Patent Publication Number: US-11384622-B2

Title: In situ decontamination of downhole equipment

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     The present application claims priority to U.S. Application Ser. No. 62/325,198, filed Apr. 20, 2016, which is incorporated herein by reference in its entirety 
    
    
     BACKGROUND 
     Subterranean oil recovery operations may involve the injection of an aqueous solution into the oil formation to help move the oil through the formation and to maintain the pressure in the reservoir as fluids are being removed. The injected water, either surface water (lake or river) or seawater (for operations offshore) generally contains soluble salts such as sulfates and carbonates. These salts may be incompatible with the ions already contained in the oil-containing reservoir. 
     The reservoir fluids may contain high concentrations of certain ions that are encountered at much lower levels in normal surface water, such as strontium, barium, zinc and calcium. Partially soluble inorganic salts, such as barium sulfate (or barite) and calcium carbonate, often precipitate from the production water as conditions affecting solubility, such as temperature and pressure, change within the producing well bores and topsides. This is especially prevalent when incompatible waters are encountered such as formation water, seawater, or produced water. 
     Some mineral scales have the potential to contain naturally occurring radioactive material (NORM). The primary radionuclides contaminating oilfield equipment include Radium-226 (226Ra) and Radium-228 (228Ra), which are formed from the radioactive decay of Uranium-238 (238U) and Thorium-232 (232Th). While 238U and 232Th are found in many underground formations, they are not very soluble in the reservoir fluid. However, the daughter products, 226Ra and 228Ra, are soluble and can migrate as ions into the reservoir fluids to eventually contact the injected water. While these radionuclides do not precipitate directly, they are generally co-precipitated in barium sulfate scale, causing the scale to be mildly radioactive. 
     Because barium and strontium sulfates are often co-precipitated with radium sulfate to make the scale mildly radioactive, handling difficulties are also encountered in any attempts to remove the scale from the equipment. Unlike common calcium salts, which have inverse solubility, barium sulfate solubility, as well as strontium sulfate solubility, is lowest at low temperatures, and this is particularly problematic in processing in which the temperature of the fluids decreases. Modern extraction techniques often result in drops in the temperature of the produced fluids (water, oil and gas mixtures/emulsions) (as low as by 5 C) and fluids being contained in production tubing for long periods of time (24 hrs or longer), leading to increased levels of scale formation. Because barium sulfate and strontium sulfate form very hard, very insoluble scales that are difficult to prevent, dissolution of sulfate scales is difficult (conventionally requiring high pH, long contact times, heat and circulation). 
     SUMMARY 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
     In one aspect, embodiments disclosed herein relate to a method of decontaminating naturally occurring radioactive material (NORM) from downhole equipment that includes injecting a NORM dissolver into an isolated region of a wellbore in which NORM-contaminated production equipment is located; and removing the NORM contaminants from the production equipment. 
     In another aspect, embodiments disclosed herein relate to a method of decontaminating naturally occurring radioactive material (NORM) from downhole equipment that includes isolating NORM-contaminated production equipment from other regions of a wellbore; flushing diesel through the isolated region; injecting a wetting agent into the isolated region to render the NORM-contaminated production equipment water wet; injecting a NORM dissolver into the isolated region; and removing the NORM contaminants from the production equipment. 
     Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1-4  show embodiments of downhole production equipment that may be treated in accordance with the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     In one aspect, embodiments disclosed herein relate to the in situ treatment of downhole equipment contaminated with NORM. Specifically, embodiments of the present disclosure relate to methods of treating downhole production equipment having NORM-containing scale thereon without retrieval of the equipment to the surface. 
     Conventionally, mineral scale (not containing NORM) may be treated in place, but occasionally, this scale contaminated tubing and equipment is simply removed and replaced with new equipment. However, when the old equipment is contaminated with NORM, the equipment is conventionally removed from the well and replaced, and the equipment is treated (a costly and hazardous affair) to remove the NORM scale therefrom. At present, a considerable amount of oilfield tubular goods and other equipment awaiting decontamination is sitting in storage facilities. Some equipment, once cleaned, can be reused, while other equipment must be disposed of as scrap. Once removed from the equipment, several options for the disposal of NORM exist, including canister disposal during well abandonment, deep well injection, landfill disposal, and salt cavern injection. 
     Conventional equipment decontamination processes have included both chemical and mechanical efforts, such as milling, high pressure water jetting, sand blasting, cryogenic immersion, and chemical chelants and solvents, all of which occur on topside, not downhole. Water jetting using pressures in excess of 140 MPa (with and without abrasives) has been the predominant technique used for NORM removal. However, use of high pressure water jetting generally requires that each pipe or piece of equipment be treated individually with significant levels of manual intervention, which is both time consuming and expensive, but sometimes also fails to thoroughly treat the contaminated area. When scale includes NORM, this technique also poses increased exposure risks to workers and the environment. 
