CA2175144A1 - Thermosetting well treatment composition - Google Patents
Thermosetting well treatment compositionInfo
- Publication number
- CA2175144A1 CA2175144A1 CA002175144A CA2175144A CA2175144A1 CA 2175144 A1 CA2175144 A1 CA 2175144A1 CA 002175144 A CA002175144 A CA 002175144A CA 2175144 A CA2175144 A CA 2175144A CA 2175144 A1 CA2175144 A1 CA 2175144A1
- Authority
- CA
- Canada
- Prior art keywords
- composition
- magnesium oxide
- thermosetting composition
- magnesium
- weight
- Prior art date
- Legal status (The legal status 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 status listed.)
- Abandoned
Links
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B33/138—Plastering the borehole wall; Injecting into the formation
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- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B14/00—Use of inorganic materials as fillers, e.g. pigments, for mortars, concrete or artificial stone; Treatment of inorganic materials specially adapted to enhance their filling properties in mortars, concrete or artificial stone
- C04B14/02—Granular materials, e.g. microballoons
- C04B14/26—Carbonates
- C04B14/28—Carbonates of calcium
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- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B22/00—Use of inorganic materials as active ingredients for mortars, concrete or artificial stone, e.g. accelerators, shrinkage compensating agents
- C04B22/06—Oxides, Hydroxides
- C04B22/066—Magnesia; Magnesium hydroxide
-
- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B22/00—Use of inorganic materials as active ingredients for mortars, concrete or artificial stone, e.g. accelerators, shrinkage compensating agents
- C04B22/08—Acids or salts thereof
- C04B22/10—Acids or salts thereof containing carbon in the anion
-
- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B22/00—Use of inorganic materials as active ingredients for mortars, concrete or artificial stone, e.g. accelerators, shrinkage compensating agents
- C04B22/08—Acids or salts thereof
- C04B22/12—Acids or salts thereof containing halogen in the anion
- C04B22/124—Chlorides of ammonium or of the alkali or alkaline earth metals, e.g. calcium chloride
-
- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
- C04B28/30—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing magnesium cements or similar cements
- C04B28/32—Magnesium oxychloride cements, e.g. Sorel cement
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/426—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for plugging
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/44—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing organic binders only
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/5045—Compositions based on water or polar solvents containing inorganic compounds
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
Abstract
An acid soluble, water impermeable, inorganic, thermosetting composition for use in sealing an underground permeable zone. The composition includes about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24% inert filler, or about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, and about 22.7% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite, and the aqueous solution being magnesium chloride solution. The amount of aqueous liquid, magnesium oxide, magnesium sulphate and inert filler is selected such that the composition has an exponential setting curve at the temperature T. The composition is mixed and injected into a well bore adjacent the zone through tubing to fill the well bore adjacent the zone. Tubing is removed from adjacent the zone; and the composition is allowed to set at least adjacent the zone.
Description
~175144 TITLE OF THE INVENTION:
Thermosetting Well Treatment Composition NAME(S) OF INVENTOR(S):
Brian H. Tomlinson FIELD OF THE INVENTION
This invention relates to acid soluble magnesium oxysulphate and oxychloride cement composition~ and their method of use.
P~XGROUND OF THE INVENTION
The use of magnesium oxysulphate or oxychloride cements to plug underground formations during oil and gas well drilling and production is well known. These cements are introduced as slurries into a well bore where they harden against the formation and provide an impermeable block to fluid migration into or from the formation. These cements are also acid solu~le so that once they are no longer needed, acid solutions may be applied to the well to remove the cements.
For example, Canadian patent no. 1,053,892 of Barthel describes a magnesium oxysulphate cement that is mixed with drilling fluid to form a hardenable cement. The magnesium oxysulphate cement is made with an additive comprising magnesium oxide, magnesium sulphate and a filler comprising magnesium carbonate or dolomite.
More .-ecently, United States patents 5,213,161; 5,220,960; and 5,298,069 of Halliburton Company, Oklahoma, have disclosed improvements on magnesium oxychloride cements. These improvements include use of a foaming agent and foam stabilizer, and use of a set retarder comprising a water soluble borate and a sugar.
SU~ARY OF THE INVENTION
These prior art compositions, however, have disadvantages. The use of slow setting compositions, and in particular, the use of a retarder tends to delay the setting time of the composition so that the cement tends to invade deep cracks and pores in the formation to such an extent that subsequent application of acid cannot remove the cement from the formation. This tends to cause loss of permeability, which can be disastrous to subsequent production from the formation.
Further, the inventor has found that it is important that the hardening process, though initially stimulated by the temperature of the cement, rapidly becomes exothermic, and that the cementation process should result in a rapidly setting firm composition.
In addition, the inventor has found that selection of the components of the cement according to the prior art teachings does not uniformly produce satisfactory results. Thus, inappropriate selection of the magnesium sulphate, or the magnesium oxide, used in such a cement may result in lack of controllability of the hardening process.
In one aspect of the invention, the inventor therefore proposes the use of magnesium sulphate trihydrate as th~ magnesium sulphate component in a cement formed of a solids component and an aqueous liquid. Magnesium sulphate trihydrate is unstable and difficult to handle, and is not believed to be an obvious candidate for use as a magnesium oxysulphate or oxychloride cement component. Moreover, it has the feature that the setting of the resulting magnesium cement is thermally triggered and rapidly becomes exothermic such that the cement has an exponential setting curve. The solids component of the cement composition is preferably 33 - 40% by weight magnesium oxide; 35 - 43% by weight of magnesium sulphate trihydrate; and 20 - 27% inert filler, typically calcium carbonate or cement filler. The inert filler must be acid soluble.
In a further aspect of the invention, for low temperature applications, the magnesium oxide is mined and may have impurities, while for high temperature applications, the magnesium oxide is pure, over 99% pure, and is calcined from brine. For high temperature applications, the aqueous liquid is preferably saturated magnesium chloride brine.
The resulting cement compositions, supplied under the trademark THERMAX, are non-invasive non-damaging thermosetting compounds, and are believed to represent a technological advance in the control of formation fluid invasion and lost circulation. The thermosetting composition is applied in pill form to the desired zone where the composition sets like cement but with many added benefits. Applications for the thermosetting composition of the invention include: drilling applications, including lost circulation, formation consolidation, zone isolation, gas shut-off and horizontal drilling; production applications, including zone protection, water blocking, zone isolation. Other applications include mining, seismic hole plugging and salt dome sealing.
The thermosetting composition of the present invention hardens through hydration. Shrinkage is limited to 0.5% or less. The thermosetting composition of the present invention is 100% inorganic and soluble in a 15% oilfield HCl solution. Due to its non-invasive characteristics the thermosetting composition of the present invention allows full return permeability.
