Stimulation of Packerless Wells for Enhanced Oil Recovery

Abstract

Four methods are described for inducing high differential pressures across perforations in wells traversing earth formations. Nitrogen, N2, or another inert gas is introduced into the well under pressure (via the annulus and/or the tubing), thereby lowering the fluid column and setting up conditions for lowering the hydrostatic pressure above the formation. The formation is then subjected to sudden exposure to the lowered hydrostatic pressure, either through use of a pressure-actuated surge valve or through sudden bleed-off of the N2 gas. In both cases, a sudden release of well fluid pressure into the tubing string and/or annulus produces an implosion force and surges the perforations.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit under Title 35 United States Code §119(e) of U.S. Provisional Patent Application Ser. No. 62/185,460; Filed: Jun. 26, 2015; the full disclosure of which is incorporated herein by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention describes a methodology for stimulation of oil and gas production from oil or gas packerless wells that traverse earth formations and that have been completed with shaped charge perforations. More particularly, the system of the invention is used to develop a high and/or sudden differential-of-pressure effect in perforations in a well bore to flow or flush debris and compacted materials from the perforations with minimal intervention and very low impact on the well equipment.

2. Description of the Related Art

It is known that shaped charge perforating guns leave residue and a compacted zone inside the perforation tunnels that they create; both the debris and the compaction contribute to clogging in the perforations, preventing them from flowing at capacity or possibly even at all. Evidence of non-producing perforations in some producing wells exists in the form of production logs or downhole imaging.

The use of a suddenly applied differential pressure surge to dislodge debris and compaction from shaped charge-created perforations has shown considerable success at increasing well production rates in consolidated formations having porosity and permeability.

U.S. Pat. No. 6,296,058, issued Oct. 2, 2001, entitled “Wellbottom Fluid Implosion Treatment System”, the full disclosure of which is incorporated herein by reference, describes a pressure-actuated retrievable surge valve used to produce a sudden differential pressure across perforations, referred to as an implosion force. For its operation, this tool is lowered through a tubing string on a wire line and locked into the tubing profile, where it closes off the cross-section of the tubing string. The wire line connection to the tool is released, and the fluid in the bore of the tubing string above the tool is gradually removed, lowering the pressure above the tool and creating a pressure differential across the tool. This differential increases as more fluid is removed. The valve is responsive to a predetermined differential pressure between the pressure of fluid in the tubing string above the tool and shut-in pressure of fluids in the well bore below the tool; the valve opens at a specifically predefined pressure differential. When the valve opens, the shut-in pressure is effectively released suddenly. This causes the implosion force that surges the formation and flushes the perforations, with only low impact on the well equipment or on the tool. The tool is retrieved on a wire line after the operation, so that the life of the tool and re-dressing time are improved.

One limitation of the “Wellbottom Fluid Implosion Treatment System” referenced above is that its method of use is designed for the treatment of wells with production packers in place. However, there are many packerless wells, including pumping wells, for which the methods of the Wellbottom implosion system are not applicable.

SUMMARY OF THE INVENTION

In the present invention, methods are provided for stimulation of oil and gas production from packerless oil or gas wells that traverse earth formations and that have been completed with shaped charge perforations. The present invention provides a system that is used to develop a high and/or sudden differential-of-pressure effect in perforations in a well bore to flow or flush debris and compacted materials from the perforations with minimal intervention and very low impact on the well equipment. Within the scope of the present invention, the various methods embody the concept of creating a high differential pressure across the perforations in the formation, thereby stimulating the well. Methods have been developed for deployment of the pressure-actuated surge valve in packerless pumping wells. Calculations describe differential limits, based on relative tubing and casing diameters in ideal cases. Attainable differential surge pressure can be predicted for given well conditions.

The invention discloses new methods of setting up pressure differentials that surge the formation and help unclog perforations, even in non-flowing packerless wells. These methods broaden the range of well conditions that can be effectively treated with surging; now existing pumping wells, which often do not have packers, can be surged.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of the downhole environment in which the described methods operate.

FIG. 2 is a flowchart showing the basic steps in a first method of implementing the processes of the present invention.

FIG. 3 is a flowchart showing the basic steps in a second method of implementing the processes of the present invention.

FIG. 4 is a flowchart showing the basic steps in a third method of implementing the processes of the present invention.

FIG. 5 is a flowchart showing the basic steps in a fourth method of implementing the processes of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Reference is made first to FIG. 1 which is a schematic drawing of the downhole environment in which the described methods operate. In FIG. 1, borehole 10 is positioned from ground level 10 to producing formation 30. Casing 14 is positioned within borehole 12, typically with cement 16. Tubing 18 is positioned within casing 14 with annulus fluid 20 filling the annulus between the tubing and the casing. Tubing 18 carries tubing fluid 22. The specific structures of surface equipment 15 are not shown in detail but are typical for the type of borehole of concern here.