     In contrast, embodiments of the present disclosure involve chemical treatment of the NORM-contaminated equipment downhole without retrieving the equipment to the surface to await a backlog of equipment needing NORM decontamination. However, in other embodiments, the equipment may be retrieved to the surface after the NORM decontamination occurs, in case, for example, the equipment needs to be repaired or replaced for reasons other than the NORM contamination. Though, by treating the equipment in situ prior to retrieving it to the surface, repair or disposal can commence immediately, rather than first waiting for NORM decontamination to occur. 
     Referring initially to  FIG. 1 , a production apparatus  100  in accordance with one or more embodiments of the present disclosure is shown. Production apparatus  100  is deployed to a wellbore lined with casing  102  upon the end of a string of production tubing  104  extending from a surface station (not shown). Production tubing  104  terminates at its distal end into a Y-shaped union commonly known as a Y-tool  106 . Below Y-tool  106  and in fluid communication with production tubing  104  are a pump string  108  and a bypass string  110 . Furthermore, while a Y-tool  106  is shown, it should be understood by one of ordinary skill in the art that any style fluid union can be used to connect production tubing  104  with bypass string  110  and pump string  108 . 
     Pump string  108  extends further into casing  102  and includes a pump assembly  112 . Pump assembly  112  may be configured to pump wellbore fluids from upper region  114  of casing  102 , up through production tubing  104 , and to a surface station above the well. Pump assembly  112  may be constructed as an electric submersible pump that includes an inlet  116  and an outlet  118  in communication with pump string  108 . A check valve  119  ensures that fluids (e.g. NORM dissolving chemicals) from production tubing  104  and bypass string  110  will not flow into pump assembly  112  unless desired. Optionally, a sensor package  120  mounted to pump assembly  112  records and reports downhole conditions to a pump controller (not shown) or a surface station. Furthermore, a control and power line  122  extends from pump assembly  112 , alongside production tubing  104  to a surface control station. Those having ordinary skill will appreciate that control and power line  122  may vary in construction depending on the pump assembly  112 . For example, if pump assembly  112  is pressure driven, control and power line  122  may comprise one or more fluid conduits in communication with a surface pressure source and pump assembly  112 . 
     Bypass string  110  may run alongside pump string  108  inside casing  102  and extend deeper into a production zone  124 . Bypass string  110  may include a bypass section  126 , an upper fluid gate  128 , a packer assembly  130 , and a lower fluid gate  132 . Upper and lower fluid gates  128 ,  132  are devices designed to selectively allow and disallow fluids from outside bypass string  110  to communicate with a bore  136  of bypass string  110 . Fluid gates  128  and  132  may be constructed as sliding sleeve type devices, but any remotely operable fluid gate devices can be used. Packer  130  may be expanded after production apparatus  100  is delivered to cased wellbore and acts to hydraulically seal off the annulus between bypass string  110  and cased wellbore and divide that annulus into upper  114  and lower regions  138 . A plug  140  capable of being set into and retrieved from bypass tubing  110  selectively allows or blocks off direct communication between bypass tubing  110  and production tubing  104 . Plug  140  can either be a physical device deployed and retrieved through production tubing  104  from the surface or can be an electrically or hydraulically operable shutoff valve. Furthermore, if plug  140  is a remotely operable valve, it may be configured to allow large diameter items to pass therethrough when open. For example, a remotely operable flapper valve can be used for plug  140 . 
     With both upper and lower fluid gates  128 ,  132  open, fluid communication between upper and lower regions  114  and  138  is permitted. With upper fluid gate  128  open and lower fluid gate  132  closed, only upper region  114  is in communication with production tubing  104  and pump assembly  112 . With upper fluid gate  128  closed and lower fluid gate  132  open, only lower region  138  is in communication with production tubing  104 . By selectively manipulating upper fluid gate  128 , lower fluid gate  132 , and plug  140 , numerous operations can be performed on cased wellbore and production zone  124 , pump assembly  112 , or other production string components without detrimentally effecting other components. 
     During production, pump assembly  112  pumps production fluids from lower zone  138  adjacent to production zone  124  to a surface location through production tubing  104 . To retrieve or produce fluids which have flowed into lower zone  138  below packer  130 , upper and lower fluid gates  128 ,  132  are opened and plug  140  is again re-set in bypass string  110 . Pump assembly  112  is then activated and fluids from upper zone  114  are drawn into pump assembly  112  through inlet  116  and pumped up through pump string  108 , Y-tool  106 , and production tubing  104  to a surface destination. As fluids are removed from upper zone  114  by pump assembly  112 , they are replenished by formation fluids entering lower zone  138  through perforations  146 . These fluids travel through lower fluid gate  132 , across packer  130 , and out upper fluid gate  128  to upper zone  114 . Because plug  140  prevents bypass string  110  from directly communicating with production tubing  104 , pump assembly  112  is able to displace fluids from lower zone  138  to surface location through production tubing  104 . Absent plug  140 , pump assembly  112  would only circulate fluids between bypass string  110  and upper zone  114 . 
