compressor is exposed to formation fluids comprising natural gas and a liquid, usually water. High pressure natural gas is continuously delivered to a power fluid inlet of the jet compressor. A mixture of the power gas and produced formation fluids are continuously delivered from the high pressure compressor outlet through a production string to the surface at a pressure and volume sufficient to keep the production string unloaded of liquids.

Description

As used herein, the term natural gas indicates any gas occurring in nature in a porous and permeable underground formation. Typically, methane is a dominant component of natural gas although hydrogen sulfide, carbon dioxide and other gases may comprise the bulk of a natural gas. The history of production of a typical natural gas well is basically as follows. Upon initial production of a gas bearing reservoir, the formation pressure is sufficient to move gases existing in the formation as well as liquids existing in the formation into the wellbore. The formation pressure is also sufficient to move the downhole gaseous and liquid components through a production string to the surface. As fluids are produced from the formation, the formation pressure decreases. After production has continued for some time, gas wells typically begin to produce a detectable quantity of water which is known to be liquid in the formation and which is normally saline. At the onset of salt water production, the wellhead pressure begins to drop at a fairly rapid rate which is merely a manifestation of the weight of liquids in the production string since the formation pressure continues to decline at a rate which can be predicted from the quantity of formation fluids produced. Sooner or later, the formation pressure adjacent the wellbore declines to a value which is insufficient to deliver a sufficient gas volume through the production string to produce or unload liquid components therein. Accordingly, these liquid components accumulate in the production string until the weight of the liquid column substantially balances the formation pressure adjacent the borehole whereupon the well dies. The accumulation of formation liquids in the production string is typically attributable to a low linear velocity of fluids in the production string. It is generally believed that formation fluids must flow upwardly through a conventional sized tubing string at about 5-10 feet/second in order to propel liquid droplets upwardly through the tubing string against the effect of gravity. As the pressure drop between the formation adjacent the bore hole and the wellhead declines, the gas volume delivered through the tubing string drops and the linear velocity of gas through the production string declines until liquids begin to accumulate in the production string. As liquids accumulate in the production string, the weight of the fluid column therein increases whereupon the pressure drop between the formation adjacent the bore hole and the wellhead declines. Thus, there is a self-defeating process operating to cease production. The techniques now used to bring such a well back onto production is to drop a "soap" stick into the well to foam the liquids therein and thereby reduce the weight of the fluid column in the production string. By opening and closing the surface valves, a sizeable amount of water can be produced at the surface in the form of a foam which reduces the weight of the liquid column in the production string and allows gas to flow again. Another technique presently used is to swab the production string and mechanically remove part or all of the water contained therein. These two techniques are useful for some time to periodically unload liquids from the production string and thereby get the well back on production. After some time, the mechanics of unloading the well and disposing of the produced salt water becomes onerously expensive when compared to the revenue from the well. At this point, the well has reached its economic limit of production and the well is plugged and abandoned.

It should be no surprise that the economic limit of production of a natural gas well has changed substantially in the last decade. Ten years ago, new gas was bringing $0.15-0.20 per MCF at the wellhead. The price of old gas, which was set at the inception of production, was substantially lower. At that time, it was substantially impossible to renegotiate price.

The price of natural gas at the wellhead crept upwardly until the winter of 1972-73 until it was in the neighborhood of $0.50 per MCF. Because of the drastic imbalance of supply and demand, the price of new gas substantially doubled in the next twelve month period. Price renegotiations are now feasible where one can demonstrate that higher prices are necessary to continue production.

Ten years ago, a well capable of producing 200 MCF per day at $0.10 per MCF and tending to load up and die every few days had to be considered a marginal well, i.e., one that had reached its economic limit. Because of the dramatic increase in the price of natural gas, a well capable of producing 200 MCF per day is far from a marginal well if, in fact, it can be produced continuously for reasonable periods of time.

