WO2021042205A1 - Systèmes et procédés de régulation de pression entre tubage - Google Patents

Systèmes et procédés de régulation de pression entre tubage Download PDF

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Publication number
WO2021042205A1
WO2021042205A1 PCT/CA2020/051190 CA2020051190W WO2021042205A1 WO 2021042205 A1 WO2021042205 A1 WO 2021042205A1 CA 2020051190 W CA2020051190 W CA 2020051190W WO 2021042205 A1 WO2021042205 A1 WO 2021042205A1
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WIPO (PCT)
Prior art keywords
pressure
brine
annulus
pressurizing unit
cement
Prior art date
Application number
PCT/CA2020/051190
Other languages
English (en)
Inventor
Stanley LAMASCUS
Malcolm THORBURN
Colin COTTRELL
Original Assignee
Inter-Casing Pressure Control Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Inter-Casing Pressure Control Inc. filed Critical Inter-Casing Pressure Control Inc.
Priority to US17/753,467 priority Critical patent/US20220341298A1/en
Priority to CA3152194A priority patent/CA3152194A1/fr
Publication of WO2021042205A1 publication Critical patent/WO2021042205A1/fr

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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
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure

Definitions

  • the invention relates to the control and/or reduction of undesirable and dangerous buildup of formation gases and fluids in the annular space between casing strings in an oil & gas well.
  • ICP Inter-Casing Pressure
  • SCP sustained casing pressure - SCP
  • HSE Health, Safety and Environmental
  • a barite is a plug made from barite weighting materials that is placed at the bottom of a wellbore. Unlike a cement plug, the settled materials do not set solid, yet a barite plug can provide effective and low-cost pressure isolation. A barite plug is relatively easy to remove and is often used as a temporary facility for pressure isolation or as a platform enabling the accurate placement of treatments above the plug.
  • Cement plugs have also been used to prevent the buildup of formation gases and fluids.
  • a process comprising: injecting brine comprising cesium formate into a cement annulus between concentric well casings; monitoring the pressure of the brine within the annulus; and controlling the flow rate of the brine being injected based on the monitored pressure.
  • the pressure of the brine within the annulus may be measured by electronic pressure gauges at the well head.
  • a measure of the pressure of the brine within the annulus may be obtained by measuring the pressure applied to the brine within the annulus. For example, the pressure may be taken in the treatment line in direct fluid communication with the annulus (e.g. after a pressure intensifier or after a release valve).
  • the density of the brine may be greater than 1 8g/ml.
  • the density of the brine may be greater than 1.2g/ml.
  • the density of the brine may be less than 2.7g/ml.
  • the flow and pressure of the injected brine may be controlled using an air pump (or another suitable pump).
  • the pump may be chosen to meet specific calculated well treatment needs (e.g. higher volume flow rate than normal, operational limitations dictated by site location, better control of injection and bleed cycles) and/or site safety requirements or regulations.
  • a mechanical pump that will be able to reach the pressure that will be required (+ 4,500psi) is generally a plunger style pump or a hydraulic vane style pump. Both styles of pumps require substantially more power and electronic controls to operate at a very slow speed. As the apparatus may be working in remote areas without power available a mechanical pump would require substantially more power generation to be available on the location which could become cost prohibitive. Also, the cost of the electronic control systems that would be required for these pumps may be cost prohibitive and maintenance intensive. In addition, using such mechanical pumps may often result in surge pressure being induced on the annulus which we are trying to avoid so as not to pack off any particulate matter resident in the cement annulus. [0011] The brine may be injected using a treatment line, wherein the treatment line includes at least one one-way check valve to prevent fluids escaping from the annulus via the treatment line.
  • the process may comprise injecting brine into multiple cement annuli in the same wellhead.
  • the process may comprise switching brine injection between multiple cement annuli.
  • the brine being injected may also be of varying densities and pH levels dictated by conditions on the well annulus being treated.
  • the process may comprise adjusting the brine density and/or brine pH levels based on the condition of the well annulus.
  • the process may comprise ramping up the pressure of the brine within the annulus to a predetermined pressure over the course of between eight hours to five or more days.
  • the process may comprise venting gas from the cement annulus.
  • the process may comprise bleeding fluids (e.g. liquids) from the cement annulus.
  • the process may comprise cycling between bleeding fluids from the annulus and injecting brine.
  • the process may comprise: measuring the volume of liquid and/or gas being ejected from the annulus.
  • the process may comprise: measuring the density of the fluid being bled from the annulus; and stopping the bleeding when the density exceeds a predetermined threshold (e.g. 1.25 sg).
  • a predetermined threshold e.g. 1.25 sg.
  • the fluid being ejected from the annulus may be caught in a, fluid sampling system (e.g. suitably pressure certified (such as: up to 3,000psi)) for recovery and investigation during the bleeding process.
  • the process may comprise: analyzing the chemical composition of the fluid or gas being bled from the annulus; and stopping the bleeding based on predetermined criteria (e.g. the concentration of cesium formate exceeding a predetermined threshold).
  • predetermined criteria e.g. the concentration of cesium formate exceeding a predetermined threshold.