BRIEF DESCRIPTION OF THE DRAWINGS
There will now be described preferred embodiments of the invention, with reference to the drawings, by way of illustration, in which like numerals denote like elements and in which:
Fig. 1 is a graph showing setting time for a high temperature thermosetting composition according to the invention having, in 1 m3 of slurry, 793 kg of a composition consisting of about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, about 22.7% inert filler (calcium carbonate and dolomite), 637.5 litres saturated MgCl2 brine and 41.7 kg inhibitor (5% sodium pentaborate);
Fig. 2 is a graph showing return permeability behaviour of berea cores (3" long at 150~F) after acidization of previously applied thermosetting composition according to the invention;
Fig. 3 is a graph showing setting time for a low temperature thermosetting composition according to the invention with and without inhibitor;
Fig. 4 is a graph showing setting time for a high temperature thermosetting composition according to the invention with and without inhibitor;
Fig. 5 is a table showing magnesium chloride solution requirements using 100% sacked MgCl.6H2O (for requirements for one bbl, divide bbls of water and required pounds of MgCl2 by 6.2; and 21751~ ~
Fig. 6 is a table showing sodium chloride solution requirements using 100% sacked NaCl (for requirements for one bbl, divide bbls of water and required pounds of NaCl by 6.2.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
The composition of the invention is an acid soluble, water impermeable, inorganic, thermosetting composition formed from a solids mixture and an aqueous liquid in which the amount of aqueous liquid, magnesium oxide, magnesium sulphate trihydrate and inert filler are selected such that upon setting the composition becomes exothermic and has an exponential setting curve at the temperature T.
The preferred aqueous liquid is a brine formed from calcium chloride, sodium chloride or magnesium chloride. The amount of liquid is preferably about 1 liter of liquid for each 1.25 kg of solids, resulting in a volume increase to about 1.56 liters of slurry. The magnesium chloride solution, particularly for high temperature applications, is preferably saturated MgCl2.6H2O brine. Sea water may be used.
For low temperature applications, namely 15~C - 70~C, the preferred solids composition is about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite (5 micron size). The temperature of calcination of the magnesium oxide may be used to regulate the setting temperature of the thermosetting composition.
For high temperature applications, namely 55~C - 100~C, the preferred solids composition is about 35.8% by weight magnesium oxide, about 41.5%
magnesium sulphate trihydrate, and about 22.7% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite (5 micron size). In the high temperature application, the composition preferably includes 5% sodium pentaborate as an inhibitor to delay the setting time of the thermosetting composition. For high and extra high temperature applications, namely 80~C and higher, the magnesium oxide is preferably calcined from pure brine. For low temperature applications, the magnesium oxide is preferably mined from a magnesite deposit and calcined at between 750~C and 900~C. In this manner, selection of the source and purity of the magnesium oxide allows controllability of the setting time of the composition.
The low temperature thermosetting composition is normally inhibited above 30~C and can be mixed in fresh water and compatible brines (not zinc bromide for example). High temperature thermosetting composition should only be mixed with saturated magnesium chloride brine.
While reasonably precise compositions have been disclosed that are known to work, it is believed that other compositions in the range 33 - 40% by weight magnesium oxide; 35 - 43% by weight of magnesium sulphate trihydrate; and 20 - 27% inert filler will also provide the exponential thermosetting characteristics when mixed with an appropriate aqueous solution.
The magnesium sulphate trihydrate peferably has a bulk density of between 37.68 and 46.31 lbs per cubic foot and a loss on ignition ratio of between 32 and 35~. It has been found that 6uch a magnesium sulphate trihydrate gives greater controllability over 217S14~
the thermosetting process as compared with that disclosed by Barthel.
The thermosetting characteristics of the above described compositions are dictated only by the temperature. They can be extremely rapid or may be slowed down by the use of the inhibitor. Due to hydration, shrinkage on setting is less than 0.5%.
The composition is unaffected by chlorides, and make-up water may be of any salinity. For sealing salt formations saturated NaCl brine is preferred. The composition adheres to salt formations and due to the availability of extremely short setting times, the thermosetting composition provides excellent characteristics for the prevention of microannular gas migration or remediation of channelling.
The exponential hardening characteristics of the thermosetting composition is triggered by the external temperature of the medium in which they are placed. This is normally the temperature of the formation or by addition of special additives. Once this temperature trigger has started the hardening process, then it becomes exothermic and self-generating. In a formation reservoir, the hardening process is accelerated even faster once the thermosetting composition enters the immediate periphery of the wellbore. Although drillpipe, tubing, etc. may still be pulled out of the slurry in the wellbore, away from the wellbore, the set is almost instantaneous with minimum penetration of the formation matrix. Hence, the thermosetting composition provides easy removability of the compound by acidization with full return permeability being possible. For water shut-off where fracture penetration may be required, the use of inhibitors will extend the setting time without any alteration of the exponential properties. The use of a saturated brine (MgCl2) in these circumstances will ensure maximum structural integrity. Use of the brine also ensures the slurry will not be diluted in the placement operation. Figure 1 illustrates a typical exponential setting curve for the invention. It will be appreciated that in cracks in the formation, when the appropriate thermosetting composition is used, the hardening will be almost immediate. A typical return permeability is shown in Fig. 2.
Setting time for low temperature and high temperature compositions of the invention are shown in Figs. 3 and 4 respectively.
The thermosetting composition is an off white powder with a median particle size of 7 microns and a viscosity of 18-30 cP, Slurry Density: 1.44-1.6 kg/l (11.9-13.37 ppg), depending on Mix Water. Bulk Density is 3.0 gm/cc. Compressive Strength 24 hour compressive strength for the low temperature composition varies as follows: 650 psi mixed with fresh water, 1500 psi mixed with saturated NaCl, 1950 psi mixed with saturated MgCl2. For the high temperature composition, the 24 hour compressive strength is 900 psi when mixed with saturated magnesium chloride. The set composition, whether high or low temperature composition, is 100% acid soluble in 15% HCl and requires approximately seven m3 (43.4 bbls) of 15% HCl to remove one m3 (6.2 bbls) of the set composition. A ratio of seven bbls to one bbls allows for possible 100% return permeability.
In the method of the invention, a thermosetting composition according to the invention includes mixing and injecting the thermosetting 2175~44 composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone; removing the tubing from adjacent the zone; and allowing the composition to set at least adjacent the zone. The mixing is preferably carried out on the fly.
