GB2410509A - Retrofit method and apparatus for secondary recovery in a well or borehole - Google Patents

Abstract

Secondary recovery equipment is retrofitted in an existing cased borehole having production tubing 13 therein by positioning bridging plugs 19, 21 in the production tubing 13 at axially spaced apart positions, and lowering a fluid-pressure driven pump 20 to engage with and to seal with the lowermost plug 19 and to be suspended from the uppermost plug 21.

Description

24 1 0509 Retrofit method and apparatus for secondary recovery in a well

or borehole The present invention relates to a retrofit method and apparatus for secondary recovery in a well or borehole, and for use especially by the oil, gas, water and geothermal industries in a wellbore or tubular member. In oil and water wells and other boreholes, the product (oil or water) is contained below ground level at great depth and is contained within pores in the rock. Following the original formation of the product and over millions of years, more rock is deposited pushing the original rock strata deeper. The product becomes pressured by the weight of the rock and will flow to surface along a borehole or well when allowed to do so.

Oil wells can also contain gas in both small and large accumulations. Free gas migrates to the topmost layer of the oil bearing strata and will serve as a type of accumulator providing pressure to the oil, even after a quantity of oil has been withdrawn. Very often, oil wells will contain water which, being heavier than oil, will migrate to the lowest part of the oil bearing strata.

Oil wells are designed to produce the oil only leaving the gas and water behind as this is the most efficient in the long term. Following months or years of production, efficiency will drop with changing well conditions. Production of gas will deplete the available pressure which is required to lift the oil from the well. Water production will not only displace valuable oil production but will also hold back and possibly kill all well production. An example of this is to consider an oil well 10,000 feet deep. If oil is being produced with a surface pressure of 600 psi and at a rate of 2,000 bbis / day the bottom hole pressure (or lifting pressure) would be the specific gravity of the oil - say 0.75 - times the depth, 10,000 ft times the factor of 4.33 = 3247 psi. Add the 600 psi surface pressure to this and the bottom hole pressure will result. The bottom hole pressure is the pressure at which the oil is stored at in the reservoir. This equals 3,847 psi. If 50% water is being produced along with the oil, the specific gravity of the water is heavier than oil, being 1.0. The bottom hole pressure will be the same but the surface pressure (and flowrate) will drop. The surface pressure will now be 5,000 times 0. 75 times 0.433 plus 5,000 times 1.0 times.433 = 3,788 psi. minus the bottom hole pressure, 59 psi. l

As can be seen, with only 59 psi at the welibead as opposed to 600 psi with no water production, very little flow will result. Additionally, a reduction of the lifting or bottom hole pressure pressure by depletion or loss of the gas cap will produce a similar result.

There are a number of techniques which are designed to maintain high production levels. These are generally called secondary recovery techniques.

Included under this heading are water injection and gas injection. Additional wells may be drilled into the oil bearing strata and used to pump either water or oil into the formation. This allows the formation pressure to be kept artificially "high" as long as the injection is maintained. Yet other secondary recovery techniques are called artificial lift. These include downhole pumps and gas lift systems.

Gas lift operates on the reverse principle of water production killing a well as described above. If a column of fluid can be made lighter, more of the bottom hole pressure will be available to lift the fluid from the wellbore. A dead well can have gas injected into the fluid column to reduce the hydrostatic head of the fluid. A small quantity of pressured gas injected into a well will displace the volume of fluid equal to the volume of that gas bubble. If the gas is injected deep in the well, as fluid is withdrawn from the well and the gas moves upwards towards the surface, the gas pressure will decrease and the volume will increase. This increase will in turn displace more fluid until equilibrium occurs when the optimum injection rate for the required production has been reached. Too much gas will result in more gas than fluids being produced. Too little will result in insufficient production. Gas lift techniques depend on the availability of gas for this purpose and the well being equipped with equipment for this purpose. Sufficient volumes of gas are not always available at the wellsite especially in older wells where most of the gas has already been produced.

Downhole pumps tall into three main categories, electric, rod and hydraulic.

Electric submersible pumps (ESP'S) deliver high flowrates and are installed near the bottom of the wellbore. They are suitable for heavy oil and for fields where there was never too much pressure. They are installed with the other well equipment and are only replaceable by removing the production tubing, a job which requires a drilling rig and great time and expense. The pumps are connected to surface by a large diameter cable which has been specially manufactured to withstand the extreme downhole conditions of pressure and temperature. A surface facility is required to provide a high voltage supply to drive the pump. Electric pumps suffer from poor reliability in service.

