US20110024122A1 - Methods and systems of treating a wellbore - Google Patents

Methods and systems of treating a wellbore Download PDF

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Publication number
US20110024122A1
US20110024122A1 US12/921,607 US92160709A US2011024122A1 US 20110024122 A1 US20110024122 A1 US 20110024122A1 US 92160709 A US92160709 A US 92160709A US 2011024122 A1 US2011024122 A1 US 2011024122A1
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Prior art keywords
wellbore
oxidants
electrolytic tool
electrolytic
filtercake
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US12/921,607
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English (en)
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David Antony Ballard
Andy Popplestone
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MI Drilling Fluids UK Ltd
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MI Drilling Fluids UK Ltd
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Priority to US12/921,607 priority Critical patent/US20110024122A1/en
Assigned to M-I DRILLING FLUIDS UK LIMITED reassignment M-I DRILLING FLUIDS UK LIMITED ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: BALLARD, DAVID ANTONY, POBBLESTONE, ANDY
Assigned to M-I DRILLING FLUIDS UK LIMITED reassignment M-I DRILLING FLUIDS UK LIMITED ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: BALLARD, DAVID ANTONY, POPPLESTONE, ANDY
Publication of US20110024122A1 publication Critical patent/US20110024122A1/en
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    • 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
    • E21B37/00—Methods or apparatus for cleaning boreholes or 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
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure

Definitions

  • Embodiments disclosed herein relate generally to methods and systems of treating a wellbore, and more particularly to the removal of filtercakes which form in wellbores.
  • Hydrocarbons are typically obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation.
  • a subterranean geologic formation i.e., a “reservoir”
  • hydrocarbons In order for hydrocarbons to be “produced,” that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore.
  • One key parameter that influences the rate of production is the permeability of the formation along the flowpath that the hydrocarbon must travel to reach the wellbore.
  • the formation rock has a naturally low permeability; other times, the permeability is reduced during, for instance, drilling the well.
  • various fluids are typically used in the well for a variety of functions.
  • a drilling fluid is often circulated into the hole to contact the region of a drill bit, for a number of reasons such as: to cool the drill bit, to carry the rock cuttings away from the point of drilling, and to maintain a hydrostatic pressure on the formation wall to prevent production during drilling.
  • the fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface.
  • the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
  • filtercake a coating on the wellbore surface
  • Filtercakes are formed when particles suspended in a wellbore fluid coat and plug the pores in the subterranean formation such that the filtercake prevents or reduce both the loss of fluids into the formation and the influx of fluids present in the formation.
  • a number of ways of forming filtercakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates.
  • the filtercake may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore.
  • a fluid loss pill of polymers may be “spotted” or placed in the wellbore.
  • Other completion fluids may be injected behind the fluid loss pill into a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location to coat the formation and prevent or reduce future fluid loss.
  • the filtercake formed during drilling and/or completion
  • the side walls of the wellbore must typically be removed, because remaining residue of the filtercake may negatively impact production. That is, although filtercake formation and use of fluid loss pills are essential to drilling and completion operations, the barriers may be a significant impediment to the production of hydrocarbons or other fluids from the well, if, for example, the rock formation is still plugged by the barrier. Because filtercake is compact, it often adheres strongly to the formation and may not be readily or completely flushed out of the formation by fluid action alone.
  • embodiments disclosed herein relate to methods of treating a wellbore including emplacing at least one electrolytic tool in a desired section of the wellbore, applying an electric charge to wellbore fluids present in the desired section of the wellbore, and generating oxidants in situ by electrolyzing components of the wellbore fluids.
  • embodiments disclosed herein relate to methods of breaking a filtercake formed in a wellbore, including generating oxidants in situ by electrolyzing components of a wellbore fluid present in the wellbore; and allowing the oxidants to degrade filtercake components.
  • FIG. 1 is a schematic drawing of one embodiment of a drilling system.
  • FIG. 2 is a schematic view of an electrolytic tool, according to embodiments disclosed herein.
  • FIG. 3 is a block diagram of an oxidant generation system, according to embodiments disclosed herein.
  • FIG. 4 is a flow chart showing a process of a filtercake treatment, according to embodiments disclosed herein.
  • Non-limiting examples of various electrolytic cells that may be used and/or modified for use downhole in the methods and system of the present disclosure include those described in U.S. Pat. Nos. 4,761,208, 5,385,711, 6,261,464, 6,524,475, 6,558,537, 6,736,966, 6,805,787, 7,005,075, and 7,008,523, all of which are herein incorporated by reference.
  • electrolytic cells may be incorporated into hardware typically used in downhole.
  • completion hardware such as slotted liners and sand screens may be used as electrodes for the generation of oxidants within the wellbore in some embodiments of the present disclosure.
  • the wellbore fluid acting as an electrolyte may be a water-based fluid.
  • the wellbore fluid may include an aqueous solution as the base fluid including at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof
  • the aqueous solution may be formulated with mixtures of desired salts in fresh water.
  • Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.
  • the wellbore fluids disclosed herein may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water.
  • Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, silicates, phosphates and fluorides. Salts that may be incorporated in brines include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts.
  • brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution.
  • a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium. The presence of these salts enhances the ionic character of the wellbore fluid, thereby increasing its ability to transmit an electric charge and enhancing its properties as an electrolyte.
  • an electrical potential may be provided by a control unit (shown in FIG. 3 as 85 ), and may be conducted between the electrodes 58 and 59 by the wellbore fluid.
  • a controlled electrical charge passes through the wellbore fluid from the at least one cathode 59 to the at least one anode 58 , thereby generating at least one oxidant in the electrolytic solution.
  • the wellbore fluid flows through the reaction chamber 57 of the electrolytic cell 51 , and an electrical current is passed between the anode 58 and the cathode 59 , several chemical reactions occur that involve the water, as well as one or more of the other salts or ions contained in the wellbore fluid.
  • the electrical current polarizes the electrodes 58 , 59 and causes dissociation of the wellbore fluid into component ions.
  • the wellbore fluid includes a solution of sodium chloride (NaCl)
  • NaCl brine may dissociate into sodium and chlorine ions which would migrate to the cathode and to the anode, respectively:
  • the anode is known to be electron deficient, and without being bound by any particular theory, it is believed that the anode withdraws electrons from the water and other ions adjacent to the anode, which results in the formation of oxidative species in the wellbore electrolyte. For instance, the following chlorine generating reaction may occur at the anode surface:
  • the chlorine gas (Cl 2 ) generated by the chlorine reaction may dissolve in the water to generate hypochlorite ions (OCl ⁇ ) which are an oxidative species useful in embodiments of this disclosure:
  • the protons generated (H + ) may in turn combine with free electrons at the electron-rich cathode to generate hydrogen gas, which may be vented from the electrolytic tool by any means known in the art:
  • oxidant generation has been illustrated by using NaCl brines as an example, one skilled in the art would appreciate that these principles apply to the generation of oxidants from any ionic solution by electrolysis.
  • the present disclosure relates to the production of one or more oxidants and may include, for example, hypochlorite, chlorine, bromine, chlorine dioxide, ozone, hydrogen peroxide, and other chloro-oxygenated and bromo-oxygenated species.
  • Flow dynamics which include the movement of molecules in a flowing solution by turbulence, predict that the conversion of salts will increase as the solution flow path nears the anode surface layer. Consequently, in some embodiments, methods and systems of the present disclosure preferably maximize the flow of the wellbore electrolyte over the anode in order to maximize the generation of oxidants.
  • Flow of the wellbore fluid may be enhanced by any means known in the art, for example mixers such as propellers, etc.
  • pumping devices 60 , 61 may be set between the positive electrode 58 and the negative electrode 59 .
  • the pumping devices may have propeller blades, valves, or any means known in the art to generate a fluid stream in the reaction chamber 57 so that the wellbore fluid surrounding the electrolytic tool is induced into the reaction chamber 57 of the electrolytic cell 51 through inlet port 54 , passes through the reaction chamber 57 of the electrolytic cell 51 , and is released from the outlet port 56 .
  • the inlet port 54 may include an inlet port mechanism such as a valve, or any other mechanism known in the art to seal the inlet port after the wellbore fluid has entered the cell. Once generated, the oxidant-rich wellbore fluid may exit the electrolytic cell 51 via the outlet port 56 .