It is an object of this invention to provide a technique for producing natural gas wells continuously for an economic period of time in which the formation flowing pressure and/or volume is insufficient to keep the production string unloaded of liquid during this period.

This primary objective is accomplished by positioning a gas jet compressor in the production string with the low pressure inlet in communication with the gas bearing formation. Relatively high pressure natural gas is continuously delivered to the power fluid inlet of the compressor. The mixture of the produced formation fluids and the power fluid is continuously withdrawn from the high pressure outlet of the compressor and delivered to the production string. It is known in the prior art to utilize jet eductors or ejectors in conjunction with petroleum producing wells, as shown in U.S. Pat. No. 2,061,865; Journal of Petroleum Technology, April, 1966, pages 419-23; Power and Fluids, Fall 1954, article entitled Gas Jet Compressors; World Oil, Feb. 1, 1957, pages 136, 139-141; and a paper presented at the Southwestern Petroleum Short Course, Department of Petroleum Engineering, Texas Tech University, Lubbock, Tex., on Apr. 26-27, 1973 entitled Jet Free Pump -- A Progress Report on Two Years of Field Performance.

The publications in the Journal of Petroleum Technology, Power and Fluids, and World Oil basically disclose the incorporation of gas jet compressors as surface equipment in gas producing wells utilizing high pressure natural gas as the power fluid. The Southwestern Petroleum Short Course paper discloses a downhole jet pump for moving liquids upwardly through a producing string utilizing high pressure liquid as the power fluid.

The disclosure in U.S. Pat. No. 2,061,865 appears of substantial pertinence since it discloses a downhole eductor utilizing high pressure gas as the power fluid to deliver formation water to the surface. Although this disclosure appears pertinent, it is only superficially so. This technique is basically to separate produced gas from liquid inside the casing string to collect the liquid in the casing string below the producing formation while producing the gas and to periodically pump the liquid out of the casing. This basic technique is now used with a conventional sucker-rod operated pump when the casing provides a significant usable volume below the producing formation. The use of a sucker-rod operated pump allows gas production to continue when liquids are being pumped out.

In summary, this invention comprises the method of substantially continuously producing natural gas at the surface from a well providing a first fluid passage affording communication between an underground formation which gives up both natural gas and a liquid wherein the formation flowing pressure and/or volume is insufficient to continuously flow the gas and liquid through the first passage to the surface, and a second fluid passage extending from a source of natural gas at a second pressure greater than the formation flowing pressure to the formation, the method comprising the steps of (1) continuously delivering natural gas from the source to a power fluid inlet of a gas jet compressor located adjacent the formation; (2) continuously withdrawing natural gas and liquid from the formation and directing the same into a low pressure inlet side of the compressor, a high pressure outlet side of the compressor being in communication with the first passage; (3) continuously withdrawing a mixture of the gases of steps (1) and (2) and the liquid of step (2) from the compressor at a pressure intermediate the formation flowing pressure and the power fluid inlet pressure and at a volume sufficient to overcome the effect of gravity on liquid droplets; (4) continuously passing the mixture upwardly through the first passage to the surface; (5) continuously removing liquid from the mixture at the surface; and (6) continuously delivering at least part of the gas to sales.

IN THE DRAWINGS

FIG. 1 is a schematic view illustrating a gas well equipped to operate in accordance with the principles of this invention;

FIGS. 2A and 2B comprise an enlarged broken longitudinal view of a tool designed in accordance with the principles of this invention;

FIG. 3 is a longitudinal cross sectional view of the tool of FIG. 2B taken substantially along line 3--3 thereof as viewed in the direction indicated by the arrows;

FIG. 4 is a schematic view similar to FIG. 1 illustrating other principles of this invention; and

FIG. 5 is a partial schematic view illustrating another technique of this invention.