Rod pumps (or nodding donkeysj are usually used on low flowrate wells in onshore locations. A plunger type pump is installed in a special nipple near the bottom of the wellbore. Rods connect the plunger to surface where they attach to a beam. "Rocking" of the beam by way of an electric motor and drive belts allows the pump to reciprocate and for fluid to be pumped to surface. This type of pump relies on the well fluid being de- gassed. Accordingly, the gas is separated from the oil downhole and flows to surface up the annular space between the tubing and the casing. The tubing contains the oil flow and also houses the rods.

Hydraulic pumps fall into two main categories, jet pumps and piston pumps. Jet pumps require a large volume of power fluid to be pumped down the tubing and into the pump. A nozzle and venturi feature on the pump outlet create an area of low pressure which draws the fluid to it. Spent power fluid and produced well fluid are produced to surface via the annular space between tubing and casing. Piston pumps are installed at the bottom of the production tubing and also receive their power fluid through the tubing. They contain engine pistons which are driven by the power fluid and pump pistons which discharge the oil into the annular space between the production tubing and the casing. The spent power fluid is also discharged into this annulus. Both these pump types must be installed with the well equipment when new or at least, provision must be made for them when the well equipment is new.

Following a drop off in well production, many options exist to increase the production. Unfortunately most of these options require a well intervention by way of removing the well tubulars and re-completing the well with new or alternative equipment. The cost of this may outweigh the benefit which the new production will bring as this type of operation is very expensive.

An attractive option would be to re-configure the well to allow secondary recovery techniques without removing the well tubulars. The present invention has been developed primarily, though not exclusively, in connection with a method for the economical fitment of a pump, e.g an hydraulic piston pump to a well which has not been provided with the necessary equipment to receive a pump and which has suffered a loss of production as a result of water production, loss or depletion of pressure or both these scenarios. The invention may also be fitted to a new well and installed with the well equipment.

The invention is defined in three separate aspects, in the patent claims attached hereto. Preferred features of the invention are set out in the dependent patent claims.

A preferred example of a method according to the invention, and novel secondary recovery equipment for use in the method, will now be described in detail, by way of example only, with reference to the accompanying drawings, in which: Figure 1 is a schematic illustration of a typical existing well or borehole for exploiting a sub-surface reservoir of producer fluid medium, such as oil or gas, and to which a method of retrofitting secondary recovery equipment according to the invention may be applied; Figure 2 is a view, similar to Figure 1, showing a further existing well or borehole to which the invention may be applied; Figure 3 is a view, similar to Figures 1 and 2, showing secondary recovery equipment installed in an existing well or borehole, for carrying out the invention; and Figure 4 is a enlarged view, corresponding to part of Figure 3, illustrating how a pumped supply of power fluid (liquid or gas) medium is routed down the annulus to a pump suspended within the production tubing, and which discharges the power fluid upwardly into the tubing to boost the upward flow of producer fluids when required.

With reference to figure 1, a standard or normal oil well 10 is shown. Oil flows from the source rock 11, through perforations 14 and into the casing 12.

Production tubing 13 extends from the surface 15 to near the source rock in order to provide a conduit for the oil to safely flow to surface under pressure. Near the bottom of the production tubing 12 is a packer 16 which isolates the annulus 17 from the pressurised oil. At surface is the Christmas tree or welibead 18 which allows the oil flow to be choked and diverted. Below this is a valve 14 which allows fluids to be injected or withdrawn from the annulus.

With reference to figure 2, the standard well is shown with a bridge plug 19 fitted and communication established between the tubing 13 and annulus 17. Bridge plugs are common place and are normally used to plug a -well and as a pressure barrier. Bridge plugs are available with generous through bores and when the nosecone pressure barrier is omitted, they are suitable for our purpose. Tubing to annulus communication (tubing punch) is routinely performed in order to circulate fluids around the tubulars and to kill a well prior to removal of the tubing, when required.

Figure 3 shows the same well with a piston type pump 20 suspended below a second bridge plug 21 and engaged with the first bridge plug 19 to create a pressure tight seal.

Figure 4 shows the piston pump 20 in section and demonstrates the flow path of power fluids from the surface 15 and down the annulus 17, acting on the power piston 21 and discharging at position 22 into the tubing 13 along with the pumped well fluids.