  • the process may comprise: injecting the brine into the cement annulus to reach an initial predetermined pressure using a first injecting apparatus; and once the initial predetermined pressure is reached, injecting the brine into the cement annulus to maintain a steady-state predetermined pressure using a second injecting apparatus.
  • the initial predetermined pressure may be greater than 2,000psi.
  • the initial predetermined pressure may be greater than 4,000psi.
  • the initial predetermined pressure may be less than 6,000psi.
  • the initial predetermined pressure may be less than 10,000psi.
  • the steady-state predetermined pressure may be substantially equal to the initial predetermined pressure.
  • the injection of the brine into the cement annulus to reach an initial predetermined pressure may increase the pressure monotonically. For example, once injection has commenced, the pressure should not decrease. This may help ensure that blockages do not form within the fissures in the cement annulus.
  • the injection of the brine into the cement annulus to reach an initial predetermined pressure may increase the pressure linearly with time.
  • the injected brine may be monovalent.
  • each of the ions (cations and anions) in the brine may have a charge of ⁇ 1.
  • the brine may comprise element ions from group 1 and/or group 17 in the periodic table of elements.
  • the process may comprise filtering the brine to less than 2 microns prior to injection.
  • the filtration may use a filter with 2 microns holes (e.g. a 2-micron weaved stainless steel filter).
  • the process may comprise filtering the brine to less than 10 microns.
  • the brine may be injected at less than between 1 to 40 litres/hour.
  • Production from the well may continue during the brine injection.
  • the process may comprise monitoring the ambient temperature at the well site.
  • the process may comprise heating the brine being injected based on the ambient temperature at the well site.
  • the process may comprise, prior to injecting the brine: measuring the pressure in the annulus; removing fluid from the annulus until a predetermined pressure is reached; and determining the rate of increase of pressure; and controlling the rate of brine injection based on the determined rate of increase of pressure.
  • the brine may be injected using a treatment line; and the process may comprise sealing the well head when the monitored pressure reaches a steady state without further injections of brine.
  • the brine may be injected using a treatment line; and the process may comprise monitoring the temperature of the treatment line and heating the treatment line when the treatment-line temperature falls below a predetermined threshold.
  • a process comprising: injecting brine comprising cesium formate into a cement annulus between concentric well casings.
  • an apparatus comprising: an annulus connector configured to connect to a cement annulus between concentric well casings; and a pressurizing unit configured to inject brine into the cement annulus between concentric well casings via the annulus connector.
  • the annulus connector may be configured to connect at the top of the annulus.
  • an apparatus comprising: an annulus connector configured to connect to a cement annulus between concentric well casings; a pressurizing unit configured to inject brine into the cement annulus between concentric well casings via the annulus connector; and a pressure monitor configured to monitoring the pressure of the brine within the annulus; and a controller configured to control the pump to control the flow rate of the brine being injected based on the monitored pressure.
  • the annulus connector may be ring-shaped to allow production to continue through the hole in the ring connector while brine injection is ongoing.
  • the apparatus may comprise: a dynamic pressurizing unit comprising a pump; and a passive pressurizing unit comprising a reservoir configured to hold a volume of brine at an elevated pressure and a passive-pressurizing-unit release valve configured to deliver brine under pressure to the cement annulus between concentric well casings.
  • the dynamic pressurizing unit may be configured to elevate the pressure within the passive pressurizing unit reservoir.
  • the dynamic pressurizing unit may be configured independently to enable delivery of brine under pressure directly to the cement annulus between concentric well casings.
  • the apparatus may comprise a treatment line between the pressurizing units and the cement annulus, the treatment line having one or more one-way valves configured to prevent retrograde flow from the cement annulus.
  • the apparatus may comprise a treatment line between the pressurizing units and the cement annulus, the treatment line having one or more pressure regulators.
  • the apparatus may comprise a dynamic pressurizing unit configured to generate pressure (e.g. using a pump).
  • the dynamic pressurizing unit may be Pressure Assisted Displacement Treatment System (PADTS).
  • PADTS Pressure Assisted Displacement Treatment System
  • the apparatus may comprise a passive pressurizing unit configured to store and release brine under pressure.
  • the passive pressurizing unit may comprise or be an Accumulator Containment Unit (ACU).
  • the dynamic pressurizing unit and/or passive pressurizing unit shells may be of steel construction with insulation which renders them suitable for a wide range of temperatures from -40C to +50C.
  • the dynamic pressurizing unit and/or passive pressurizing unit shells may be designed, built and certified for use in a Zone 1 Division 1 environment including all lighting, electrical and electronics installed.
  • the dynamic pressurizing unit and/or passive pressurizing unit shells may be designed for either on or offshore applications and are custom designed specifically for the operation.
  • the dynamic pressurizing unit may use a high-pressure low flow capable air pump used to both charge the accumulators in the passive pressurizing unit and for use in the initial treatment for the well prior to instituting the slow feed process using the stored hydraulic energy in the passive pressurizing unit.
  • the air pump may be used in conjunction with a hydraulic intensifier.