Referring to FIG. 1, there is illustrated a typical natural gas producing well 10 having a bore hole 12 extending from the surface 14 through the earth to intersect a porous and permeable gas bearing formation 16. A casing string 18 extends from the surface 14 to adjacent the formation 16 and is bonded to the wall of the bore hole 12 by a cement sheath 20. A plurality of perforations 22 place the formation 16 in communication with the interior of the casing string 18. A packer 24 seals between the interior of the casing string 18 and the exterior of a production or tubing string 26 which extends to the surface 14.

As is conventional, the tubing string 26 comprises a plurality of joints which are connected together by suitable threaded connections. As shown most clearly in FIG. 2B, the lowermost end of the tubing string 26 comprises a seating nipple 28 of any suitable design to be received and held by the packer 24. Threaded onto the upper end of the seating nipple 28 is a collar 30 providing a plurality of transversely extending passages 32 therethrough providing communications between an annulus 34, defined between the casing string 18 and the tubing string 26, and the interior of the tubing string 26. Threaded into the top of the collar 30 is a landing nipple 36 which may be of any suitable design and which is illustrated as providing a latching shoulder or recess 38. It will be evident that the nipples 28, 36 and the collar 30 are illustrated as basically comprising an Otis Type X Side-Door Nipple, as shown on page 3,969 of Otis Engineering Corporation 1975-75 catalogue.

Disposed inside the lower end of the tubing string 26 is a tool 40 designed in accordance with the principles of this invention. The tool 40 comprises a check valve assembly 42 which is illustrated as being of the type manufactured by Otis Engineering Corporation and being more particularly illustrated in the Otis 1974-75 catalogue, page 3,971, but which may be of any type suitable to prevent fluids from flowing downwardly through the production string 26 into the formation 16. The upper end of the check valve assembly 42 includes a threaded sleeve 44 which is secured to a nipple 46 having a passageway 48 therethrough and providing an assembly 50 for sealing between the nipple 46 and the machined interior of the seating nipple 28.

Positioned above the nipple 46 is a gas jet compressor 52 comprising a nozzle section 54 and a throat-diffuser section 56. The nozzle section 54 is threaded into the nipple 46 and provides a low pressure inlet 58 in communication with the formation 16 through the check valve assembly 42. The nozzle section 54 also provides a power fluid inlet 60 in communication through the passages 32 with the annulus 34. Desirably, the power fluid inlet 60 extends generally transverse to the axis of the tool 40 in alignment with the passages 32. The power fluid inlet 60 is in communication with a nozzle 62 which acts to increase the velocity of the power gas and decrease the pressure thereof.

The nozzle 62 is desirably removably attached to the nozzle section 54 to permit interchanging of various sized nozzles. The configuration of the operative surfaces inside the nozzle 62 may be designed in accordance with known engineering principles as discussed in the previously mentioned publications appearing in the Journal of Petroleum Technology, Power and Fluids, and World Oil.

The throat-diffuser section 56 is threaded into the top of the nozzle section 54 and provides a supersonic diffuser surface 64, a throat 66 and a subsonic diffuser surface 68 all aligned with the axis of the nozzle 62. The configuration of the surfaces 64, 66, 68 is in accordance with known technology as set forth in the article appearing in the Journal of Petroleum Technology.

The throat-diffuser section 56 is threaded onto a pup joint 70 which is in turn threaded onto a sleeve 72 carrying an assembly 74 for sealing against the machined interior of the landing nipple 36 as shown in FIG. 2A. The sleeve 72 provides a conical wedging surface 76 for cooperation with a conventional latch assembly 78 comprising a plurality of latch elements 80 suspended by resilient fingers 82 from an axially adjustable collar 84.

