Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/128—Adaptation of pump systems with down-hole electric drives

Definitions

• This invention relates to the use of electric submersible pumps (ESPs) in temporary well operations.
• the invention relates to the use of ESPs for production logging and well testing operations, and for restarting well production.
• FIG. 1 shows a known type of ESP which comprises an optional pre-motor section 10 with electronics for data acquisition and possibly a motor control unit such as commutation system, one or more motor sections 12 (two are shown here), each of which contains a stator and a rotor mounted on a drive shaft; a protector section 14 including a pump intake 16, and a series of pump sections 18 (four are shown here, although the number of sections can be selected according to the amount of lift and volume the pump must deliver.
• a motor control unit such as commutation system
• the exact construction of the known ESPs varies according to requirements, typically the amount of lift that has to be provided. Even for relatively low lift levels, the ESP can be long and involve complex on-site construction for installation. Furthermore, since ESPs are installed for long-term (ideally permanent) operation, they are typically engineered for reliable operation rather than ease of assembly or convenient handling which is more of a secondary consideration. The overall length of known ESPs often reaches up to 50m which effectively precludes temporary or short-term use.
• Another problem with known ESPs is that they effectively prevent accurate measurements below the ESP from being made vs. depth.
• the physical presence of the ESP prevents easy access to the lower part of the well for production logging tools.
• the flow that exits the ESP is a co-mingled flow so it is not possible to identify which parts of the well are contributing which part of the fluid flow, so making identification of zones for remedial or production enhancement treatments difficult. It is also difficult to isolate intervals of the well below the ESP for well test measurements to allow such treatments to be properly designed.
• This invention is based on the recognition that the flow modification produced by an ESP can be used in short term well operations to great effect, particularly in production logging and well testing applications. By designing the ESP for relatively short term operation, some of the disadvantages in conventional ESP can be overcome while allowing modification of the design to provide the required operations and/or measurements. Disclosure of the invention
• a first aspect of this invention provides a method of conducting operations in a well, comprising:
• the method preferably further comprises temporarily isolating the portion of the well above the ESP from the portion of the well below the ESP such that the only fluid communication between the two portions is via the ESP.
• Such isolation can typically be performed using a packer (conventional or inflatable) to temporarily isolate the two portions of the well. It may also be desirable to create an isolated interval in the portion of the well below the ESP by temporarily isolating the portion of the well below the ESP from the remainder of the well. This can also be performed by setting a bridge plug or a packer connected to a blind-pipe: an inflatable packer below the ESP can create the lower isolation.
• One preferred embodiment of the method comprises making pressure and/or flow rate measurements on the well fluids during operation of the ESP.
• Flow rate can be measured above or below the ESP. This can include measuring flow rate below the ESP at or near a location where reservoir fluids enter the well.
• Another preferred embodiment of the invention comprises modulating or interrupting flow through the ESP and measuring pressure in the portion of the well below the ESP. This can typically comprise modulating the flow rate through the ESP by at least 20%
• One such approach comprises periodically interrupting flow through the ESP and measuring pressure during the periods when there is no flow, for example operating the ESP for a predetermined period of time so as to establish a pressure in the portion of the well below the ESP at a substantially constant level below reservoir pressure; stopping flow through the ESP; and measuring the pressure in the portion of the well below the ESP as the pressure returns to reservoir pressure.
• a valve in the outlet of the ESP may be operated to modulate or interrupt the flow. It may also be appropriate to divert flow from the ESP back into the portion of the well below the ESP when the valve is operated to interrupt the flow.
• the step of moving the ESP to another location can comprise moving it to another location in the same well or withdrawing it from the well completely.
• Another embodiment of the method comprises positioning the ESP in a well that is not capable of flowing to surface (for example one with low reservoir pressure that has been shut in an stopped flowing due to the separation of the phases of the well fluid, and operating the pump until the well is capable of flowing to surface under reservoir pressure at which point the ESP is withdrawn from the well.
• a second aspect of the invention comprises a system for performing a method as claimed in any preceding claim, comprising: an ESP;
• This preferably includes means for isolating the portion of the well above the ESP from the portion of the well below the ESP such as a packer (preferably an inflatable packer). It may also comprise means for isolating the portion of the well below the ESP from the remainder of the well to create an isolated interval which may also comprise an inflatable packer.
• the packer may also be combined with slips to transmit the axial load of the packer onto the well-bore: this may be important when the system supporting the ESP is limited in axial load resistance. This is a particular combination involving inflatable packers, slips, and an ESP.