  • a hydraulic intensifier may comprise a: fixed ram, a hollow inverted sliding cylinder, and a fixed inverted cylinder.
  • the hydraulic intensifier may have a fixed ram through which the brine, under a high pressure, flows to the wellhead.
  • a hollow inverted sliding cylinder, containing brine under high pressure, is mounted over the fixed ram.
  • the inverted sliding cylinder is surrounded by another inverted fixed cylinder which contains air from the air pump at a lower pressure.
  • the dynamic pressurizing unit may have both electronic pressure gauges and manual charts for recording and storing system pressure tests.
  • multiple (e.g. up to 5 or more) passive pressurizing unit’s may be mounted on and become an integral part of the dynamic pressurizing unit.
  • Gauges relating to the passive pressurizing unit may be installed in the passive pressurizing unit for high visibility during treatment or may be easily transferred into the interior mounting bracket on the passive pressurizing unit when it is left to operate remotely on a well site.
  • All electronic gauges may have a built-in data logger function. All electronic gauges may be configured to operate independently for up to six months on internal power and record up to 1,000,000 data points or more in storage.
  • Electronic pressure gauges may monitor ambient temperature around units.
  • the apparatus may have a secondary heating system configured to heat the brine being injected based on the ambient temperature.
  • the system may be mobile.
  • the system may comprise: a skid mounting assembly for supporting the apparatus; a generator and an air compressor.
  • All connections on fluid treatment lines may comprise quick connect type couplings that will not leak fluid when being connected.
  • Manifolds used in connecting treatment lines to the wellhead are custom designed.
  • N2 gas connection manifold on top of the accumulators are custom designed.
  • the custom manifolds allow for the simultaneous attachment of a manual pressure gauge, an electronic pressure gauge and a port to be used in recharging the internal bladder with nitrogen as required.
  • Electronic pressure gauges may be used to monitor one or more pressures on the units such as:
  • All electronic gauges may have manual back up conventional gauges to check and confirm pressures.
  • the apparatus or system may comprise a power generator.
  • the apparatus or system may comprise a renewable power generator (e.g. one or more of a solar panel and a wind turbine).
  • the brine may comprise potassium formate.
  • the brine may consist of cesium formate, potassium formate and water (e.g. where other materials in the brine account for less than 5% by weight).
  • the process may be conducted while surface temperatures range between -40°C up to +50°C.
  • the apparatus may be configured to operate in the temperature range of 40°C up to +50°C.
  • the apparatus may have a secondary heating system to maintain treatment line temperatures above -10°C. This may help to prevent crystallization of the fluid being injected into the well bore.
  • An advantage of using cesium formate is its stability in high temperature and high-pressure environments.
  • the apparatus and process may be used where you have a pressure in a relatively closed cement environment, caused by gas or a liquid.
  • the pressure may be controlled using hydrostatic force of a fluid to restrict or eliminate any influx into this environment.
  • the apparatus and process may also be used to control pressure in a cement annulus that has been caused by an ineffective cementing operation on the production casing string that has high inter-casing pressure (e.g. which is considered unsafe to run completion operations to bring the well online and produce oil and gas from the well).
  • the apparatus may be configured to switch between the dynamic pressurizing unit and the passive pressurizing unit based on the monitored pressure.
  • the dynamic pressurizing unit may be releasably attached to the apparatus. For example, when the passive pressurizing unit is being used to inject brine, the dynamic pressurizing unit may be removed.
  • the passive pressurizing unit may be releasably attached to the apparatus. This may allow the passive pressurizing unit to be replaced when one passive pressurizing unit is exhausted.
  • the compression reservoir may be releasably attached to the passive pressurizing unit to enable replacement.
  • the apparatus may comprise multiple passive pressurizing units.
  • the injection brine or fluid may be filtered to less than 2 microns to allow it to easily flow down micro- fissures in the cement.
  • the micro- fissures may have been created over time in the cement column or as a result of:
  • the injection brine or fluid may be non-corrosive, non-toxic and suitable for high pressure (e.g. up to 6,000psi) and/or high-temperature (e.g. up to 150°C) environments.
  • the fluid injection brine or fluid may be pumped and injected at low flow rates, (e.g. below 15 litres/hour). This may help prevent any material bridging or packing off in (e.g. blocking) the annulus flow path. This may help ensure that the brine can penetrate more fully into any fissures in the annulus cement.
  • the present process may not require any mechanical intervention in the annulus or well.
  • the present process may operate in parallel with well production.
  • the present process may reduce annulus pressure induced by high temperatures within the annulus (if present).
  • the present process may be considered to use the application of hydrostatic pressure being generated by the heavy cesium formate brine as it is drawn into the well caused by the effects of gravity.
  • the present process may be configured to use a remote automatic slow fluid feed system on the wellhead to continuously inject a heavy cesium formate brine solution into the cement annulus on an oil and gas well over an extended period of time.
  • An extended period of time may be 2 days or greater.
  • the ability to inject fluid into the cement annulus at a controlled slow rate may reduce or eliminate the potential for blockages to be created in the cement micro annulus voids and slowly allow the pressure to be increased over a long period of time.