Threaded onto the upper end of the sleeve 72 is a stinger 86 having a downwardly facing shoulder 88 thereon. Surrounding the stinger 86 and axially movable therealong is a latch actuator 90 having a collar 92 on the lower end thereof captivated to the collar 84. As will be apparent to those skilled in the art, relative downwardly movement of the latch actuator 90 causes the latch elements 80 to bear against the wedging surface 76 and expand outwardly into load bearing engagement with the latching shoulder 38. Relative downward movement of the stinger 86 causes the wedging surface 76 to retreat from the latch elements 80 allowing the same to retract out of engagement with the latching shoulder 38 thereby freeing the tool 40 for movement inside the landing nipple 36. The latch actuator 90 comprises a shoulder 94 thereon. As will be apparent to those skilled in the art, the upper end of the tool 40 is illustrated as basically an Otis Type N Mandrel as shown in the Otis Engineering Corporation Catalogue, 1974-75, page 3,963. The shoulders 88, 94 allow manipulation of the tool 40 to land and retrieve the same from the nipple 36 in basically the same fashion as an Otis Type N Mandrel.

As previously described, the tool 40 is a wireline tool which is placed in and retrieved from the tubing string 26 in accordance with known techniques. It will be apparent to those skilled in the art that the tool 40 may be incorporated as a section of the tubing string 26. This may be advantageous when completing a well through small size strings, e.g., a 27/8 inch casing string and a 11/2 inch tubing string.

It will be apparent that fluids passing through the throat-diffuser section 56 move upwardly through the tool 40 into the tubing string 26. Referring to FIG. 1, the tubing string 26 is exposed at the surface and is connected to a control valve 96. A flow line 98 connects the valve 96 to a free water knockout or gas/liquid separator 100. The separator 100 includes a liquid outlet 102 and a gas outlet 104 connected to a compressor 106. The compressor 106 is connected to a high pressure flow line 108 leading to a meter run 110 where the gas is metered, delivered and sold to a pipeline company. A conduit 112 is connected to the flow line 108 between the compressor 106 and meter run 110 to deliver high pressure power fluid to the gas jet compressor 52. To this end, the conduit 112 includes a flow controller 114 therein and is connected to a control valve 116 communicating with the annulus 34.

In order to decrease the back pressure against the formation 16, the tool 40 is preferably set so that the low pressure inlet 58 is a minimum distance above the formation 16. The tool 40 is installed in the production string 26 at a stage of exploitation of the formation 16 when the formation flowing pressure and/or volume is insufficient to continuously produce all liquids appearing in the tubing string 26 to the surface. As previously discussed, this typically occurs after the formation 16 has been produced for a substantial length of time and the flowing pressure thereof declined substantially. There are some situations in high pressure, low volume wells in which the well may load up and die as a result of hydrocarbon liquids occurring in the production string 26 even though the pressure in the formation is substantial. In any event, the tool 40 is typically installed when the well begins to load up and die.

The following tabulated data is indicative of different applications of this invention:

DOWNHOLE GAS COMPRESSION __________________________________________________________________________ APPLICATIONS Power Jet Jet Comp. (2)Lbs. If Form Gas is "A" MCFD, Comp. Comp. Comp. Adj. Net Value of Gas Disch. Suct. Ratio P'R Total Gas is "B" MCFD & Ratio HP. Fuel Comp. Gas Net Gas Pres., Pres., Pres., of Gas/Lbs. P'R Gas is "C" MCFD of Req'd Req'd- Fuel Gain- Gain/ PSIA PSIA PSIA 52(1) Form.Gas "A" "B" "C" 106(3) for "C" MCFD Req'd(4) MCFD Mo.(5) __________________________________________________________________________ 75 40 25 1.6 3.0 250 1000 750 1.9 31 8 10 240 3875 75 40 15 2.7 7.7 250 2175 1925 1.9 79 19 24 226 2400 75 30 20 1.5 2.0 250 750 500 2.5 28 7 9 241 4430 75 30 15 2.0 3.6 250 1150 900 2.5 50 12 15 235 3820 75 30 10 3.0 7.0 250 2000 1750 2.5 98 23 29 221 2480 75 20 15 1.33 1.0 250 500 250 3.8 20 5 6 244 4780 75 20 10 2.0 2.5 250 875 625 3.8 51 12 15 235 4150 75 20 7 2.9 6.0 250 1750 1500 3.8 122 29 36 214 2630 200 60 30 2.0 2.6 250 900 650 3.3 48 12 15 235 4120 200 60 20 3.0 5.0 250 1550 1300 3.3 95 23 29 221 3010 200 40 20 2.0 2.0 250 750 500 5.0 51 13 16 234 4260 200 30 10 3.0 3.0 250 1000 750 6.7 86 21 26 224 3750 200 20 20 2.0 1.0 250 500 250 10.0 35 9 11 239 4080.sup.(6) 500 100 70 1.43 1.0 250 500 250 5.0 25 6 8 242 4750 500 100 50 2.0 2.3 250 825 575 5.0 59 14 18 232 4135 500 100 30 3.3 5.8 250 1700 1450 5.0 148 36 45 205 2400 500 50 30 1.7 1.4 250 600 350 10.0 49 12 15 235 3680.sup.(6) 500 50 20 2.5 2.6 250 900 650 10.0 91 22 28 222 2260.sup.(6) 500 50 15 3.3 4.5 250 1370 1120 10.0 157 38 48 202 120.sup.(6) 500 200 100 2.0 3.5 250 1125 875 2.5 49 12 15 235 3830 500 200 70 3.0 6.7 250 1925 1675 2.5 94 23 29 221 2570 1000 500 400 1.25 1.2 250 550 300 2.0 13 2 3 247 4670 1000 500 300 1.7 3.0 250 1000 750 2.0 33 8 10 240 4100 1000 500 200 2.5 6.5 250 1875 1625 2.0 72 17 21 229 2810 1000 300 200 1.5 1.4 250 600 350 3.3 26 7 9 241 4600 1000 300 100 3.0 5.0 250 1550 1300 3.3 95 23 29 221 3020 1000 100 50 2.0 1.5 250 625 475 10.0 67 16 20 230 3070.sup.(6) 2000 1200 1000 1.2 1.5 250 625 375 1.67 14 4 5 245 4660 2000 1200 800 1.5 2.8 250 950 700 1.67 27 9 11 239 4140 3000 1500 1200 1.25 1.5 250 625 375 2.0 17 4 5 245 4690 3000 1200 1000 1.2 1.0 250 500 250 2.5 14 3 4 246 4740 3000 1200 600 2.0 3.5 250 1025 875 -- -- -- -- 250 5525 __________________________________________________________________________

1. The indicated value is jet discharge pressure, psia/jet suction pressure, psia.

2. Data generated from curves in article entitled Gas Jet Compressors in Power and Fluids, Fall 1954.

3. The indicated value is power gas pressure, psia/jet discharge pressure, psia and is low to what can be expected in practice since it assumes that the pressure drop in the production string 26 between the tool 40 and the compressor inlet is negligible and that the pressure drop in the flow line 112 and the annulus 34 between the compressor 34 and the tool 40 is negligible. In fact, the pressure drop in the tubing string 26 probably requires a moderately larger compression ratio to deliver power gas at the power gas inlet pressure. The pressure drop in the flow line 112 and the annulus 34 is probably on the order of 1-2 psi and is accordingly negligible.

4. See note (3). The indicated value is 25% greater than the column entitled "Comp.Fuel Req'd-MCFD" to account for the erroneous assumption noted in note (3).

5. Net gas gain/day .times. 30 days/mo. .times. $1.00/MCF .times. 0.92 (for production taxes) .times. 0.80 (to account for royalties due) minus ($0.04/MCF .times. power gas volume in MCF for compressor costs/Mo. minus $300/mo. for other operating expenses.

6. Because of the 10.0 compression ratio required, a three-stage compressor would probably be required. Accordingly, compressor costs should be about $0.12/MCF for power gas.