In the preparation of the invention, the following steps are carried out: Calculate the volume of required slurry, calculate the final volume of water or brine, calculate the kilograms of thermosetting composition, use the attached graphs to determine setting time, calculate the final slurry density (kg/m3), determine the amount of Inhibitor, if required, from the attached graphs (see Figs. 3 and 4). Steps: fill the tank with water as calculated in step two above, add Inhibitor, if required, as calculated above, and agitate for 10 to 15 minutes, add MgCl2 or NaCl if required, add thermosetting composition, with vigorous agitation, as calculated above, displace the slurry into the well with a pumping unit.
Requirements of less than two cubic metres will be batch mixed. For larger volume applications, the composition will be continuously mixed through standard oilfield cementing equipment. Maintain the slurry density at +/-10 kg/m3 of the density calculated above. Maximum inhibitor concentration should not exceed 5% by dry weight of the solids composition (i.e. maximum 40 kg of inhibitor/m3 of slurry). It is recommended that the composition be mixed with magnesium chloride brine for maximum compressive strength.
Example #1 In September, 1993, a well in Alberta, Canada, had been shut in for some years. A
217~ 1 44 radioactive tracer had shown communication between the Cardium Conglomerate above Cardium sandstone in Alberta, Canada. Top of the production perforations was only 4 feet from the conglomerate. To solve the problem, a packer was set between sand and conglomerate, with a retainer at top of conglomerate (conglomerate interval perforated). Then tubing was inserted into the retainer and the conglomerate squeezed off with a low temperature thermosetting composition described above. 1.0 m3 of the low temperature thermosetting composition was batch mixed into a pumper and squeezed over a perforation interval of 6.4 m. Squeezing was to ~ust below fracture gradient at 4 mPa. The tubing was pulled out of the retainer. 24 hours later, the retainer and cement was drilled out to the packer, then the well pressure tested to 600 psi. After drilling out the packer and re-perforating the Cardium sandstone, it was found that the thermosetting composition successfully shut off vertical communication outside the casing.
Example #2 In this well, the producing zone watered out from migrating fluid below production zone. Log report indicated water was channelling upward along sides of the casing. A sleeved retainer was set 10 m below production zone. Then a high density perforating gun was used to make staggered radial perforations at 150 intervals. The thermosetting composition was displaced to the bottom of the tubing, the annulus closed in and the composition squeeze to seal water invasion. After squeezing, the tubing was removed, the composition allowed to set for 12 hours then drilled out. The well swabbed dry and stood full.
After perforating the production zone, the well surged 3 - 4 m3 of fluid with no the water invasion.
Example #3 An upper hole gas zone was encountered while drilling 311 mm hole in the Colony formation plus total lost circulation after drilling the Nisku (fractured carbonate). The well was drilled ahead blind to horizontal casing depth of 891 m. Over 6500 m3 of LCM pumped with no results (Nisku on vacuum).
Unable to pull out of the hole due to pack-off above the bit which allowed circulation down the backside to control the gas influx. To solve this, a thermosetting composition plug was established from the top of the Nisku at 723 m to total depth by displacement through the drill bit. Procedure Jet mixed a total of 10 MT
Thermax Lt (12.5 m3) with cementing unit and displaced through the bit. After pulling out, packing-off, clearing the drill bit, waiting 8 hours, circulation was re-established, with the thermosetting composition plug sealing off the massive lost circulation in the Nisku formation.
Example #4 A abandoned well leaked gas from casing.
Pressure and void space in casing was not known. A
low temperature thermosetting composition was used to seal off the void in casing and eliminate gas flow at surface. To do this, surface casing was exposed 2 m below surface. Then, casing was hot-tapped and 100 psi initial pressure recorded that reduced immediately thereafter. Then a lubricator was attached to a valve on casing. 34 liters thermosetting composition was mixed into a slurry @ 40O Celsius, then poured into lubricator and squeezed with service rig pumps to 6500 kPa. The pressure held. Approximately 25 liters of 217~i144 composition was squeezed into casing, the lubricator knocked off and flushed with water. Sample set up in 15 minutes. The thermosetting composition plug sealed off the void in the casing, enabling the crews to cut-off the cap with a cutting torch to put on the BOPs.
Example #5 While drilling at 1643 feet (507 m) the Grosmount formation in Alberta, Canada, was encountered and partial lost returns were experienced.
Drilling continued down to 1665 feet (514 m) where total lost returns occurred. With the lost circulation occurring, a possible gas kick from the exposed Colony formation could take place. 307 sacks of Bentonite, 373 sacks of Sawdust, 128 sacks of Primaseal, 86 sacks of Cellophane were mixed in different lost circulation plugs along with a 660 sack cement plug, all of which were unsuccessful. A gas kick was experienced from the Colony and due to a sloughing formation below that created a bridge, the zone was top killed by pumping weighted drilling fluid down the annulus. The bridge would not allow the drill collars to pull past, thus creating a seal for the annulus.
The drill pipe was pulled to 1555 feet (480 m) and a 6.29 bbls (1.0 cubic meter) low temperature thermosetting plug was spotted by displacing the drill pipe with 12.58 bbls (2.0 m3) of water. The drill pipe was pulled out of the plug to 972 feet (300 m).
5 hours was allowed for setting the plug before circulation. To do this, 158.5 gal us (600 litres) of fresh water was loaded onto an oil field cementer 32 sacks of low temperature thermosetting composition jet mixed off the ground hopper at approximately 15 seconds per sack which yielded 6.29 bbls (1.0 m3).
217~144 The slurry was mixed and pumped down the drill pipe.
It was displaced with 12.58 bbls (2.0 m3) of fresh water. 20 stands of drill pipe were pulled and 5 hours waited for setting. The drill pipe was run in to 450 meters where the top of the plug was found. Full circulation was established and the drill pipe was pulled out of the hole. The production casing was run and cemented above the top of the plug.
Example #6 While drilling the last portion of the Leduc formation (Alberta, Canada) at 5835 feet (1801 m) total lost circulation was encountered. The Glauconite formation kicked gas at approximately 4050 feet (1250 m). Flow from the Glauconite up the annulus peaked at 8 mmcfd. The drill pipe was free to move. Attempts to control the Glauconite were made by top killing the gas zone. Lost circulation material was mixed into 12,580 bbls (2,000 m3) of drilling mud and pumped through the bit into the Leduc with a large amount of pumping pressure and no success in bridging the lost circulation zone. Explosives were utilized to blow the bit and sub off the end of the drill string to achieve higher pump rates. Following the removal of the bit and sub 12,580 bbls (2,000 m3) of LCM pills were pumped into the lost circulation zone without success. A total of eight (8) rig days were spent fighting the lost circulation.