  • the apparatus may be configured to monitor pressure on all pressure points in the system with electronic gauges and read and record the stored pressures as required directly from the unit’s sensors into a portable device even when in a zone 1 division 1 ambient environment (e.g. a location where the hazardous atmosphere is expected to be present during normal operations on a continuous, intermittent or periodic basis). Once data has been downloaded it can be organized into a graph style presentation to effectively show treatment progress in relationship to flow and pressure into cement annulus. 10076] Treatment time and pressure records may be monitored to confirm pressure control of annulus pressure(s) on wells over an extended time periods and/or for the commercial lifetime of the well. Well pressure data may be used by government regulators and authorities to show the wells are being operated within acceptable pressure limits.
  • the apparatus may be configured to transmit data to a remote computer to provide a remote indication of annular pressure re-occurrence.
  • the fracture gradient may be considered to be the factor used to determine formation fracturing pressure as a function of well depth in units of psi/ft.
  • the fracture gradient in units of psi per foot is the fracture pressure in psi divided by the vertical depth of the fracture below the rig floor in feet.
  • a casing assembly may comprise a series of concentric casings. Typically, the casings which are towards the centre of the wellbore are longer and penetrate further into the ground from the surface than casings which are further away from the centre.
  • a casing string is a pipe which is run into the wellbore and which is typically cemented in place.
  • a casing assembly may comprise one or more of:
  • a production casing which may be cemented to stop oil migrating to thief zones and to prevent formation degradation which may cause loss in productivity.
  • the production casing may be the longest and smallest-diameter casing.
  • an intermediate casing which may be configured to isolate formations. There may be several intermediate casing strings. The intermediate casing may be shorter and wider than the production casing.
  • the surface casing may be shorter and wider than the intermediate casing and/or the production casing.
  • a conductor casing which may be configured to prevent drilling fluids circulating outside the casing, causing surface erosion.
  • the conductor casing may be shorter and wider than the surface casing, the intermediate casing and/or the production casing [0084]
  • the regions between the concentric casings form annuli which are filled with cement.
  • a Christmas tree may be considered to be an assembly of valves, spools, pressure gauges and chokes fitted to the wellhead of a completed well to control production
  • a casing bowl may be considered to be a wellhead component, or a profile formed in wellhead equipment in which the casing hanger is located when a casing string has been installed.
  • the casing bowl incorporates features to secure and seal the upper end of the casing string and frequently provides a port to enable communication with the annulus.
  • a casing shoe may be considered to be the bottom of the casing string, including the cement around it, or the equipment run at the bottom of the casing string.
  • Cesium formate is a neutral to slightly alkaline salt of cesium hydroxide and formic acid having the formula HCOO CsT It is extremely soluble in water.
  • An 82 wt.% cesium formate solution has a density of 2.4 g/cm 3 . It has shown favorable health, safety and environmental (HSE) characteristics in laboratory tests and has applications as a drill-in, completion or workover fluid.
  • Cesium formate may be mixed with less expensive potassium formate to make clear brine mixtures with a density range from 1.6 to 2.4 g/cm 3 . Formates have temperature stability up to around 190°C, depending on the duration of exposure to such a temperature.
  • a brine is a high-concentration solution of salt in water.
  • Cesium formate brine may be an aqueous solution of Cesium formate salt.
  • FIG. 1 is a schematic of the entire brine injection apparatus according to the present disclosure.
  • FIG 2 is a schematic of a dynamic pressurizing unit which is a Pressure Assisted Displacement Treatment System (PADTS).
  • PADTS Pressure Assisted Displacement Treatment System
  • FIG 3a is a schematic side-view of a passive pressurizing unit which is an Accumulator Containment Unit (ACU).
  • ACU Accumulator Containment Unit
  • Figure 3b is a schematic top-view of a gauge manifold which is part of the passive pressurizing unit of figure 3a.
  • Figure 3c is a schematic side-view of a pressure flow regulating assembly which is used in conjunction with the passive pressurizing unit of figure 3a.
  • Figure 4 is a side view of the wellhead assembly.
  • Figure 5 is a schematic top-view of the connectors to the wellhead assembly.
  • Figure 6 is a flow diagram of the method of inject brine comprising cesium formate into a cement annulus according to the present disclosure.
  • the present disclosure describes using a dynamic bleed and lube process that will use hydraulic pressure to continuously, gently and automatically inject a high-density cesium formate brine solution into the cement sheath within an inter-casing annulus.
  • the fluid can flow into small fissures in the cement sheath displacing fluids (e.g. liquid and/or gases) as it flows. Once the fissures are filled with brine, further influx of fluids may be prevented. This may help increase the hydrostatic force in the well bore, stop the continued influx of oil and gas into the cement annulus and/or buffer the corrosive nature of H 2 S and C0 2 present in the cement sheath.
  • the present process uses a monovalent heavy cesium formate brine to create hydrostatic pressure in the cement annulus which will reduce the influx of fluids into the cement annulus from below and after a period of time reach a balance point which will, over time result in a substantial reduction of previously recorded pressure.