Downhole within producing formation 30 are one or more plugged perforation tunnels 32. Packers 26, where present, would be positioned as shown in broken line form. Packerless wells would include no packers 26 in the annulus where shown. In pumping wells, piston assembly 28 on a rod to surface pump would be removed for some of the operations described in the present invention. Finally, a retrievable surge valve 24 is positioned as shown with locking mandrel and pressure gauge. The surge valve 24 is not present for all operations of the present invention.

The first method of the present invention is characterized by the following steps which are shown in the flowchart of FIG. 2. Step 100 initiates the method while query Step 102 determines whether the well is a beam pumping well. The process then proceeds as follows:

(a) Remove the sucker rod and pump if the well is a beam pumping well (Step 104);

(b) Apply nitrogen pressure to the tubing column (bleed off any fluid that exits through the annulus) (Step 106);

(c) Introduce the through-tubing surge valve into the well and set it (Step 108);

(d) Gradually bleed off the nitrogen (Step 110); and

(e) Surge the well (Step 114) when the pressure-actuated valve opens (Step 112).

This process creates sudden, high differential pressure at perforation, sufficient to unplug perforation tunnels and increase well production flow rate.

The second method of the present invention is characterized by the following steps which are shown in the flowchart of FIG. 3. Step 120 initiates the method while query Step 122 again determines whether the well is a beam pumping well. The process then proceeds as follows:

(a) Remove the sucker rod and pump if the well is a beam pumping well (Step 124);

(b) Apply nitrogen pressure to the tubing column (bleed off any fluid that exits through the annulus) (Step 126);

(c) No introduction of the through-tubing surge valve into the well; and

(d) Bleed off the nitrogen suddenly (Steps 128 & 130).

This process creates fast, high differential pressure at perforation, sufficient to unplug perforation tunnels and increase well production flow rate.

The third method of the present invention is characterized by the following steps which are shown in the flowchart of FIG. 4. Step 140 initiates the method while query Step 142 again determines whether the well is a beam pumping well. The process then proceeds as follows:

(a) Remove the sucker rod and pump in a beam pumping well (this step is not necessary in a flowing or gas lift well) (Step 144);

(b) Apply nitrogen pressure to the annulus, not to the tubing column (bleed off any fluid that exits through the tubing column) (Step 146);

(c) No introduction of the through-tubing surge valve into the well; and

(d) Bleed off the nitrogen suddenly (Steps 148 & 150).

This creates fast, high differential pressure at perforation, sufficient to unplug perforation tunnels and increase well production flow rate.

The fourth method of the present invention is characterized by the following steps which are shown in the flowchart of FIG. 5. Step 160 initiates the method and the process then proceeds as follows:

(a) No removal of sucker rod and pump, even in a beam pumping well (Step 162);

(b) Apply nitrogen pressure to the annulus, not to the tubing column (bleed off any fluid that exits through the tubing column) (Steps 164 & 166);

(c) No introduction of the through-tubing surge valve into the well (Step 168); and

(d) Bleed off the nitrogen suddenly (Steps 170 & 172).

All these methods create fast, high differential pressures at perforation, sufficient to unplug perforation tunnels and increase well production flow rate. Note that all procedures can be repeated as often as desired. More complete unplugging may occur with repeated operations.

The fourth method provides for pumping equipment to remain in place for the operation, simplifying the entire procedure. It also allows for the well to be tested for production flow rate between applications of nitrogen and surging. It may require special adaptors in order to install multiple bleed off valves to enable fast bleed off of nitrogen from the annulus. Variations of these procedures may apply in gas lift wells.

The use of nitrogen or other inert gas is a conventional part of well service practice and requires no special equipment beyond what is already standard. Such gases are delivered in liquid form by truck for use at a well site.

Reference is again made to FIG. 1 which is a schematic drawing of the downhole environment in which the described methods operate. The drawing shows borehole, casing, tubing, producing formation, and perforation tunnels, and indicates the fluid columns present in annulus and tubing. It also illustrates components; packers, surge valve, piston assembly and rod; that will be present in some wells and operations but not in all. The packer is shown but will not be present in packerless wells; the surge valve is shown but is present only for those procedures using the surge valve; the piston assembly and rod are shown but are present only in beam pumping wells. A locking mandrel with surge valve and pressure gage sealed and locked in tubing is retrievable. Again, the piston assembly is shown on rod to surface pump (in pumping wells) but is removed for some operations.