Analysis of this data will show that one assumption made is that the suction gas or produced formation gas in column A is 250 MCFD which is a relatively modest volume. It will be appreciated that the first three groups of examples present exceedingly tough situations since the flowing bottom hole pressures are quite low. This is characteristic of shallow gas bearing formations which are approaching the economic limit of production. In situations comparable to those outlined in the first three groups of examples, a very tiny quantity of liquid in the production string will kill the well. It will be apparent from a perusal of the column entitled "Value of Net Gas Gain Per Month" that many of the situations presented in the data will justify working over an existing well in order to place the tool 40 therein and thereby prolong its economic life. In addition, it may be practical to drill a new well with a view to completing in a partially depleted reservoir incorporating the tool 40 in the production equipment.

Taking the first example illustrated in the tabulated data, it is assumed that the formation 16 will produce 250 MCFD at 25 psia bottom hole flowing pressure. Accordingly, 250 MCFD at 25 psia is delivered to the low pressure inlet 58 of the jet compressor 52. The flow controller 114 is set to deliver 750 MCFD through the flow line 112 at 75 psia. Accordingly, this quantity of gas flows down the annulus 34, through the passages 32 and into the power fluid inlet 60 to exhaust through the nozzle 62. Approximately 1,000 MCFD at 40 psia passes through the pup joint 70 into the production string 26. This quantity of gas passes through the production string 26 and the flow line 98 into the free water knockout 100. The liquids existing in the mixture are dropped out in the separator 100 and are disposed of through the liquid outlet 102. Gas passing through the separator 100 exits through the gas outlet 104 and is delivered to the compressor 106. The compressor 106 is operated at a compression ratio of approximately 1.9 to deliver gas at 75 psia. Approximately 10 MCFD is consumed as compressor fuel, about 240 MCFD is delivered to the meter run 110 to sales and about 750 MCFD is circulated through the flow line 112.

As mentioned previously, the effect of the tool 40 is two-fold. First, the pressure in the production string upstream of the tool 40 is increased which will increase the ability of the flowing gases to keep liquids unloaded. Second, and at least as important, an increased volume of gas is circulated through the production string 26. A linear velocity on the order of 5-10 feet/second is widely believed necessary to elevate liquid droplets in the production string 26 to the surface. It will be apparent that the linear velocity in the production string 26 is increased since a substantially greater quantity of gas is moved therethrough.

It will be apparent from a perusal of the data tabulated previously that the value of the net gas gain per month varies widely and depends in substantial part on the cost of operating the compressor 106 as reflected in footnotes 3 and 4. This operating cost can be substantially reduced in many situations existing in the field where a source of high pressure gas is available, as from a nearby well. This situation is quite common offshore since a production platform may have a large number of closely spaced wellheads thereon. The situation also exists to a lesser degree on shore where adjacent wells are producing from different formations on the same structure.

One technique for utilizing an available source of high pressure gas in the practice of this invention is illustrated in FIG. 4. Since the illustration of FIG. 4 is substantially identical to that of FIG. 1, the only reference characters appearing in FIG. 4 are those directed to different features of this embodiment. Unless otherwise mentioned, the various components of FIGS. 1 and 4 may be substantially identical. In FIG. 4, the annulus of the well 118 is connected to a valve which is in turn secured to a flow line 120 having a flow controller 122 therein. The flow line 120 extends to a separate or source well 124 which produces natural gas at a substantially higher pressure than the well 118. Preferably, gas from the source well 124 need not be compressed at all to act as the power fluid although it will be appreciated that a substantial savings can be effected if gas from the source well 124 must be compressed at a substantially lower ratio than gas from the well 118.

Ideally, gas from the source well 124 is sufficiently high to operate the tool 126 of this invention and elevate the pressure of gas produced from the gas bearing formation so that it will enter the sales pipeline without requiring compression thereof. An indication of an ideal situation is illustrated in the last example of the tabulated data wherein gas from the source well is available at 3,000 psia. The bottom hole flowing pressure in the low pressure formation, in this example, is 600 psia and the discharge from the tool 126 is 1,200 psia. It will be appreciated that gas flowing in the production string 128 at 1,200 psia need not be compressed at the wellhead whereupon the compressor may be omitted.