  • the local concentration of oxidants present in the exiting wellbore fluid may be measured by any instrument known in the art, for example, an oxidant sensor. Once the oxidant sensor has detected that the local concentration of oxidant is sufficient to break the filtercake, the electrical potential applied across the electrodes of the electrolytic cell may be removed and the electrolytic tool may then be removed from the wellbore.
  • the oxidants now present in the wellbore fluid may degrade the filtercake by any mechanism known in the art.
  • filtercakes may comprise polymers such as polysaccharides. Oxidants are known to attack the glycosidic linkage between the rings, causing chain scission. Accordingly, as the polymer breaks down to shorter chains, the filtercake degrades, and may be removed by the circulating wellbore fluid. The oxidant becomes reduced by this process, and the reduced form may be reoxidized by the electrolytic tool, if deemed necessary. Alternatively, one skilled in the art would appreciate that the electrolytic tool may continuously (or intermittently) generate oxidants until it has been determined that the filtercake has been sufficiently removed.
  • the ability to generate oxidants in situ for the breaking of filtercakes provides advantageous control over the timing of the breaking of the filtercake.
  • the electrolytic tool may be emplaced at the site of the filtercake desired to be removed (e.g., at the producing interval), thereby generating an oxidant-rich environment in close proximity to the filtercake, the timing of the breaking of the filtercake may be triggered by the providing of an electrical potential across the electrodes of the electrolytic cell.
  • this technique may provide greater controllability as compared to conventional emplacement of breaker fluids, which may react too fast or too slow depending on the presence or absence of delay mechanisms.
  • an electrolytic tool may be placed downhole to generate oxidants in situ which are able to kill bacteria which may be present in the wellbore.
  • the drilling process initiates communication between the surface and the subsurface oilfield environments.
  • wellbore fluids may be circulated from the surface to the bit to remove cuttings, and to control formation pressures downhole.
  • chemicals and bacteria from the surface may be circulated into the deep subsurface energy-rich, oil-bearing strata, and the hydrocarbon laden cuttings may be brought into the oxygen-rich, moderate temperature surface environment.
  • microbiological activity may be initiated in the surface and subsurface environments. While this typically does not occur normally, this may lead to bacterial contamination of the wellbore.
  • organic polymers present as viscosifiers and fluid loss control agents in a wellbore fluid tend to be of plant or microbiological origin and may act as a ready food source for growth of naturally occurring oilfield bacteria. If bacterial growth is excessive, the consumption of these organic wellbore fluid components may result in a loss of the rheological properties of the mud, microbial corrosion of well tubulars and screens, biomass plugging in injection wells and the formation, and hydrogen sulfide production deep in the formation. If left untreated, it is possible that bacterial contamination may cause a breakdown of wellbore integrity.
  • electrolytic tools disclosed herein may be used to trigger breaking of the gel in the inappropriate location so that it may be placed in the desired location. Additionally, if the tool is being used to control bacterial growth, it is envisioned that it may be desirable to form oxidants at any stage, including drilling.
  • the desired depth and/or lateral positioning of the electrolytic tool in the wellbore may be advantageously controlled by the use of any equipment known in the art such as winches etc. Further, the depth and lateral positioning of the electrolytic tool in the wellbore may be measured by any instrumentation known in the art, such as depth gauges, sensors, cameras etc. Once optimal placement of the electrolytic tool has been achieved, the oxidants may then be generated in situ at the desired section of the wellbore, thereby achieving paramount axial distribution of the oxidant breaker.
  • the electrolytic tool includes an oxidant generation system 80 .
  • the oxidant generation system 80 includes the oxidant generator 50 , a control unit 85 , the winch unit 70 , a power supply unit 81 , and a valve actuator 82 .
  • the oxidant generator 50 includes an electrolytic cell 51 , an oxidant sensor 52 , and optionally a hydraulic power generator 53 .
  • the oxidant generator 50 may comprise multiple electrolytic cells 51 , which may be electrically connected to each other in series or in parallel, to allow for the breaking of filtercakes over larger intervals.
  • multiple oxidant generators 50 may be used in a single operation depending on the length of interval to be broken and/or dimensions of the tool.
  • the oxidant generator 50 is suspended in the wellbore 101 by a cable 71 .
  • a winch unit 70 lifts and/or lowers the cable 71 to adjust depth position of the oxidant generator 50 in the wellbore 101 .
  • the control unit 85 includes, for example, a CPU, a ROM, a RAM, an input and an output port, a memory apparatus and the like (not shown).
  • the control unit 85 is electrically connected to at least the oxidant generator 50 , the winch unit 70 , and power supply unit 81 .
  • the control unit 85 operates the oxidant generator 50 , the winch unit 70 and valve actuator 82 by transmitting command signals (solid arrowed lines).
  • the command signals may be based on detection signals of the oxidant sensor 51 connected to the oxidant generator 50 and/or the depth gauge 72 connected to the winch unit 70 .
  • a feedback command signal may be sent to the winch unit 70 through the control unit 85 to adjust the depth of the oxidant generator 50 accordingly.
  • a feedback command signal may be sent to the winch unit 70 through the control unit 85 to adjust the output of the oxidant generator accordingly.
  • the feedback command signal may be automated or input manually. Accordingly, the power supply unit 81 supplies electrical power (broken arrowed lines) to control unit 60 , the oxidant generator 50 , the winch unit 70 and the valve actuator 82 , based on command signals transmitted by the control unit 85 .
  • a method of treating a wellbore is shown in a flow chart.
  • a wellbore fluid which is an electrolytic brine solution may be emplaced within a wellbore.
  • electrolytic brine solutions may have been the fluid used to drill the wellbore or may have been a subsequent fluid placed in the wellbore for completion operations, for example.
  • the electrolytic tool may be placed in the section of the wellbore where removal of the filtercake is desired.
  • applying voltage to the electrodes generates oxidants in the brine solution in the electrolytic cell.
  • the wellbore is evaluated to assess the efficiency of the breaking of the filtercake.
  • the electrolytic tool is deactivated in 5000 , and removed from the wellbore, as in 6000 . If the filtercake has not been sufficiently removed, the electrolytic tool may be activated once again by applying a voltage across the electrodes, as in 3000 . This iteration may repeat until the filtercake has been sufficiently removed, and then the electrolytic tool may then be deactivated and removed from the wellbore as in 5000 and 6000 , respectively.
  • embodiments of the present disclosure provides for the degradation of filtercakes by oxidants generated downhole, in situ, by use of an electrolytic tool.
  • the in situ generation of oxidants may provide advantageous control over timing of breaking of the oxidative breaker in the wellbore.
  • generating oxidants in situ from relatively benign precursors such as brines may result in less corrosion in the drill string assembly and is more environmentally friendly.
  • generating oxidants in situ at the desired site may allow use of smaller volumes of chemicals such as oxidative breaker and other additives, and may be more cost-efficient, using species already present in a wellbore instead of requiring a subsequent pumping of a breaker fluid downhole.
  • generating oxidants downhole may allow for control of bacterial populations downhole.
  • Control of bacterial populations downhole may result in decreased microbial corrosion of tubular and screens, biomass plugging, and hydrogen sulfide production.
  • appreciable cost savings, environmental, and safety benefits may be actualized by use of embodiments of the methods and systems of the present disclosure.