Although the present invention has been described in conjunction with a number of preferred embodiments, those skilled in the art will recognize modifications to these embodiments that still fall within the spirit and scope of the invention. Because of variations in downhole environments some variations in the methods described are anticipated.

All methods are for packerless non-flowing wells. This means that as a pressure differential is created, whether by opening the surge valve or simply by bleed-off of nitrogen, well fluid will flow between annulus and tubing. This will continue until the hydrostatic pressure between casing and tubing is balanced, i.e. until the two fluid columns are of equal height H*. At this point the actual differential surge pressure is established and is felt suddenly and strongly by the formation. The surge differential is the difference between formation pressure and the hydrostatic pressure at the equalized column height H*.

The amount of well fluid pushed out of the system during the application of nitrogen determines H*, the height at which the two columns equalize once nitrogen bleed off begins, and this determines the surge differential felt by the formation. Thus the differential surge pressure can be expressed for ideal conditions in terms of the amount of well fluid pushed out of the system:

ΔP=ρdH

Where: d is the density of the formation fluid; H is the distance that the tubing extends down into the formation fluid (the height of the fluid column in the tubing at static conditions); p is the fraction of well fluid volume (from annulus and tubing) that is pushed out of the system using nitrogen, prior to surging (ρ≦1); and ΔP is the differential surge pressure.

This allows a control over differential surge pressure for an operation, by monitoring and controlling the amount of well fluid bleed off during nitrogen application. The cross-sectional areas of tubing and annulus determine the volume of well fluid present at hydrostatic conditions, and it is the fraction ρ of well fluid volume removed from the system that determines the anticipated surge differential ΔP.

It should be noted that some perforation flow may occur during the column equalization phase. Nevertheless, ΔP as calculated above provides an estimate of the minimal surge differential across perforations to be expected by the first through third methods of the present invention. Once column equalization is reached, this differential is felt suddenly across the formation and surges the perforations.

For the fourth method, in which the pump is left in place, a check valve inhibits fluid flow from tubing to annulus and there will be no equalization between the columns. However, if ρ is re-defined as the fraction of fluid column pushed out of the annulus using the nitrogen, then ΔP is still given by the above formula and indicates the maximal differential the perforations can feel as nitrogen is bled quickly out of the annulus; how quickly it is bled off determines how close to this ideal the actual differential will come.

Some examples are provided, with specific values of inner diameter (I.D.) and outer diameter (O.D.), hydrostatic column height, and well fluid density. Notice how the measurement of well fluid bleed off at the surface allows control of surge differential. Too low a surge differential indicates the need for continued bleed-off.

Example 1: Casing I.D.=4.494″; Tubing O.D.=2.875″; Tubing I.D.=2.441″; and d=0.396 psi/ft. (the density of light oil). These values determine cross-sectional areas of tubing and annulus, and then well fluid volume in tubing and annulus varies with H:

H=1,000′, volume=98 ft³

H=2,000′, volume=196 ft³

H=3,000′, volume=294 ft³.

The relation ΔP=ρ d H shows that if the bleed-off volume of well fluid is fixed at, say 49 ft³, then surge differential does not vary with H:

H=1,000′, ρ=0.5, and ΔP=198 psi,

H =2,000′, ρ=0.25, and ΔP=198 psi,

H =3,000′, ρ=1/3, and ΔP=198 psi.

Bleeding off higher volumes of well fluid results in higher surge differential: a bleed-off of 75 ft³ results in surge differential ΔP=303 psi for all tubing depths H where well fluid volume of tubing and annulus is more than 75 ft³.

As tubing goes deeper, more well fluid is contained in tubing and annulus, making it possible to reach higher surge differentials by pushing out more fluid than present for smaller H:

For a bleed-off of 147 ft3 with H=2000′, ΔP=594 psi

For a bleed-off of 200 ft3 with H=3000′, ΔP=808 psi.

Example 2: Casing I.D.=4.950″; Tubing O.D.=3.500″; Tubing I.D.=3.068″; and d=0.413 psi/ft.

Volumes:

H=1,000′, volume=118 ft³,

H=2,000′, volume=236 ft³,

H=3,000′, volume=354 ft³.

Removing 59 ft³ by bleed off well fluid prior to surge results in a surge differential ΔP=206 psi for all three values of H. For H=2000′ and H=3000′, removing 120 ft³ gives ΔP=419.6 psi. For H=3000′, removing 250 ft3 of well fluid gives ΔP=875 psi.

Example 3: Casing I.D.=4.276″; Tubing O.D.=3.500″; Tubing I.D.=3.068″; and d=0.413 psi/ft.

Volumes:

H=1,000′, volume=84 ft³,

H=2,000′, volume=168 ft³,

H=3,000′, volume=252 ft³.