Another feature of the embodiment of FIG. 4 which may be particularly attractive when used in conjunction with gas from a source well is the provision of a second tool 130, substantially identical to the tools 40, 126, in the production string 128. In some situations, the compression afforded by the tool 126 may be insufficient to keep the tubing string 128 unloaded. It will be apparent that the second tool 130 downstream of the tool 126 may be provided to again compress the gas-liquid mixture flowing upwardly in the string 128. Although the staging of jet compressors may be practical when mechanically compressing gas at the surface, it appears particularly attractive when employing high pressure gas from a source well.

It will be apparent that the separate or source well suggested in FIG. 4 may be a production string inside the casing 132 wherein the gas is delivered to the surface, metered and then delivered to the flow line 120.

A more complicated technique, from both a practical and a regulatory standpoint, of utilizing high pressure source gas from a formation completed through the same casing string is illustrated in FIG. 5. The bore hole 134 is illustrated as intersecting an upper formation 136 which is approaching its economic limit of production and a lower formation 138 which will comprise the source of high pressure gas. In this embodiment, the source formation is illustrated as being deeper than the formation approaching the economic limit although it will be understood that if the high pressure formation is shallower than the low pressure formation, suitable adjustments in production equipment can be made.

As illustrated in FIG. 5, a pair of upper and lower packers 140, 142 seal between a stinger 144 and a casing string 146. The packer 140 is set above the low pressure formation 136 which is completed through a production string 148. A tool 150 is located at the lower end of the production string 148 with the power fluid inlet thereof in communication with gas flowing through the stinger 144 from the formation 138.

One practical problem with the embodiment of FIG. 5 resides in properly proportioning the quantity of gas produced from the formation 138 through the tool 150 and through the annulus 152. There are two pressure controlling devices which may be changed to properly proportion gas from the formation 138. The first, and by far the easiest, is a choke (not shown) at the surface in the annulus flow line (not shown). By increasing the size of the choke, a greater quantity of gas will flow up the annulus 152 with less gas passing through the tool 150. By decreasing the size of the choke, less gas will flow up the annulus 152 and more gas will flow through the tool 150. In addition, the nozzle in the tool 150 may be changed to vary the flow restriction of the power fluid.

It will accordingly be seen that there is provided an improved technique for the downhole compression of natural gas which allows the economic life of a gas producing well to be extended.

Claims

I claim:

1. A method of continuously producing natural gas for a period of time at the surface from a well providing a first fluid passage affording communication between the surface and an underground formation which produces both natural gas and a liquid wherein the formation flowing pressure and/or the produced gas volume are insufficient to continuously flow the gas and liquid through the first passage to the surface and a second fluid passage extending from a source of natural gas at a second pressure greater than the formation flowing pressure toward the formation, the method comprising the contemporaneous steps of

1. continuously delivering natural gas from the source through the second passage to a power fluid nozzle inlet of a gas jet compressor located adjacent the formation and accelerating the power gas to a supersonic velocity in a suction chamber downstream of the nozzle;

2. continuously withdrawing natural gas and liquid from the formation and directing the same into the low pressure suction chamber of the gas jet compressor;

3. sequentially deaccelerating the gas through a supersonic diffuser and then through a subsonic diffuser for raising the pressure thereof, the subsonic diffuser comprising a high pressure outlet side of the compressor in communication with the first passage;

4. continuously withdrawing a mixture of the gases of steps (1) and (2) and the liquid of step (2) from the subsonic diffuser at a pressure intermediate the formation flowing pressure and the power fluid inlet pressure and at a volume sufficient to overcome the effect of gravity on liquid droplets;

5. continuously passing the mixture upwardly through the first passage to the surface;

6. continuously removing liquid from the mixture at the surface; and

7. continuously delivering at least part of the gas to sales.

2. The method of claim 1 further comprising the step of continuously compressing, at the surface, at least part of the gas resulting from step (6) to the second pressure and thereby providing the source of step (1).