     Further, in one or more embodiments, a work conduit (not shown) extends from within production tubing  104 , through Y-tool  106 , through bypass string  110 , past upper fluid gate  128 , through packer  130 , and through lower fluid gate  132 . Work conduit may be a wireline assembly, capillary tubing, slickline, fiber-optic line, or coiled tubing, etc. Work conduit can be deployed either to take measurements or to perform work operations. Such work operations can include the injection of treatment chemicals, the manipulation of downhole equipment (e.g. valves), and the cleansing of bores of the production apparatus  100 . Such measurements can include temperature, pressure, density, and resistivity of downhole fluids. 
     In one or more embodiments, the system of  FIG. 1  may be used to perform NORM decontamination of one or more components of the production apparatus  100  while emplaced in the wellbore. Specifically, bypass string  110  may be used to deliver one or more NORM dissolvers downhole (such as through work conduit). Depending on the component of the production apparatus needing decontamination, the NORM dissolver may be delivered to the appropriate location within the well, while closing off, for example, the producing zone  124  and/or other sections or components of the production apparatus  100 . For example, in the event that one or more components of the pump assembly is to be decontaminated, the upper fluid gate  128  may be opened and lower fluid gate  132  may be closed, so that only upper region  114  is in communication with production tubing  104  and pump assembly  112 . NORM dissolvers may be applied, and depending on the chemistry of the dissolvers involved a pre-flush with diesel followed by a wetting agent may be first circulated into the upper region  114  to render the contaminants water wet prior to circulation of the NORM dissolver into the upper region  114  and through the pump assembly  112 . A production logging tool containing a gamma densitometer may be run before and after the treatment with the NORM dissolver to verify removal of NORM. Prior to re-commencing production, the pump assembly  112  and upper region may be optionally re-flushed with a fluid such as diesel or water. Such fluid containing the dissolved scale may be produced or may be flushed into the formation. 
     Further, while the Y-tool and bypass equipment described in  FIG. 1  may readily allow for the isolation of the producing zone  124  from the pump assembly  112 , the present disclosure is not limited to the use of the particular production apparatus  100  shown in  FIG. 1 . Rather, it is envisioned that in any wellbore, the producing zone (and potentially lower completion equipment) may be shut off by a through-tubing plug and cement or a polymeric gel or plug, allowing for treatment of one or more parts of the upper completion. 
     Referring to  FIG. 2 , an embodiment of downhole production equipment that may be treated in accordance with the present disclosure is shown. In this embodiment, a wellbore  28  extends through a geological formation  30 . As illustrated, wellbore  28  is lined with a wellbore casing  38  having perforations  40  through which fluid flows between producing zone  34  and wellbore  28 . A string of production tubing  20  extends from a surface station (not shown) and terminates at its distal end at a Y-tool  22 . Below Y-tool  22  and in fluid communication with production tubing  20  are a pump string  34  and a bypass string  36 . 
     An electric submersible pumping system  26  is suspended below pump string  34 . For example, a hydrocarbon-based fluid may flow from formation  30  through perforations  40  and into wellbore  28  adjacent electric submersible pumping system  26 . Upon fluids entering wellbore  28 , pumping system  26  is able to produce the fluid upwardly through pump string  34 , Y-tool  22 , and production tubing  20  to wellhead (not shown) and on to a desired collection point. 
     Although electric submersible pumping system  26  may comprise a wide variety of components, the example in  FIG. 2  is illustrated as having a submersible pump  32 , a pump intake  44 , and an electric motor  46  that powers submersible pump  32 . Motor  46  receives electrical power via a power cable  48  and is protected from deleterious wellbore fluid by a motor protector  50 . In addition, pumping system  26  may comprise other components including a sensor unit  54 . One or more of these components of the electric submersible pump  26  may be treated in situ to perform NORM decontamination therefrom, such as by shutting off the producing zone  30  (by packer, plug, and/or cement) from the pumping system  26 , and then circulating a NORM dissolver in the section of the wellbore containing NORM-contaminated equipment. Further, while an electric submersible pump is illustrated, it is envisioned that other artificial lift components including other pumps or gas lifts may be treated accordingly as well. 
     In addition to a pump assembly, other production equipment that may be treated in accordance with methods of the present disclosure include, but are not limited to, subsurface safety valves, packers, injection mandrels, gas lifts, monitoring equipment, cables, etc. 