12.0 m3 low temperature thermosetting composition was mixed and pumped with an oilfield cementer and spotted across the Leduc formation. To do this, the drill pipe was landed at 5074 feet (1566 m).
The thermosetting composition was loaded in to a cleaned bulk transport truck and brought to location.
Water was supplied by two 100 bbl (16 m3) tank trucks.
217~i144 A slurry of the thermosetting composition was continuously mixed and pumped down the drill pipe and displaced with 37.7 bbls (6.0 m3) of fresh water.
Waited 8 hours prior to attempting to establish circulation which was successful. Upon retrieving the bottom collar of the drill string it was discovered that the bit and sub were still attached. The only damage made to the drill collar from the explosives was a slight bulge. The nozzles in the bit were blown out by the explosion. The pipe was run back into the well and the plug was drilled down to 5654 feet (1745 m). It was then logged and casing cemented into the well.
Example #7 A well drilled and suspended four (4) years previously experienced a pressure build up of 130 psi (896 kPa) in the surface casing assumed to be a gas zone below the casing shoe. The Regulatory Board would not allow the resource company to cap and abandon the well. Previous attempts were made with cement. The procedure was as follows: perforating the production casing and circulating the cement slurry through the perforations into the annulus and up into the surface casing annulus. Attempts to squeeze cement into the perforation were unfavourable.
The solution proposed in accordance with the invention was to perforate the casing using both shallow and deep penetration charges, then mix 4.0 m3 of low temperature thermosetting composition and squeeze the product into the perforations. To do this, the day before the production casing was perforated below the surface casing shoe form 375.0 to 376.0 m. An injection rate was established into the perforations at 30 litres per minute at 28 mPa. On the day of 217~1~4 treatment 38.1 mm coil tubing (total length 3800 m) were run in to 386 m. 4.0 m3 low temperature thermosetting composition was continuously mixed and pumped 3.2 tonnes down the coil tubing and across the perforations. Once the plug was balanced on bottom the coil was pulled above the plug. 3.0 m3 of the composition was squeezed into the perforations at 80 litres per minute at 1450 psi (10 mPa). Coil tubing was pulled from the well. Due to the well's remote location, a 38.1 mm coil tubing unit was utilized for its economic benefit versus moving in a service rig.
The day after the treatment a pressure recorder was utilized to measure the build up pressure over a 24 hour period. In the first hour the pressure built up to 24 kPa and stayed constant for 24 hours. The pressure that built up was thought to be residual gas from the well and would take a couple of weeks to come to surface.
The setting time of the thermosetting composition of the present invention can be precisely determined through pilot testing of the waters to be used. The thermosetting composition of the present invention can be formulated with fresh water, magnesium chloride brine or sodium chloride brine.
Salinity has no measurable effect upon the hardening reaction. The thermosetting composition of the present invention can be mixed through jet hoppers, in batch mix tanks, pumped with cementing trucks, and spotted open-ended or through the bit. A cement plug made in accordance with the invention requires the same mud conditioning to drill as is used when drilling green cement. Slurries of the invention require no spacers when spotted. Balanced plugs may also be run where required. Once the thermosetting composition of the present invention has been spotted the drillpipe should be pulled up above the pill. The thermosetting composition of the present invention has exponential setting characteristic but do not generate gel strengths, allowing minimum pump pressures throughout the application, due to consistent rheological properties right up to the setting point.
The exothermic and rheological properties of the thermosetting composition of the present invention compounds allow a wide variety of applications, and complement the most up-to-date engineering concepts in placement and workover techniques, including the latest coiled tubing equipment. In horizontal drilling, the thermosetting composition of the present lS invention has the unique capability of providing the facility of selective zone isolation. This together with its compressive strength and extremely fast drillability allows the utilization of the compound across the critical build section of the well with the assured capability of drilling out on track without kicking off.
A particular advantage of the present invention is that the thermosetting composition is suitable for use at various depths. At lower depths, hence lower temperatures, the lower hydrostatic pressure means that the composition will not invade deeply into the formation even though setting time will be slower. In deeper wells, the higher hydrostatic pressure as offset by the faster setting time within the immediate well bore periphery.
A person skilled in the art could make immaterial modifications to the invention described and claimed in this patent without departing from the essence of the invention.
Thermosetting Well Treatment Composition NAME(S) OF INVENTOR(S):
Brian H. Tomlinson FIELD OF THE INVENTION
This invention relates to acid soluble magnesium oxysulphate and oxychloride cement composition~ and their method of use.
P~XGROUND OF THE INVENTION
The use of magnesium oxysulphate or oxychloride cements to plug underground formations during oil and gas well drilling and production is well known. These cements are introduced as slurries into a well bore where they harden against the formation and provide an impermeable block to fluid migration into or from the formation. These cements are also acid solu~le so that once they are no longer needed, acid solutions may be applied to the well to remove the cements.
For example, Canadian patent no. 1,053,892 of Barthel describes a magnesium oxysulphate cement that is mixed with drilling fluid to form a hardenable cement. The magnesium oxysulphate cement is made with an additive comprising magnesium oxide, magnesium sulphate and a filler comprising magnesium carbonate or dolomite.
More .-ecently, United States patents 5,213,161; 5,220,960; and 5,298,069 of Halliburton Company, Oklahoma, have disclosed improvements on magnesium oxychloride cements. These improvements include use of a foaming agent and foam stabilizer, and use of a set retarder comprising a water soluble borate and a sugar.
SU~ARY OF THE INVENTION
These prior art compositions, however, have disadvantages. The use of slow setting compositions, and in particular, the use of a retarder tends to delay the setting time of the composition so that the cement tends to invade deep cracks and pores in the formation to such an extent that subsequent application of acid cannot remove the cement from the formation. This tends to cause loss of permeability, which can be disastrous to subsequent production from the formation.
Further, the inventor has found that it is important that the hardening process, though initially stimulated by the temperature of the cement, rapidly becomes exothermic, and that the cementation process should result in a rapidly setting firm composition.
In addition, the inventor has found that selection of the components of the cement according to the prior art teachings does not uniformly produce satisfactory results. Thus, inappropriate selection of the magnesium sulphate, or the magnesium oxide, used in such a cement may result in lack of controllability of the hardening process.