  • Perforating the production casing may result in a loss of well bore integrity as the production casing is the primary structure in the well bore. Once the casing is perforated the it may be necessary to apply a steel sheath on the inside of the casing to restore well bore integrity. However, the costs of this type of remedial action can render this process unfeasible.
  • Any cement slurry is a multi-valent mix that may mix with any remaining particulate matter in the cement sheath which will severely restrict its movement inside the cement sheath.
  • the cement is multi-valent and will mix with any residual fluid or particulate matter present in the cement sheath which will restrict the depth this solution will be able to react in the cement sheath.
  • polymers are multi-valent and will mix with any residual fluid or particulate matter present in the cement sheath which will restrict the depth this solution will be able to react in the cement sheath.
  • the brine solution containing zinc bromide was found very toxic to aquatic life with long lasting effects.
  • Zinc bromide is an HSE risk to humans.
  • Zinc Bromide solution may be harmful if swallowed; cause severe skin burns and eye damage; cause an allergic skin reaction; be toxic to aquatic life with long lasting effects; and be extremely corrosive to both metals and rubber products.
  • the zinc solution is a multivalent chemical solution that may combine with fluid and particulate matter in the cement sheath which limits its ability to travel deep enough in the cement sheath to have a reasonable chance of being an effective treatment.
  • an analysis of the well may be done to establish whether the well is a valid candidate for this treatment which will help the operator identify other potential problems if it is deemed not to be a candidate.
  • Each well may be individually assessed regardless of its proximity to other wells which may be under treatment process. During this process attempts must be made to try and identify the source of the influx.
  • the analysis may include:
  • Good candidate wells for this process may include one or more of the following:
  • Poor Candidate Wells may include one or more of the following:
  • the cemplete apparatus accerding te the present disclesure is cenfigured te deliver brine under pressure te at least ene inter-casing annulus and tc remcve gas and/cr ether fluid deciding the inter-casing annulus.
  • Figure 1 is a general schematic cf the entire apparatus 100.
  • PTM Primary Treatment Manifcld
  • PADTS Pressure Assisted Displacement Treatment System
  • the apparatus ccmprises a dynamic pressurizing unit 210 which is a Pressure Assisted Displacement Treatment System (PADTS).
  • PADTS Pressure Assisted Displacement Treatment System
  • the dynamic pressurizing unit 210 comprises a pump 214 which, in this case, is an air pump for applying pressure (up to +4,500psi) to the brine to be injected into at least one annulus.
  • a pump 214 which, in this case, is an air pump for applying pressure (up to +4,500psi) to the brine to be injected into at least one annulus.
  • the air pump 214 applies pressure to the brine from the reservoir via a hydraulic pressure intensifier 216.
  • a hydraulic pressure intensifier 216 may be used in the brine line to draw fluid in from the reservoir 201 (which may be unpressurized) and then allow pressure to be applied into either the inter-casing annulus or the passive pressurizing unit 220.
  • the outlet pressure is calculated by the transmission ratio between air piston and plunger piston multiplied by the drive pressure.
  • the static ultimate pressure and flow may be adjusted and controlled by the regulation of the air supply pressure.
  • the brine solution is fed into the hydraulic pressure intensifier 216 under atmospheric pressure which is intensified gradually up to the required treatment pressure at a control rate.
  • the dynamic pressurizing unit 210 is configured to receive brine from a brine reservoir 201 for injection into at least one annulus and is configured to pressurize this brine in a controlled manner. It may also allow the pressure on the cement annulus to be increased gradually to help limit the possibility of packing off due to residual matter left in the cement string.
  • a fluid return allows excess brine to be returned to the brine reservoir 201.
  • the dynamic pressurizing unit 210 has two purposes in this operation:
  • the dynamic pressurizing unit 210 is configured to directly pump brine through the passive pressurizing unit manifold (330 Figure 3a) into the at least one annulus via the wellhead. That is, pressure delivered by the pump is applied to fluid which is moved directly into the at least one annulus.
  • the dynamic pressurizing unit is configured to pressurize the brine into an accumulator of a passive pressurizing unit 220 which stores the brine under pressure.
  • the brine can then be slowly released from the accumulator even when the dynamic pressurizing unit pump is not running. This may reduce energy consumption of the apparatus as it runs over an extended period of time (e.g. days, weeks or months).
  • the dynamic pressurizing unit 110, 210 is connected to the Primary Treatment Manifold 140, 240 by three lines: a high-pressure treatment line 113, 213; a pressure bleed line 112, 212 and an air purge line 211,111.
  • the air purge line has a valve 215.
  • the high-pressure treatment line 113, 213 is pressurized directly by the action of the air pump 110 acting on the brine in the dynamic pressurizing unit 110, 210.
  • a pressure bleed line is configured to return fluid from the Primary Treatment Manifold back to the dynamic pressurizing unit. The return line may be used to minimize the potential loss of the treatment fluid as pressure must be released to allow for disconnect of any pressure lines.
  • the air purge line 111 , 211 may be used to vacate fluid from lines for preparation of moving the units between well sites to prevent any loss of treatment fluid.