The installation is conducted using proven slickline techniques. Slickline is a well intervention service which utilises a single strand wireline. This is highly portable, is inexpensive to operate, does not require the presence of a rig and requires minimal personnel. All aspects of the installation exist and are conducted on a regular basis. Following installation, fluid pumped down the annulus will function the hydraulic pump. The power fluid may be water or it may be crude oil or another liquid. In certain applications, gas may be used to power the pump. The pump will create positive pressure above and reduced pressure below creating additional production from the previously dead well. The new production will flow to surface through the production tubing in the san e manner as previously. As a result, no changes will be required to the surface flow lines or the configuration of the surface processing equipment. If water is used as the injection fluid, it may be separated out at surface in the usual way. Crude oil will also be processed as before as will any spent gas used for this purpose. Where gas is to be used in place of a power fluid, an additional benefit is accrued whereby a rudimentary gas s lift system is provided whereby the spent gas which is discharged from the pump may assist in lifting the produced well fluids.

The maximum and minimum output of the pump and the subsequent well production will be dictated by well constraints such as tubing diameter, available surface pumping capacity, deliverability of the oil producing formation and surface separation and processing capacity. As an indication, for every barrel pumped, an additional barrel will be recovered. The pump operation is not constrained by setting depth as are some other systems but by surface pump capacity only.

Surface constraints are much more easily dealt with than downhole ones.

The pump design differs from existing piston pumps in that it receives the power fluid from the annulus whereas conventional pumps of this type require the power fluid to be pumped down the tubing and the spent power fluid along with the well production to be produced up the annulus. The pump is retrievable as it is suspended from the upper bridge plug. Bridge plugs are generally retrievable by using slickline techniques and when removed from the well, the pump will also be removed. This allows for a maintenance and servicing schedule or for re- configuration of the pump.

The lower bridge plug may be left in situ during this time. To prevent annulus power fluid from flowing from the annulus and down into the oil bearing formation with the pump removed, the lower bridge plug may be equipped with a check valve. This will allow upwards flow only.

Claims (6)

1. A method of retrofitting secondary recovery equipment in an existing well or borehole (10) for exploiting a sub-surface reservoir of a producer fluid medium, having a casing (12) running from the surface (15) to a producing formation (11), and production tubing (13) within the casing (12) and defining an annulus (17) between the inner wall of the casing (12) and the outer wall of the tubing (13), in which the recovery equipment includes a fluid-pressure driven pump (20), and first and second bridging plugs (19, 21), and the method comprising: positioning the first and second bridging plugs (19, 21) in the production tubing (13) at axially spaced apart positions; and lowering the pump (20) into position down the production tubing (13) to engage with and to seal with the lowermost of the bridging plugs (19) and to be suspended from the uppermost of the bridging plugs (21).

2. A method according to Claim 1, in which any suitable power fluid to drive the pump (20) is routed down the annulus (17) to the pump (20), and is discharged upwardly at position (22) within the tubing (13) thereby to assist in secondary recovery of the producer fluid medium.

3. A method according to Claim 1 or 2, in which the pump is located in position via a slickline installation.

4. A method according to Claim 1, in which the secondary recovery equipment is assembled as original equipment in a primary production apparatus, and is used to extract liquid and/or gaseous hydrocarbons via the primary production apparatus initially, and when the rate of flow of produced fluids falls below required levels, the secondary recovery equipment is operated to boost the flow rates.

5. A method of secondary recovery in a well or borehole (10) in which primary extraction of a producer fluid medium from a sub-surface reservoir (11) takes place via a casing (12) running from the surface (15) to the reservoir (11), and production tubing (13) within the casing (12) and defining an annulus (17) between the inner wall of the casing (12) and an outer wall of the tubing (13); l in which a secondary recovery apparatus is provided in the tubing (13) and comprising upper and lower bridging plugs (19, 21) mounted at spaced apart locations in the tubing (13) and a power fluid driven pump (20) suspended from the upper bridge plug (21) and engaging with the lower bridge plug (19): the method comprising the steps of initiating secondary recovery (when the rate of primary extraction,ai,s below required,eveis) by routing a power pressure fluid from the surface (15) to the pump (20) via the annulus (17), and routing the discharge of the power pressure fluid upwardly into the tubing (13) to boost upward flow of producer fluid from the reservoir (11) to the surface (15) via the tubing (13).

6. A method according to any one of claims 1 to 5, in which the power fluid used to operate the pump is a liquid or a gas.