In one aspect of the invention, the inventor therefore proposes the use of magnesium sulphate trihydrate as th~ magnesium sulphate component in a cement formed of a solids component and an aqueous liquid. Magnesium sulphate trihydrate is unstable and difficult to handle, and is not believed to be an obvious candidate for use as a magnesium oxysulphate or oxychloride cement component. Moreover, it has the feature that the setting of the resulting magnesium cement is thermally triggered and rapidly becomes exothermic such that the cement has an exponential setting curve. The solids component of the cement composition is preferably 33 - 40% by weight magnesium oxide; 35 - 43% by weight of magnesium sulphate trihydrate; and 20 - 27% inert filler, typically calcium carbonate or cement filler. The inert filler must be acid soluble.
In a further aspect of the invention, for low temperature applications, the magnesium oxide is mined and may have impurities, while for high temperature applications, the magnesium oxide is pure, over 99% pure, and is calcined from brine. For high temperature applications, the aqueous liquid is preferably saturated magnesium chloride brine.
The resulting cement compositions, supplied under the trademark THERMAX, are non-invasive non-damaging thermosetting compounds, and are believed to represent a technological advance in the control of formation fluid invasion and lost circulation. The thermosetting composition is applied in pill form to the desired zone where the composition sets like cement but with many added benefits. Applications for the thermosetting composition of the invention include: drilling applications, including lost circulation, formation consolidation, zone isolation, gas shut-off and horizontal drilling; production applications, including zone protection, water blocking, zone isolation. Other applications include mining, seismic hole plugging and salt dome sealing.
The thermosetting composition of the present invention hardens through hydration. Shrinkage is limited to 0.5% or less. The thermosetting composition of the present invention is 100% inorganic and soluble in a 15% oilfield HCl solution. Due to its non-invasive characteristics the thermosetting composition of the present invention allows full return permeability.
BRIEF DESCRIPTION OF THE DRAWINGS
There will now be described preferred embodiments of the invention, with reference to the drawings, by way of illustration, in which like numerals denote like elements and in which:
Fig. 1 is a graph showing setting time for a high temperature thermosetting composition according to the invention having, in 1 m3 of slurry, 793 kg of a composition consisting of about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, about 22.7% inert filler (calcium carbonate and dolomite), 637.5 litres saturated MgCl2 brine and 41.7 kg inhibitor (5% sodium pentaborate);
Fig. 2 is a graph showing return permeability behaviour of berea cores (3" long at 150~F) after acidization of previously applied thermosetting composition according to the invention;
Fig. 3 is a graph showing setting time for a low temperature thermosetting composition according to the invention with and without inhibitor;
Fig. 4 is a graph showing setting time for a high temperature thermosetting composition according to the invention with and without inhibitor;
Fig. 5 is a table showing magnesium chloride solution requirements using 100% sacked MgCl.6H2O (for requirements for one bbl, divide bbls of water and required pounds of MgCl2 by 6.2; and 21751~ ~
Fig. 6 is a table showing sodium chloride solution requirements using 100% sacked NaCl (for requirements for one bbl, divide bbls of water and required pounds of NaCl by 6.2.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
The composition of the invention is an acid soluble, water impermeable, inorganic, thermosetting composition formed from a solids mixture and an aqueous liquid in which the amount of aqueous liquid, magnesium oxide, magnesium sulphate trihydrate and inert filler are selected such that upon setting the composition becomes exothermic and has an exponential setting curve at the temperature T.
The preferred aqueous liquid is a brine formed from calcium chloride, sodium chloride or magnesium chloride. The amount of liquid is preferably about 1 liter of liquid for each 1.25 kg of solids, resulting in a volume increase to about 1.56 liters of slurry. The magnesium chloride solution, particularly for high temperature applications, is preferably saturated MgCl2.6H2O brine. Sea water may be used.
For low temperature applications, namely 15~C - 70~C, the preferred solids composition is about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite (5 micron size). The temperature of calcination of the magnesium oxide may be used to regulate the setting temperature of the thermosetting composition.
For high temperature applications, namely 55~C - 100~C, the preferred solids composition is about 35.8% by weight magnesium oxide, about 41.5%
magnesium sulphate trihydrate, and about 22.7% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite (5 micron size). In the high temperature application, the composition preferably includes 5% sodium pentaborate as an inhibitor to delay the setting time of the thermosetting composition. For high and extra high temperature applications, namely 80~C and higher, the magnesium oxide is preferably calcined from pure brine. For low temperature applications, the magnesium oxide is preferably mined from a magnesite deposit and calcined at between 750~C and 900~C. In this manner, selection of the source and purity of the magnesium oxide allows controllability of the setting time of the composition.
The low temperature thermosetting composition is normally inhibited above 30~C and can be mixed in fresh water and compatible brines (not zinc bromide for example). High temperature thermosetting composition should only be mixed with saturated magnesium chloride brine.
While reasonably precise compositions have been disclosed that are known to work, it is believed that other compositions in the range 33 - 40% by weight magnesium oxide; 35 - 43% by weight of magnesium sulphate trihydrate; and 20 - 27% inert filler will also provide the exponential thermosetting characteristics when mixed with an appropriate aqueous solution.
The magnesium sulphate trihydrate peferably has a bulk density of between 37.68 and 46.31 lbs per cubic foot and a loss on ignition ratio of between 32 and 35~. It has been found that 6uch a magnesium sulphate trihydrate gives greater controllability over 217S14~
the thermosetting process as compared with that disclosed by Barthel.
The thermosetting characteristics of the above described compositions are dictated only by the temperature. They can be extremely rapid or may be slowed down by the use of the inhibitor. Due to hydration, shrinkage on setting is less than 0.5%.
The composition is unaffected by chlorides, and make-up water may be of any salinity. For sealing salt formations saturated NaCl brine is preferred. The composition adheres to salt formations and due to the availability of extremely short setting times, the thermosetting composition provides excellent characteristics for the prevention of microannular gas migration or remediation of channelling.
The exponential hardening characteristics of the thermosetting composition is triggered by the external temperature of the medium in which they are placed. This is normally the temperature of the formation or by addition of special additives. Once this temperature trigger has started the hardening process, then it becomes exothermic and self-generating. In a formation reservoir, the hardening process is accelerated even faster once the thermosetting composition enters the immediate periphery of the wellbore. Although drillpipe, tubing, etc. may still be pulled out of the slurry in the wellbore, away from the wellbore, the set is almost instantaneous with minimum penetration of the formation matrix. Hence, the thermosetting composition provides easy removability of the compound by acidization with full return permeability being possible. For water shut-off where fracture penetration may be required, the use of inhibitors will extend the setting time without any alteration of the exponential properties. The use of a saturated brine (MgCl2) in these circumstances will ensure maximum structural integrity. Use of the brine also ensures the slurry will not be diluted in the placement operation. Figure 1 illustrates a typical exponential setting curve for the invention. It will be appreciated that in cracks in the formation, when the appropriate thermosetting composition is used, the hardening will be almost immediate. A typical return permeability is shown in Fig. 2.