  • the Primary T reatment Manifold 140, 240 is configured to connect to the wellhead connection assembly 170, 270 via a quick connector 242.
  • a one-way valve is located in the feed line to prevent retrograde fluid flow from the wellhead connection assembly 170, 270 to the Primary Treatment Manifold 140, 240.
  • the dynamic pressurizing unit 110, 210 is configured to monitor pressures and flows using the electronic gauges (which may be intrinsically safe) while injection is in progress which allows for careful control during this operation and a record for review at any time after the job is complete. Gauges may each be independently set to monitor and record at different intervals.
  • Gauge data is easily and quickly downloaded by wireless transmission into an intrinsically safe tablet where data can be stored and easily transferred between users and computers as required.
  • All pressure hose connections used to transfer fluid or pressure are of a type which reduce any potential for accidental spillage, or loss of, the treatment fluid.
  • the connections in this case are a high pressure (10,000psi rated) hydraulic quick couplings which may have a secondary seal which is engaged prior to the screw collar is tighten which release the flow pins and allows fluid to pass through the hoses. Once the screw collar is tightened the primary seal is engaged on the unit. Any hose containing treatment fluid makes use of this type of connection, regardless of size, to reduce the chance of accidental spillage.
  • the treatment lines are equipped with multiple safety barriers such as one-way check valves and ball valves (all rated to a minimum of 6,000psi which is the pressure rating of all fluid hoses being used) to help ensure that fluids cannot escape from the wellhead into the environment or get back into, and damaging, either the dynamic pressurizing unit or passive pressurizing unit.
  • safety barriers such as one-way check valves and ball valves (all rated to a minimum of 6,000psi which is the pressure rating of all fluid hoses being used) to help ensure that fluids cannot escape from the wellhead into the environment or get back into, and damaging, either the dynamic pressurizing unit or passive pressurizing unit.
  • All connections and manifolds, in this embodiment, are made with grade 304 stainless steel (minimum) to help ensure safe use in possible hhS environments.
  • ACU Accumulator Containment Unit
  • the apparatus 100 also comprises a passive pressurizing unit 120, 220, 320 (or Accumulator Containment Unit - ACU) comprising a reservoir 321 configured to hold a volume of brine at an elevated pressure and a release valve 330 configured to deliver brine under pressure to the cement annulus between concentric well casings.
  • the passive pressurizing unit 120, 220, 320 forms part of the dynamic pressurizing unit 110, 210.
  • the passive pressurizing unit 320 comprises a compression reservoir 321 which is configured to receive pressurized flow 338 from the pump of the dynamic pressurizing unit to charge the reservoir 321.
  • the pressure flow from the dynamic pressurizing unit is delivered via a hydraulic quick-release coupling 326.
  • the pressure flow from the dynamic pressurizing unit is delivered to the compression reservoir via a fluid manifold 330, an isolation valve 323 and a compression reservoir connection assembly 322.
  • Connected to the compression reservoir is a gauge manifold 329 to allow for a manual pressure gauge 329a, an electronic pressure gauge 329b and a nitrogen charge point 329c (see figure 3b).
  • the bladder inside the accumulator is charged to a predetermined set value using nitrogen through connection point 329c.
  • the system also comprises two pressure gauges connected to the fluid manifold: an electronic gauge 324 and a manual gauge 325.
  • the isolation valve 323 is closed isolating the compression reservoir 321 from both the pump of the dynamic pressurizing unit and the inter-casing annulus.
  • brine 337 is actively pumped from the dynamic pressurizing unit into the annulus via a pressure flow regulating assembly 328 and a primary treatment manifold. This ramps up the pressure within the annulus slowly.
  • the pressure flow regulating assembly 328 is shown in figure 3c and comprises: a hydraulic coupling 331; a pressure regulator 332; a pressure gauge 333, a one-way check valve 334 and a second hydraulic coupling 335 for connection to the primary treatment manifold. In this way flow 337 is directed to the primary treatment manifold.
  • the line between the hydraulic coupling 331 (which connects to the pressurizing units) and the wellhead connector may be considered to be the treatment line.
  • the one-way check valve is configured to prevent retrograde flow from the annulus back into either the passive or dynamic pressurizing units.
  • the dynamic pressurizing unit is turned off and isolated from the pressure flow regulating assembly.
  • the dynamic pressurizing unit isolation valve 323 is opened to allow regulated flow from the compression reservoir 321 into the inter-casing annulus.
  • FIG 4 is a side view of the wellhead assembly 471.
  • the well itself comprises a series of concentric tubes and casings.
  • the production casing 486 is hung off the wellhead flange 490 (or Internal Production Casing Spool) and cemented.
  • tubing 485 which is hung of the top 491 of the wellhead (from a tubing hanger) and is configured to transport oil and/or gas from the well up into the Christmas Tree (an assembly of valves, spools, pressure gauges and/or chokes fitted to the wellhead of a completed well to control production).
  • the wider and shorter intermediate casing 487 string which is suspended from a wellhead flange and cemented.
  • Outside the intermediate casing is the even wider and even shorter surface casing 488 which is cemented into the well with a casing bowl attached.