• Pressure and or flow rate sensors can be provided for making measurements on the well fluids during operation of the system.
• flow rate sensors are provided above or below the ESP.
• the flow rate sensors can be positioned below the ESP at or near a region of the well where reservoir fluids enter the well.
• the system may also comprise means for modulating or interrupting flow through the ESP.
• the means are typically operable to modulate the flow rate through the ESP, for example up to 10% or 20%, and may periodically interrupt flow through the ESP.
• the means can comprise a valve in the outlet of the ESP to modulate or interrupt the flow.
• a flow diverter may also be provided for diverting flow from the ESP back into the portion of the well below the ESP when the valve is operated to interrupt the flow.
• the flow modulation can also be achieved by changing the rotational speed of the pump via the motor control system (typically located at surface).
• the system preferably includes a cable for supporting the ESP in the well an providing power and control signals.
• the ESP can also be supported on tubing or coiled tubing with a cable provided for power and data.
• the construction of the ESP is optimized for high speed rotation so that the ESP can have a small overall size (e.g. less than 12 meters). This allows the weight to be low enough that the ESP can be supported by a wireline cable.
• the wireline cable may be specifically configured to transmit sufficient power for operation of the ESP motor.
• the ESP can also be provided with a small diameter housing which allows the ESP to be lowered (with any associated packers) through production tubing.
• the ESP can be constructed to allow attachment of conventional wireline logging tool below it.
• This wireline logging tool can be autonomous, i.e. it can be operated from an internal power supply (batteries) and measured data can be stored in an internal memory (in a similar manner to certain current production logging tool systems).
• the logging tool communicates with the electronic module of the ESP via wireless telemetry (electro-magnetic telemetry).
• the wireline logging tool can also communicate with ESP electronic system, as well as taking power for the ESP power system via appropriate cabling and an interface.
• the bottom data measurement unit (wireline tool) can be mounted onto an extendible support, allowing the data logging versus depth while the ESP, with an optional packer (which is set), is static in the well-bore.
• measurements such as fluid composition (gas, oil, water ratio) as well as fluid velocity can be performed. These measurements can be performed versus various pressures (as they are performed in the ESP suction zone: the ESP can be operated at different regime to change the suction pressure). This allows determination of properties such as the compressibility of each phase, and/or the phase change (especially the bubble point) at downhole conditions.
• Figure 1 shows a prior art ESP
• Figure 2 shows a first embodiment of a system according to the invention
• Figure 3 shows a second embodiment of a system according to the invention
• Figure 4 shows a plot of pump flow rate and well pressure vs. time for a first embodiment of a well test according to the invention
• Figure 5 shows a plot of pump flow rate and well pressure vs. time for a second well test according to the invention
• Figure 6 shows an embodiment of the invention deployed at the end of tubing. Mode(s) for carrying out the invention
• the invention is based around the use of an ESP as a temporary installation in order to perform various operations before being moved and used again.
• a pump has a single shaft on which the motor and pump components are mounted, all located in a common housing.
• This construction is shorter than a conventional ESP, typically less than 12m. By maintaining a relatively short overall length, the ESP can be placed in the well through conventional well-head equipment.
• the motor and pump sections are relatively short, they are run at higher speeds than conventional ESPs in order to provide corresponding levels of lift.
• a conventional ESP might be run at 3000 rpm
• the compact ESP used here can be run at higher speeds to achieve the same lift, e.g. 6000 - 12000 rpm.
• maintenance can be carried out to avoid reliability problems that might otherwise arise from extended periods of high speed use.
• the use of the ESP in this invention allows production logging and well testing measurements to be made in wells that do not normally produce to surface, or produce at such low rates as to make flow rate and pressure measurements impractical.
• Figure 2 shows a first embodiment of the present invention configured to make flow profile production logging measurements.
• a candidate well could be one that used to produce to surface but no longer does so due to a drop in reservoir pressure over time.
• Production logging measurements can be useful in such cases to identify the zones of the well producing oil (from which production is sought) as opposed to those producing water which may need to be blocked before artificial lift is applied in order for the production to be economically beneficial.
• the well 10 has been drilled down to a producing formation 12 where a series of perforations 14 are provided to allow reservoir fluids to enter the well.
• the system according to an embodiment of the invention comprises a compact ESP 16 that is lowered into the well 10 on a cable 18 until it is above the producing formation 12.