Setting time for low temperature and high temperature compositions of the invention are shown in Figs. 3 and 4 respectively.
The thermosetting composition is an off white powder with a median particle size of 7 microns and a viscosity of 18-30 cP, Slurry Density: 1.44-1.6 kg/l (11.9-13.37 ppg), depending on Mix Water. Bulk Density is 3.0 gm/cc. Compressive Strength 24 hour compressive strength for the low temperature composition varies as follows: 650 psi mixed with fresh water, 1500 psi mixed with saturated NaCl, 1950 psi mixed with saturated MgCl2. For the high temperature composition, the 24 hour compressive strength is 900 psi when mixed with saturated magnesium chloride. The set composition, whether high or low temperature composition, is 100% acid soluble in 15% HCl and requires approximately seven m3 (43.4 bbls) of 15% HCl to remove one m3 (6.2 bbls) of the set composition. A ratio of seven bbls to one bbls allows for possible 100% return permeability.
In the method of the invention, a thermosetting composition according to the invention includes mixing and injecting the thermosetting 2175~44 composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone; removing the tubing from adjacent the zone; and allowing the composition to set at least adjacent the zone. The mixing is preferably carried out on the fly.
In the preparation of the invention, the following steps are carried out: Calculate the volume of required slurry, calculate the final volume of water or brine, calculate the kilograms of thermosetting composition, use the attached graphs to determine setting time, calculate the final slurry density (kg/m3), determine the amount of Inhibitor, if required, from the attached graphs (see Figs. 3 and 4). Steps: fill the tank with water as calculated in step two above, add Inhibitor, if required, as calculated above, and agitate for 10 to 15 minutes, add MgCl2 or NaCl if required, add thermosetting composition, with vigorous agitation, as calculated above, displace the slurry into the well with a pumping unit.
Requirements of less than two cubic metres will be batch mixed. For larger volume applications, the composition will be continuously mixed through standard oilfield cementing equipment. Maintain the slurry density at +/-10 kg/m3 of the density calculated above. Maximum inhibitor concentration should not exceed 5% by dry weight of the solids composition (i.e. maximum 40 kg of inhibitor/m3 of slurry). It is recommended that the composition be mixed with magnesium chloride brine for maximum compressive strength.
Example #1 In September, 1993, a well in Alberta, Canada, had been shut in for some years. A
217~ 1 44 radioactive tracer had shown communication between the Cardium Conglomerate above Cardium sandstone in Alberta, Canada. Top of the production perforations was only 4 feet from the conglomerate. To solve the problem, a packer was set between sand and conglomerate, with a retainer at top of conglomerate (conglomerate interval perforated). Then tubing was inserted into the retainer and the conglomerate squeezed off with a low temperature thermosetting composition described above. 1.0 m3 of the low temperature thermosetting composition was batch mixed into a pumper and squeezed over a perforation interval of 6.4 m. Squeezing was to ~ust below fracture gradient at 4 mPa. The tubing was pulled out of the retainer. 24 hours later, the retainer and cement was drilled out to the packer, then the well pressure tested to 600 psi. After drilling out the packer and re-perforating the Cardium sandstone, it was found that the thermosetting composition successfully shut off vertical communication outside the casing.
Example #2 In this well, the producing zone watered out from migrating fluid below production zone. Log report indicated water was channelling upward along sides of the casing. A sleeved retainer was set 10 m below production zone. Then a high density perforating gun was used to make staggered radial perforations at 150 intervals. The thermosetting composition was displaced to the bottom of the tubing, the annulus closed in and the composition squeeze to seal water invasion. After squeezing, the tubing was removed, the composition allowed to set for 12 hours then drilled out. The well swabbed dry and stood full.
After perforating the production zone, the well surged 3 - 4 m3 of fluid with no the water invasion.
Example #3 An upper hole gas zone was encountered while drilling 311 mm hole in the Colony formation plus total lost circulation after drilling the Nisku (fractured carbonate). The well was drilled ahead blind to horizontal casing depth of 891 m. Over 6500 m3 of LCM pumped with no results (Nisku on vacuum).
Unable to pull out of the hole due to pack-off above the bit which allowed circulation down the backside to control the gas influx. To solve this, a thermosetting composition plug was established from the top of the Nisku at 723 m to total depth by displacement through the drill bit. Procedure Jet mixed a total of 10 MT
Thermax Lt (12.5 m3) with cementing unit and displaced through the bit. After pulling out, packing-off, clearing the drill bit, waiting 8 hours, circulation was re-established, with the thermosetting composition plug sealing off the massive lost circulation in the Nisku formation.
Example #4 A abandoned well leaked gas from casing.
Pressure and void space in casing was not known. A
low temperature thermosetting composition was used to seal off the void in casing and eliminate gas flow at surface. To do this, surface casing was exposed 2 m below surface. Then, casing was hot-tapped and 100 psi initial pressure recorded that reduced immediately thereafter. Then a lubricator was attached to a valve on casing. 34 liters thermosetting composition was mixed into a slurry @ 40O Celsius, then poured into lubricator and squeezed with service rig pumps to 6500 kPa. The pressure held. Approximately 25 liters of 217~i144 composition was squeezed into casing, the lubricator knocked off and flushed with water. Sample set up in 15 minutes. The thermosetting composition plug sealed off the void in the casing, enabling the crews to cut-off the cap with a cutting torch to put on the BOPs.
Example #5 While drilling at 1643 feet (507 m) the Grosmount formation in Alberta, Canada, was encountered and partial lost returns were experienced.
Drilling continued down to 1665 feet (514 m) where total lost returns occurred. With the lost circulation occurring, a possible gas kick from the exposed Colony formation could take place. 307 sacks of Bentonite, 373 sacks of Sawdust, 128 sacks of Primaseal, 86 sacks of Cellophane were mixed in different lost circulation plugs along with a 660 sack cement plug, all of which were unsuccessful. A gas kick was experienced from the Colony and due to a sloughing formation below that created a bridge, the zone was top killed by pumping weighted drilling fluid down the annulus. The bridge would not allow the drill collars to pull past, thus creating a seal for the annulus.
The drill pipe was pulled to 1555 feet (480 m) and a 6.29 bbls (1.0 cubic meter) low temperature thermosetting plug was spotted by displacing the drill pipe with 12.58 bbls (2.0 m3) of water. The drill pipe was pulled out of the plug to 972 feet (300 m).