  • inter-casing annulus Between each casing pair, there is an inter-casing annulus.
  • the Christmas tree in this case comprises a lower master valve 492, an upper master valve 493, a swab valve 494, a wing valve 495 and a production choke 496 where production flow 497 is controlled.
  • Other configurations may also be used.
  • each brine injection valve 478, 489 is in fluid communication with a ring-shaped connector which facilitates injecting the brine into the respective annulus.
  • a ring-shaped connector which facilitates injecting the brine into the respective annulus.
  • there is also no fluid communication between the annuli and the production tubing i.e. each annulus is isolated from the production tubing. This means that it is not necessary to seal off the central production casing or tubing while brine is being injected into one or more of the annuli.
  • the wellhead connection assembly there are two configurations for the wellhead connection assembly.
  • the wellhead 571 is connected to the pressurized fluid source 584 via a wellhead manifold 577.
  • a one-way valve 583 in this case a stainless steel 1 ⁇ 2-inch check valve
  • valves 578, 579 between the wellhead 571 and the wellhead manifold 577 there are two valves 578, 579 (using two valves is an industry standard to allow for a failure of one valve).
  • there is also an additional ball valve 560 e.g. a stainless steel 1 ⁇ 2-inch ball valve
  • the pressure gauge line also includes a ball valve 561 (e.g. a 1 ⁇ 4-inch stainless steel ball valve), a pressure bleed valve 562 (e.g. 1 ⁇ 4-inch) and a hydraulic connector 563 (e.g. 1 ⁇ 4-inch) for connecting to the pressure gauge 581.
  • the gauge assembly may be electronic or conventional.
  • the flare line comprises a series of valves (including pressure bleed needle valve 572 and high-pressure ball valves 570 and 576) to allow the flare line to be opened and closed when fluid is to be extracted from the casing annulus and a visual flow monitor 573.
  • valve 572 may be used to enable samples to be obtained.
  • Needle valve 572 can also be used to capture either gas or fluid samples into pressure bottles. As the fluid from the well is removed a user may be able to visually see what is coming from it which will allow the bleeding of the well to be controlled or stopped and the valve assembly reconfigured to capture fluid or gas samples as required for analysis (e.g. density or chemical analysis). An initial density check may be conducted onsite (with fluid density scale) and a further sample may be retained for laboratory analysis off site.
  • Figure 5 corresponds to the wellhead connection used for initial treatment (i.e. when pressure is being ramped up on the wellhead annulus) and bleed operations (i.e. when fluid is being removed from the annulus).
  • the wellhead is connected to a flare line.
  • the connection to the well is via a single 1 ⁇ 2 inch line. This provides sufficiently large diameter to feed the treatment fluid into the well head when injecting into the cement annulus.
  • access to the annulus may be via two 9/16-inch autoclave fittings on the well head. Therefore, other embodiments may use multiple smaller diameter lines (e.g. two 1 ⁇ 4 inch hoses). The multiple lines may be connected to a larger diameter line (e.g. 1 ⁇ 2 inch line) using a splitter which may be located between valve 577 and the wellhead connector.
  • the hoses being used to attached to the well head along with the valves (e.g. the three innermost valves) on the well head connection block are all rated to 10,000psi.
  • the flare line can be closed using valve 576 and the flare line removed at the connector 574. The flare line can be connected quickly if required.
  • PIDTS Pressure Assisted Displacement Treatment System
  • treatment fluid is slowly injected into the cement annulus being treated and the pressure gradually comes up to the predetermined pressure determined by analysis that was done on the well. For example, on a well (each well will be different) all pressures, in this case, are read from the well head valves:
  • Treatment pressure will be built up over 4 to 8 hours or more if required. Pump time may depend on well conditions.
  • the injection process comprises: injecting brine comprising cesium formate into a cement annulus between concentric well casings; and monitoring the pressure of the brine within the annulus; and controlling the flow rate of the brine being injected based on the monitored pressure.
  • the flow and pressure of the injected brine is controlled using an air pump.
  • the flow and pressure of the injected brine may be controlled by a plunger style pump (or another suitable pump).
  • the choice of pump may depend on meet specific calculated well treatment needs, the safety requirements of the site and/or the site conditions.
  • the density of the brine is greater than 1.8g/ml.
  • the injected brine is monovalent which means that it does not bind easily to substances within the annulus, thereby allowing it to penetrate deeply into fissures in the cement.
  • the brine is filtered than 2 microns prior to injection which may also help the brine penetrate into fissures without blocking them.
  • gas may be continuously or periodically vented from the cement annulus. That is, the process may comprise cycling between bleeding fluids from the annulus and injecting brine.
  • liquid when liquid is bled from the annulus it is analyzed by measuring the density of the fluid being bled from the annulus.
  • the apparatus is configured to allow stopping the bleeding when the density exceeds a predetermined threshold (e.g. 1.25sg) as this may indicative that the injection fluid is being removed from the annulus.
  • a predetermined threshold e.g. 1.25sg
  • the chemical composition of the liquid and/or gas may be analyzed. This can indicate when injection fluid being removed from the annulus.