3. The method of claim 2 wherein the compressing step comprises compressing substantially all of the gas resulting from step (6) to the second pressure and step (7) comprises delivering only part of the compressed gas to sales.

4. The method of claim 1 wherein the well comprises a second jet compressor in the first fluid passage downstream of the first mentioned gas jet compressor and having a power fluid inlet nozzle for accelerating the power gas to a supersonic velocity in a suction chamber downstream of the nozzle, a low pressure inlet to the suction chamber in communication with the high pressure outlet of the first gas jet compressor, and a diffuser comprising a supersonic diffuser section and a subsonic diffuser section, and further comprising the steps of

a. directing the mixture of step (4) into the low pressure inlet of the second gas jet compressor;

b. continuously delivering natural gas at a third pressure greater than the intermediate pressure into the power fluid inlet nozzle of the second gas jet compressor and accelerating the power gas to a supersonic velocity in the suction chamber;

c. sequentially de-accelerating the gas through the supersonic diffuser section and then through the subsonic diffuser section;

d. continuously delivering the mixture of the gases of steps (1), (2) and (b) and the liquid of step (2) from the second gas jet compressor at a fourth pressure between the third pressure and the intermediate pressure at a volume sufficient to overcome the effect of gravity on liquid droplets in the first passage.

5. The method of claim 1 wherein the source of natural gas is a separate gas bearing formation and step (1) comprises continuously delivering produced gas from the separate formation to the power fluid inlet.

6. The method of claim 5 wherein the separate formation is completed through a separate well, the second passage extends from the surface and step (1) comprises passing natural gas down the second passage.

7. The method of claim 5 wherein the separate formation is completed through the same well as the underground formation and the second fluid passage comprises a wholly subterranean passage extending from the separate formation to the power fluid nozzle inlet, the step of delivering produced gas from the separate formation to the power fluid nozzle inlet comprises delivering only part of the produced gas thereto and further comprising the step of continuously passing the remainder of the produced gas from the separate formation upwardly through a third fluid passage to the surface.

8. Apparatus for producing natural gas from a formation which produces both natural gas and a liquid wherein the formation flowing pressure and/or the produced gas volume are insufficient to continuously flow the gas and liquid to the surface, the apparatus comprising:

conduit means extending from the surface to a location adjacent the formation providing a fluid passage therebetween;

a jet compressor, carried by the conduit means adjacent the lower end thereof, including a power gas nozzle having a subsonic convergent inlet section and a divergent supersonic outlet section, a housing in communication with the divergent nozzle outlet section and providing a low pressure inlet in communication with the formation, and a diffuser including a supersonic convergent inlet section in communication with the divergent nozzle outlet section and the housing, and a subsonic divergent outlet section in communication with the fluid passage;

a source of natural gas at a first pressure greater than the formation flowing pressure and means placing the source in communication with the power gas nozzle inlet for reducing the pressure in the housing and for discharging a mixture of natural gas and liquid through the diffuser outlet at a second pressure intermediate the formation flowing pressure and the first pressure and at a volume sufficient to overcome the effect of gravity on liquid droplets in the mixture;

a flow line connected at the surface to the conduit means for receiving the mixture therefrom;

a free water knockout in the flow line for removing the liquid; and

a meter run in the flow line downstream of the free water knockout for measuring gas flowing therethrough.

9. The apparatus of claim 8 wherein the source comprises a compressor in the flow line and the placing means comprises a conduit leading from the compressor to the convergent inlet section.

10. The apparatus of claim 9 further comprising a casing string surrounding the conduit means, the conduit comprising the annulus between the casing string and the conduit means and a flow line in communication between the compressor and the annulus.

11. The apparatus of claim 8 wherein the source is a high pressure gas naturally occurring in an earth formation separate from the first mentioned formation.

12. The apparatus of claim 8 wherein the conduit means comprises a first tubular string and a second tubular string inside the first tubular string and the fluid passage comprises the inside of the second tubular string.