5 hours was allowed for setting the plug before circulation. To do this, 158.5 gal us (600 litres) of fresh water was loaded onto an oil field cementer 32 sacks of low temperature thermosetting composition jet mixed off the ground hopper at approximately 15 seconds per sack which yielded 6.29 bbls (1.0 m3).
217~144 The slurry was mixed and pumped down the drill pipe.
It was displaced with 12.58 bbls (2.0 m3) of fresh water. 20 stands of drill pipe were pulled and 5 hours waited for setting. The drill pipe was run in to 450 meters where the top of the plug was found. Full circulation was established and the drill pipe was pulled out of the hole. The production casing was run and cemented above the top of the plug.
Example #6 While drilling the last portion of the Leduc formation (Alberta, Canada) at 5835 feet (1801 m) total lost circulation was encountered. The Glauconite formation kicked gas at approximately 4050 feet (1250 m). Flow from the Glauconite up the annulus peaked at 8 mmcfd. The drill pipe was free to move. Attempts to control the Glauconite were made by top killing the gas zone. Lost circulation material was mixed into 12,580 bbls (2,000 m3) of drilling mud and pumped through the bit into the Leduc with a large amount of pumping pressure and no success in bridging the lost circulation zone. Explosives were utilized to blow the bit and sub off the end of the drill string to achieve higher pump rates. Following the removal of the bit and sub 12,580 bbls (2,000 m3) of LCM pills were pumped into the lost circulation zone without success. A total of eight (8) rig days were spent fighting the lost circulation.
12.0 m3 low temperature thermosetting composition was mixed and pumped with an oilfield cementer and spotted across the Leduc formation. To do this, the drill pipe was landed at 5074 feet (1566 m).
The thermosetting composition was loaded in to a cleaned bulk transport truck and brought to location.
Water was supplied by two 100 bbl (16 m3) tank trucks.
217~i144 A slurry of the thermosetting composition was continuously mixed and pumped down the drill pipe and displaced with 37.7 bbls (6.0 m3) of fresh water.
Waited 8 hours prior to attempting to establish circulation which was successful. Upon retrieving the bottom collar of the drill string it was discovered that the bit and sub were still attached. The only damage made to the drill collar from the explosives was a slight bulge. The nozzles in the bit were blown out by the explosion. The pipe was run back into the well and the plug was drilled down to 5654 feet (1745 m). It was then logged and casing cemented into the well.
Example #7 A well drilled and suspended four (4) years previously experienced a pressure build up of 130 psi (896 kPa) in the surface casing assumed to be a gas zone below the casing shoe. The Regulatory Board would not allow the resource company to cap and abandon the well. Previous attempts were made with cement. The procedure was as follows: perforating the production casing and circulating the cement slurry through the perforations into the annulus and up into the surface casing annulus. Attempts to squeeze cement into the perforation were unfavourable.
The solution proposed in accordance with the invention was to perforate the casing using both shallow and deep penetration charges, then mix 4.0 m3 of low temperature thermosetting composition and squeeze the product into the perforations. To do this, the day before the production casing was perforated below the surface casing shoe form 375.0 to 376.0 m. An injection rate was established into the perforations at 30 litres per minute at 28 mPa. On the day of 217~1~4 treatment 38.1 mm coil tubing (total length 3800 m) were run in to 386 m. 4.0 m3 low temperature thermosetting composition was continuously mixed and pumped 3.2 tonnes down the coil tubing and across the perforations. Once the plug was balanced on bottom the coil was pulled above the plug. 3.0 m3 of the composition was squeezed into the perforations at 80 litres per minute at 1450 psi (10 mPa). Coil tubing was pulled from the well. Due to the well's remote location, a 38.1 mm coil tubing unit was utilized for its economic benefit versus moving in a service rig.
The day after the treatment a pressure recorder was utilized to measure the build up pressure over a 24 hour period. In the first hour the pressure built up to 24 kPa and stayed constant for 24 hours. The pressure that built up was thought to be residual gas from the well and would take a couple of weeks to come to surface.
The setting time of the thermosetting composition of the present invention can be precisely determined through pilot testing of the waters to be used. The thermosetting composition of the present invention can be formulated with fresh water, magnesium chloride brine or sodium chloride brine.
Salinity has no measurable effect upon the hardening reaction. The thermosetting composition of the present invention can be mixed through jet hoppers, in batch mix tanks, pumped with cementing trucks, and spotted open-ended or through the bit. A cement plug made in accordance with the invention requires the same mud conditioning to drill as is used when drilling green cement. Slurries of the invention require no spacers when spotted. Balanced plugs may also be run where required. Once the thermosetting composition of the present invention has been spotted the drillpipe should be pulled up above the pill. The thermosetting composition of the present invention has exponential setting characteristic but do not generate gel strengths, allowing minimum pump pressures throughout the application, due to consistent rheological properties right up to the setting point.
The exothermic and rheological properties of the thermosetting composition of the present invention compounds allow a wide variety of applications, and complement the most up-to-date engineering concepts in placement and workover techniques, including the latest coiled tubing equipment. In horizontal drilling, the thermosetting composition of the present lS invention has the unique capability of providing the facility of selective zone isolation. This together with its compressive strength and extremely fast drillability allows the utilization of the compound across the critical build section of the well with the assured capability of drilling out on track without kicking off.
A particular advantage of the present invention is that the thermosetting composition is suitable for use at various depths. At lower depths, hence lower temperatures, the lower hydrostatic pressure means that the composition will not invade deeply into the formation even though setting time will be slower. In deeper wells, the higher hydrostatic pressure as offset by the faster setting time within the immediate well bore periphery.
A person skilled in the art could make immaterial modifications to the invention described and claimed in this patent without departing from the essence of the invention.
Claims (30)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:
1. An acid soluble, water impermeable, inorganic, thermosetting composition for use in sealing an underground permeable zone having a known temperature T, the composition comprising a solids mixture and an aqueous liquid in which the solids mixture includes:
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate;
20 - 27% inert filler;
the amount of aqueous liquid, magnesium oxide, magnesium sulphate and inert filler being selected such that upon setting the composition becomes exothermic and thereby has an exponential setting curve at the temperature T.
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate;
20 - 27% inert filler;
the amount of aqueous liquid, magnesium oxide, magnesium sulphate and inert filler being selected such that upon setting the composition becomes exothermic and thereby has an exponential setting curve at the temperature T.
2. The thermosetting composition of claim 1 in which the aqueous liquid is a brine including a salt selected from the group comprising calcium chloride, sodium chloride and magnesium chloride.
3. The thermosetting composition of claim 1 in which the composition includes about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite.