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  • Environmental & Geological Engineering (AREA)
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  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
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WO2012156875A2 (en) * 2011-05-18 2012-11-22 Schlumberger Technology B.V. Altering a composition at a location accessed through an elongate conduit
RU2473799C2 (ru) * 2011-04-22 2013-01-27 Шлюмберже Текнолоджи Б.В. Способ увеличения проницаемости призабойной зоны пласта
WO2012166670A3 (en) * 2011-05-27 2013-02-28 M-I L.L.C. Disinfeciting water used in a fracturing operation
WO2013131102A1 (en) * 2012-03-02 2013-09-06 Miox Corporation Waste to product on site generator
GB2512818A (en) * 2013-03-04 2014-10-15 Schlumberger Holdings Electrochemical reactions in flowing stream
US10132150B2 (en) * 2014-06-23 2018-11-20 Halliburton Energy Services, Inc. In-well saline fluid control

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JP6569354B2 (ja) * 2015-07-27 2019-09-04 日本製鉄株式会社 坑井の掘削方法
CN113426770A (zh) * 2021-07-30 2021-09-24 西安热工研究院有限公司 一种烟气组分吸收管的处理装置及方法

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CN101970793A (zh) 2011-02-09
MX2010009936A (es) 2010-10-25
WO2009112948A3 (en) 2009-11-05
CA2853269A1 (en) 2009-09-17
AU2009223855A1 (en) 2009-09-17
EA201071065A1 (ru) 2011-04-29
EA018242B1 (ru) 2013-06-28
WO2009112948A2 (en) 2009-09-17
CA2718072A1 (en) 2009-09-17
CN101970793B (zh) 2014-10-08
AU2009223855B2 (en) 2012-05-03

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