     For example, referring to  FIG. 3 , another schematic of production equipment is shown. As shown, production equipment  300  may include a subsurface safety valve  305  installed in the upper wellbore to provide emergency closure of the producing conduits in the event of an emergency. There is no limitation on the type of valve that may be used, but in one embodiment, it may be a flapper type valve. Also included in production equipment  300  are one or more chemical injection mandrels  310  connected to chemical injection line(s) for injecting one or more chemicals into the wellbore, and one or more packers  315  for isolating various regions of the wellbore from one another. Further, the location of the components on the production string  320  is not limited, and it is envisioned, for example, that the subsurface safety valve  305  may be above the injection mandrel, etc. Depending on the component needing NORM decontamination and its location, additional isolations may be emplaced in the well to protect the producing zone and/or other equipment. NORM dissolvers may be injected through the injection mandrel or through other means into the well, depending on the location of the component to be decontaminated. 
     Referring now to  FIG. 4 ,  FIG. 4  depicts a gas lift system  410  that includes a production tubing  414  that extends into a wellbore. For purposes of gas injection, the system  410  includes a gas compressor  412  that is located at the surface of the well for purposes of introducing pressurized gas into an annulus  415  of the well. To control the communication of gas between the annulus  415  and a central passageway  417  of the production tubing  414 , the system  410  may include several gas lift mandrels  416 . Each one of these gas lift mandrels  416  includes an associated gas lift valve  418  that responds to the annulus pressure. More specifically, when the annulus pressure at the gas lift valve  418  exceeds a predefined threshold, the gas lift valve  418  opens to allow communication between the annulus  415  and the central passageway  417 . For an annulus pressure below this threshold, the gas lift valve  416  closes and thus, prevents communication between the annulus  415  and the central passageway  417 . 
     Mineral scale that may be effectively removed from oilfield equipment in embodiments disclosed herein includes oilfield scales, such as, for example, salts of alkaline earth metals or other divalent metals, including sulfates of barium, strontium, radium, and calcium, carbonates of calcium, magnesium, and iron, metal sulfides, iron oxide, and magnesium hydroxide. That is, the scale may include NORM, and may also include other mineral scale precipitated therewith. The NORM may also include radioactive plating that has occurred on the production equipment from non-farrous radioactive metals such as Lead 210 and Pollonium 210. 
     In one or more embodiments, NORM dissolver may include a chelating agent. The chelating agent that may be used in the solution to dissolve the metal scale may be a polydentate chelator so that multiple bonds with the metal ions may be formed in complexing with the metal. Polydentate chelators suitable for use in embodiments disclosed herein include, for example, ethylenediaminetetraacetic acid (EDTA), diethylenetriaminepentaacetic acid (DTPA), nitrilotriacetic acid (NTA), ethyleneglycoltetraacetic acid (EGTA), 1,2-bis(o-aminophenoxy)ethane-N,N,N′,N′-tetraacetic acid (BAPTA), cyclohexanediaminetetraacetic acid (CDTA), triethylenetetraaminehexaacetic acid (TTHA), salts thereof, and mixtures thereof. However, this list is not intended to have any limitation on the chelating agents suitable for use in the embodiments disclosed herein. One of ordinary skill in the art would recognize that selection of the chelating agent may depend on the metal scale to be dissolved. In particular, the selection of the chelating agent may be related to the specificity of the chelating agent to the particular scaling cation, the log K value, the optimum pH for sequestering and the commercial availability of the chelating agent. 
     In a particular embodiment, the chelating agent used to dissolve metal scale is EDTA, and/or DTPA, or salts thereof. Salts of EDTA and DTPA may include, for example, alkali metal salts and depending on the pH of the dissolving solution different salts or the acid may be present in the solution. 
     In one or more embodiments, the NORM dissolver may be a metal nitrate (the metal having a lower electronegativity than the contaminants). In a particular embodiment, the NORM dissolver may be zirconium nitrate, which may optionally be used in conjunction with an oxidizing agent such as H 2 O 2 . 
     Further, as mentioned, the NORM dissolver may be preceded by circulation of diesel and/or a wetting agent to render the tool surfaces (and NORM scale) water wet. Further, following the NORM dissolver treatment, a fluid (such as diesel or water) may be flushed through the region to remove the NORM dissolver. The dissolved NORM may be removed from the wellbore either by production or by flushing the material back into the formation (such as by opening the isolation). 
     Following treatment, a gamma tool may be used to verify that the NORM material has been dissolved and removed from the tool on which it had precipitated. This logging may be compared to a log conducted prior to NORM treatment. Further, after treatment, production of hydrocarbons may resume, though, in some embodiments, it is envisioned that a tool could be replaced (even the tool having been decontaminated) if the tool is not operational for other reasons. However, the downhole treatment of the tool will present fewer risks to the operator and avoid a backlog of equipment topside needing NORM decontamination. 
     Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.