  • injection of the brine switches from a first injecting apparatus (e.g. the dynamic pressurizing unit) to a second injecting apparatus (e.g. the passive pressurizing unit).
  • the second injecting apparatus is configured to maintain a steady-state predetermined pressure on the annulus.
  • the brine is injected at less than 40 litres/hour (e.g. and/or less than 15 litres/hour).
  • the dynamic pressurizing unit being used to treat the well may be disconnected from the passive pressurizing unit, while the passive pressurizing unit still injects fluid into the well as the treatment fluid drops in the annulus. The dynamic pressurizing unit may then be removed.
  • the pressure on the wellhead may be electronically monitored continuously while the passive pressurizing unit is feeding the well.
  • the apparatus may be configured to stop injection and the passive pressurizing unit may be disconnected from the wellhead. Before removing the pressurizing unit, the treatment line may be sealed when the monitored pressure reaches a steady state without further injections of brine.
  • Pressure can continue to be monitored and pressures recorded for an extended period of time even after removal of the pressurizing units.
  • the “Bleed & Lube” cycle is continued with a controlled annulus pressure bleed off.
  • the removed fluid is analyzed (e.g. by density or chemically). For example, if bled fluid has a density higher than 1.25sg bleeding is to be stopped and more time is given to the well to allow the treatment fluid to fall in the well.
  • the Bleed & Lube cycle may be repeated as needed by well response and the treatment stops when the well pressures are reduced to zero or below a predetermined acceptable safe level.
  • the dynamic pressurizing unit shell and passive pressurizing unit shell may be formed of extruded fiberglass construction materials to reduce weight and eliminate corrosion from the elements.
  • the system may comprise intrinsically safe and battery-powered communications system to upload data from the units to the cloud from remote locations and back to computers in any office worldwide.
  • the system may be configured to provide automatic alerts to predetermined personnel (through a communications system) when key pressure points are reached.
  • the system may be configured to provide remote operation and control (through a communications system) e.g. by predetermined personnel.
  • the system may comprise remote shut down valves that can be activated from a central facility through the cloud when wells are on automatic feed if remote monitoring indicates a problem.
  • the system may be configured to provide long-term pressure monitoring, e.g. via a cloud communication system.
  • the system may be configured to provide to provide remote operation and control of a series of wells with single or multiple pressurizing units installed for long term (e.g. months or years) SAP (Systems Applications and Products) control via a cloud communication system or another electronic communication system.
  • SAP Systems Applications and Products
  • the system may comprise a unit (e.g. which may be mobile) to create cesium formate making use of several new available technologies and using carbon capture as feed stock to create the formic acid to be used in the creation of the cesium formate fluid in local markets to enhance the local content of our operations. This unit may also be used to refurbish cesium formate recovered from a well.
  • the system may comprise a heater that will maintain treatment line temperatures above -10°C to prevent crystallization of the fluid being injected into the well bore.
  • Cesium formate is often used in high temperature and high-pressure wells as a completion fluid due to its stability in this type of environments.
  • each dynamic pressurizing unit may be configured to accommodate multiple (up to five or more) passive pressurizing units.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Processing Of Solid Wastes (AREA)

Abstract

L'invention concerne un appareil et un procédé de régulation et/ou de réduction de l'accumulation indésirable et dangereuse de gaz et de fluides de formation dans l'espace annulaire entre les colonnes de tubage dans un puits de pétrole ou de gaz. Le procédé comprend l'injection d'une saumure de formiate de césium dans un espace annulaire de ciment entre des tubages de puits concentriques ; et la surveillance de la pression de la saumure dans l'espace annulaire. Sur la base de la pression, le débit de la saumure injectée est régulé pour déplacer ou réguler les gaz et les fluides de formation à l'intérieur de l'espace annulaire.
PCT/CA2020/051190 2019-09-04 2020-08-31 Systèmes et procédés de régulation de pression entre tubage WO2021042205A1 (fr)

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US17/753,467 US20220341298A1 (en) 2019-09-04 2020-08-31 Inter-casing pressure control systems and methods
CA3152194A CA3152194A1 (fr) 2019-09-04 2020-08-31 Systemes et procedes de regulation de pression entre tubage

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US201962895635P 2019-09-04 2019-09-04
US62/895,635 2019-09-04

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US20240102358A1 (en) * 2022-09-26 2024-03-28 Saudi Arabian Oil Company Controlling a wellbore pressure

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EP0974731A2 (fr) * 1998-07-11 2000-01-26 Kavernen Bau- und Betriebs GmbH Procédé et dispositif pour l'exploitation par dissolution d'un reservoir incliné
US20040216882A1 (en) * 2002-09-12 2004-11-04 M-I Llc Remediation Treatment of Sustained Casing Pressures (SCP) In Wells with Top Down Surface Injection of Fluids and Additives
US20110247986A1 (en) * 2007-08-02 2011-10-13 M-I Llc Reclamation of formate brines
US20190117339A1 (en) * 2016-01-27 2019-04-25 Marcelo BOLZAN Vibratory intra-oral biofeedback apparatus

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