Notice that parameters are the same here as for Example 2 except that casing inner diameter is smaller, meaning that total well fluid volume (tubing and annulus) is lower than in Example 2. Removing 59 ft³ well fluid by bleeding off prior to surge gives a surge differential of ΔP=290 psi for all three values of H. (Same amount of well fluid bleed off gives a higher differential in Example 3, compared to Example 2.)

For H=2000′ and H=3000′, removing 120 ft³ gives ΔP=590 psi.

For H=3000′, removing 250 ft³ of well fluid gives ΔP=860 psi.

Total bleed off of well fluid from annulus and tubing is not recommended because it is the remaining well fluid that equalizes when nitrogen pressure decreases as nitrogen is bled off It is the column equalization phase that sets up balanced columns between tubing and annulus and produces an actual surge differential that is felt suddenly by the formation.

It is likely that even small surge differentials may be effective at unclogging perforations because they will be suddenly felt, giving more force to the differential pressure (suddenly-applied force tends toward twice the strength of slowly-applied force), and because each of these operations can be repeated. It has been observed that multiple surges sometimes have a better cumulative effect than a single surge. For packerless pumping wells, maximum pump rate should be measured prior to the operation and then compared with the maximum rate measured again after the operation.

Any well that was perforated at completion and not surged suffers from the effect of clogged perforations that have never been cleaned out. This is not specific to flowing wells, and indeed, many pumping wells are in the same need of surging as flowing wells are. This covers wells in consolidated formations, where surging is operative. Thus the present invention proposes a method to deploy the through-tubing pressure actuated surge valve of U.S. Pat. No. 6,296,058 to pumping wells, and indeed to any wells without packers. This enormously widens the field of application of the previous patent, which was essentially intended for flowing wells with packers.

Additionally, other methods are proposed, not involving the through-tubing pressure actuated surge valve. The observation that nitrogen or another inert gas can be used to set up a pressure differential to surge packerless wells (pumping or flowing) simplifies the procedure significantly. These methods use only standard equipment, except for possible special adaptors to allow multiple large bleed off valves to be installed and opened simultaneously for quick nitrogen bleed off. The introduction of nitrogen or other inert gas into a well is standard well procedure for a variety of uses, but those uses do not include well stimulation.

It has been observed that existing equipment and procedures can be modified and used for the purpose of setting up surge differentials and allowing perforations to be surged and unclogged (and the definition of how to do it) that is unique to the present system. It is generally known that putting nitrogen into a well, but no one knows about the differential that can be set up this way and the fact that this can be used to surge a well and unplug perforations. The present system has low impact on well equipment, has potential for high impact on production rates with very simple operations, and now extends the application of surging to include pumping wells (no packers).

Differential surge pressure can be controlled with the amount of bleed off of well fluid. This allows technicians in the field to know what differential to expect or to control the differential they will produce just by measuring volume of bleed off of well fluid at the surface.

The fourth method described above is a simple operation because it allows pump and sucker rod to remain in place. It would thus be the least expensive of all the methods proposed.

Its simplicity does mean that the differential pressure will be less suddenly-applied than for the other methods, but that is compensated for by recommending many large bleed off valves open simultaneously in order to make the nitrogen bleed off fast. The recommendation also to repeat this operation several times makes it more likely to be successful, and repeating this operation will be exceedingly easy. No current applications in the field are applying N₂ and bleeding it off rapidly and then repeating additional times to get production rate up.

In the first method described above, with the surge valve, there is likely to be an initial surge prior to the equalization of the tubing and annulus columns. The sudden opening of the surge valve into empty tubing is likely to be felt by the formation before the equalization is done. This differential is simply ΔP=dH and is the best possible surge differential the system can provide. However, interference with flow from the perforations from the annulus will cause the equalization of tubing and annulus columns, at which point the differential will be ΔP=T/(A+T) d H, as shown by previous and current calculations, where T/(A+T) is the fraction of well fluid volume removed from the system when the tubing is emptied.

Although the present invention has been described in conjunction with a number of preferred embodiments, those skilled in the art will recognize modifications to these embodiments that still fall within the spirit and scope of the invention. Because of variations in downhole environments some variations in the methods described are anticipated.

Claims

1. A method for the stimulation of packerless wells for enhanced oil recovery, the method comprising the steps of:

(a) removing the sucker rod and pump if the well is a beam pumping well;

(b) applying nitrogen pressure to the tubing column and bleeding off any fluid that exits through the annulus;

(c) introducing a through-tubing surge valve into the well and setting it;

(d) gradually bleeding off the nitrogen; and

(e) surging the well when the pressure-actuated valve opens.