• a control unit 20 is provided at the surface for controlling operation of the system, providing electric power and recording data.
• the ESP is equipped with a sealing device, such as a packer 22 that can be deployed so as to create a barrier between the upper part of the well 10A and the lower part 10B in which the perforations 14 are located.
• a production logging tool 24 such as a flow profiling device is connected to the bottom of the ESP by means of an attachment system 25 and is deployed near to the perforations 14.
• a further flow meter 26 can be provided in the outlet of the ESP 16.
• An inflatable packer is a preferred solution as a sealing device.
• the ESP system in cases where the ESP system is lowered through tubing, it can be equipped with a plug system which sits and seals in the appropriate receptacle of the tubing.
• the sealing device is normally supporting a difference of pressure between its two faces. This pressure difference multiplied by the sealed section generates an axial force: this axial force is often quite large and needs to be properly supported.
• the transfer is often done by slips transmitting the load onto the well bore. This becomes more critical when an inflatable packer is used, and the support structure of ESP is quite limited in load capacity (such as a wireline cable support).
• the ESP is operated to lift fluids from the lower part of the well 1OB, causing fluids to enter the well through the perforations 14.
• the production logging tool can then be used to analyse the flow from various perforations to determine which, if any, produce water and so interfere with valuable production from the well.
• the flow meter 26 provides a total flow from the well and so allows the relative contribution from the logged perforations to be assessed.
• the production logging tool may be moved along the well while making measurements to provide proper discrimination of the inflow.
• the whole system may be moved to another location in the well by deflating the packer 22 and moving the system to another location by raising or lowering the cable 18. At the end of the operation, the whole system can be removed from the well so that well interventions can be performed and a conventional ESP installed.
• the production logging tool may be moveable in the well independently of the ESP 1 to limit the number of setting and unsetting operations of the packer.
• the logging tool can be attached in the well via a system which can extend and retract.
• the attachment system can comprise a telescopic structure or a support tube sliding in a seal where it connects to the ESP. If the well is sufficiently vertical, gravity may be sufficient to pull the logging tool downwards.
• the ESP discharge pressure can be an effective generator of movement when applied on these types of extending structure.
• the retraction of the logging tool can be performed by an elastic system which pulls the logging tool back towards the ESP. Typically the ESP has to be stopped (or operating at low speed) so that the discharge pressure is low enough to allow the retraction. With such a combination, multiple passes of logging can be performed without unsetting the packer and moving the ESP system.
• Another combination is to use gravity to ensure the downwards movement of the logging tool via the "fixed" ESP 1 when the ESP is not delivering significant pressure. Then the upwards movement can be achieved by means of the ESP discharge pressure applied to a piston and cylinder combination associated with the extension mechanism.
• a braking system can be associated to limit the displacement speed when performing the logging.
• the speed may be controlled by the logging tool.
• a module may be added to allow the measurement of the distance between the ESP and the logging tool. This measurement may be performed by the logging tool: it can be based on direct measurement of the distance tracking the extension of the support, or by a wheel rolling on the casing, or by cross-correlation of a formation or borehole measurement such as natural gamma-ray, etc.
• Figure 3 shows a second embodiment of the invention configured for well testing applications (parts that correspond with those of the embodiment of Figure 2 are given the same reference numbers).
• the system is configured to create pressure perturbations in the well.
• the packer 22 seals the upper part of the well 1OA from the lower part 10B.
• a second packer 28 (preferably inflatable) is provided some distance below the ESP 16 so as to isolate the interval of interest 1OB from the remainder of the well 10C.
• a pressure sensor 30 is provided on the ESP to measure the pressure in the interval 10B
• the packers 22, 28 are set on either side of the interval of interest 10B and the ESP 16 operated. This has the effect of producing a given pressure drop in the interval 10B.
• the pressure response of the formation over time can be measured using the pressure sensor 30.
• a valve 32 is provided in the outlet of the ESP 16 so as to prevent flow through the ESP, and a flow redirector 34 with a corresponding valve is provided below the packer to redirect flow into the interval when the valve 32 is closed.
• valve 32 can be operated electrically. Control from surface allows appropriate setting of the valve.
• Valve 34 can be operated in conjunction with valve 32, so that it opens at the moment that valve 32 closes. It can also be set to open when the discharge pressure of the ESP reaches a certain value.
• Figure 4 shows plots of flow rate and interval pressure for a first test.
• the ESP 16 is operated at a set speed (flow rate q) until a steady state pressure p is obtained. At this point, flow through the ESP is stopped, for example by closing the valve 32 and redirecting the flow from the ESP 16 back into the interval 1OB, and the pressure change monitored, the pressure p rising until it reaches the natural formation pressure.
• the shape of the pressure curve as the pressure p falls and rises can be used to analyse the formation for production enhancement possibilities. This sequence can be repeated several times to improve measurement accuracy.
• Figure 5 shows plots of flow rate and interval pressure for a second test.
• the speed/flow rate of the pump 16 is modulated by An appropriate amount, for example up to 10% or 20%.
• the pump speed can be reduced and/or the valve 32 operated to achieve the flow perturbation.
• the flow is restored to its original level before the interval reaches equilibrium and is again reduced when it has regained it original level.
• This modulation can be repeated over a period of time to make several measurements.
• the periods of the regular and reduced flows can be selected to ensure that the formation is maintained in its transient state and allow its response to be evaluate effectively.
• pressure and flow rate measurements can be made at the same time, or sequentially, if the ESP is equipped with both sets of sensors. Also, the timing of the overall test, period of modulation, level of modulation, etc. can be changed to assess different formation properties.
• Another operation that can be performed with an embodiment of the invention is to restart production from a low pressure well.
• the formation pressure is only just enough to produce formation fluids to the surface.
• water can accumulate in the well (being denser than oil) so as to produce a hydrostatic column that is denser than that obtained when oil and gas are being naturally produced.
• a common technique to restart such production is to inject nitrogen to reduce the density of the column and allow production to restart.
• the ESP can be operated until the water column is produced to the surface and the normal, self-sustaining multiphase flow established. At this point, the ESP can be stopped and withdrawn from the well, its compact size allowing standard pressure control equipment to be used and so avoid having to shut in the well to remove the ESP.
• the inflation of the inflatable packer can be driven by the discharge pressure of the ESP.
• the combination of valve 32 and 34 ensures predictable inflation, as they can be closed during inflation.
• a additional valve (not shown) could be added to the short line connected to the inflatable packer: after inflation, this valve can be close to keep the inflation at the proper level.
• An ESP system of the type described above, associated optionally with packer(s) and a bridge plug, such as flow valves (32, 34) can also be lowered in the well at the bottom of tubing (or coiled tubing). This would give all possibility as described previously.
• Figure 6 shows an embodiment of the invention deployed at the bottom of tubing 40.
• the cable 18 can be lowered inside the tubing 40 (and not outside as conventional ESP installation). In this case, the cable 18 is lowered inside the tubing 40 after installation of the ESP at the required depth.
• a down-hole cable latching connector 42 is used to connect the cable 18 to the ESP 16.
• the ESP can be mounted upside down in the well (i.e. it sucks fluid from above and pushes it downwards).
• An inflatable packer can again be used to separate the discharge form the suction.
• the ESP can be installed above a layer of the formation that is in communication with the well-bore so that its discharge can generate fracture in the rock.
• the ESP can be supported by a wireline cable or tubing or coiled tubing.
• This embodiment can be useful for characterizing the fracturing parameters of the rocks, as well as performing fracturing requiring limited amounts of proppant or no proppant at all.
• the ESP with packer(s) can be associated with a perforation system (perforation gun).
• perforation gun perforation gun
• the perforation system is located below the ESP and its packer.
• the packer is set, the ESP is activated to generate a low pressure around the perforation gun. Then the gun is triggered. This allows performance of under- balance perforation, without the need to change the well-bore fluid.
• a small diameter ESP can be lowered in production tubing above a normal ESP. It normally is equipped with a packer and is suspended on a wireline cable.
• the small, temporary ESP can be activated when the normal ESP is static, allowing production. This mode of production can useful during a proppant flow back period to limit damage in the main ESP. The same operation can also be useful when the main ESP cannot operate properly but production is to be maintained until work-over can be performed.
• the provision of the main ESP with by-pass system can help the performance of this operation.

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• Environmental & Geological Engineering (AREA)
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• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Structures Of Non-Positive Displacement Pumps (AREA)
• Control Of Non-Positive-Displacement Pumps (AREA)
• Measuring Fluid Pressure (AREA)

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• 2008
  • 2008-02-27 RU RU2010139409/03A patent/RU2469182C2/ru active
  • 2008-02-27 WO PCT/RU2008/000106 patent/WO2009113895A1/en active Application Filing

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