4. The thermosetting composition of claim 3 in which the magnesium oxide is mined magnesium oxide.
5. The thermosetting composition of claim 4 in which aqueous liquid is present in the ratio of about 1 liter of aqueous liquid for each 1.25 kg of solids.
6. The thermosetting composition of claim 1 in which the composition includes about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, and about 22.7% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite, and the aqueous solution being magnesium chloride solution.
7. The thermosetting composition of claim 6 in which the magnesium oxide is calcined from magnesium brine.
8. The thermosetting composition of claim 7 in which the magnesium oxide includes no more than about 1% by weight impurities.
9 The thermosetting composition of claim 7 in which the aqueous liquid is a saturated MgCl2.6H2O
brine.
brine.
10. The thermosetting composition of claim 9 in which the aqueous liquid is present in the amount of about 1 liter of aqueous liquid for each 1.25 kg of solids.
11. A method of sealing an underground permeable zone penetrated by a well bore, the method comprising the steps of:
mixing together a solids mixture and an aqueous liquid in which the solids mixture includes:
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate;
20 - 27% inert filler;
the amount of aqueous liquid, magnesium oxide, magnesium sulphate and inert filler being selected such that upon setting the composition becomes exothermic and thereby has an exponential setting curve at the temperature T, thereby being capable of forming an acid soluble, water impermeable, inorganic, thermosetting composition;
injecting the thermosetting composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone;
removing the tubing from adjacent the zone before the thermosetting composition solidifies at its center; and allowing the composition to set at least adjacent the zone.
mixing together a solids mixture and an aqueous liquid in which the solids mixture includes:
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate;
20 - 27% inert filler;
the amount of aqueous liquid, magnesium oxide, magnesium sulphate and inert filler being selected such that upon setting the composition becomes exothermic and thereby has an exponential setting curve at the temperature T, thereby being capable of forming an acid soluble, water impermeable, inorganic, thermosetting composition;
injecting the thermosetting composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone;
removing the tubing from adjacent the zone before the thermosetting composition solidifies at its center; and allowing the composition to set at least adjacent the zone.
12. The method of claim 11 in which mixing the solids mixture and the aqueous liquid is carried out on the fly.
13. The method of claim 11 in which the well bore lies substantially horizontally in the permeable zone.
14. The method of claim 11 further comprising selecting the source and purity of the magnesium oxide in order to control setting time of the thermosetting composition.
15. An acid soluble, inorganic, thermosetting composition for use in sealing an underground permeable zone having a known temperature T, the composition comprising a solids mixture, in which the solids mixture includes:
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate; and 20 - 27% acid soluble inert filler.
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate; and 20 - 27% acid soluble inert filler.
16. The thermosetting composition of claim 15 in which the composition includes about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite.
17. The thermosetting composition of claim 16 in which the magnesium oxide is mined magnesium oxide.
18. The thermosetting composition of claim 15 in which the composition includes about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, and about 22.7% inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite.
19. The thermosetting composition of claim 18 further including up to about 5% by weight of an inhibitor for inhibiting the setting time of the composition.
20. A method of sealing an underground permeable zone penetrated by a well bore, the method comprising the steps of:
mixing together a solids mixture and an aqueous liquid in which the solids mixture includes:
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate;
20 - 27% acid soluble inert filler;
in which the aqueous solution is water or brine;
the aqueous liquid being present in the amount of about 1 liter for each 1.25 kg of solids mixture thereby being capable of forming an acid soluble, water impermeable, inorganic, exothermic, thermosetting composition;
injecting the thermosetting composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone;
removing the tubing from adjacent the zone before the thermosetting composition solidifies at its center but after the thermosetting composition has solidified in the immediate periphery of the wellbore;
and allowing the composition to set at least adjacent the zone.
mixing together a solids mixture and an aqueous liquid in which the solids mixture includes:
33 - 40% by weight magnesium oxide;
35 - 43% by weight of magnesium sulphate trihydrate;
20 - 27% acid soluble inert filler;
in which the aqueous solution is water or brine;
the aqueous liquid being present in the amount of about 1 liter for each 1.25 kg of solids mixture thereby being capable of forming an acid soluble, water impermeable, inorganic, exothermic, thermosetting composition;
injecting the thermosetting composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone;
removing the tubing from adjacent the zone before the thermosetting composition solidifies at its center but after the thermosetting composition has solidified in the immediate periphery of the wellbore;
and allowing the composition to set at least adjacent the zone.
21. The method of claim 20 in which the aqueous solution is brine and the brine is selected from the group comprising sodium chloride brine, magnesium chloride brine and calcium chloride brine.
22. A method of making an acid soluble, water impermeable, inorganic, thermosetting composition for use in sealing an underground permeable zone having a known temperature T, the method comprising the steps of:
preparing a solids mixture including 33 - 40% by weight magnesium oxide, 35 - 43% by weight of magnesium sulphate trihydrate, and 20 - 27% acid soluble inert filler, wherein (A) when T is less than 55°C, the magnesium oxide is mined magnesium oxide that has been calcined at between 750°C and 900°C, (B) when T is 55°C to 70°C the magnesium oxide is selected from the group comprising mined magnesium oxide that has been calcined at between 750°C and 900°C and magnesium oxide that has been calcined from a pure magnesium brine, and (C) when T is greater than 70°C the magnesium oxide is calcined from a pure magnesium brine; and mixing the solids mixture with an aqueous solution, at a ratio of 1 liter of aqueous solution to each 1.25 kg of solids mixture.
preparing a solids mixture including 33 - 40% by weight magnesium oxide, 35 - 43% by weight of magnesium sulphate trihydrate, and 20 - 27% acid soluble inert filler, wherein (A) when T is less than 55°C, the magnesium oxide is mined magnesium oxide that has been calcined at between 750°C and 900°C, (B) when T is 55°C to 70°C the magnesium oxide is selected from the group comprising mined magnesium oxide that has been calcined at between 750°C and 900°C and magnesium oxide that has been calcined from a pure magnesium brine, and (C) when T is greater than 70°C the magnesium oxide is calcined from a pure magnesium brine; and mixing the solids mixture with an aqueous solution, at a ratio of 1 liter of aqueous solution to each 1.25 kg of solids mixture.
23. The method of claim 22 wherein the aqueous solution is selected from the group comprising water and brine, and the brine includes a salt selected from the group comprising magnesium chloride, sodium chloride and calcium chloride.
24. The method of claim 23 in which the aqueous solution is saturated magnesium chloride brine.
25. The method of claim 22 in which:
if T is less than about 80°C, the solids mixture includes about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24%
acid soluble inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite; and if T is about 80°C or more, the solids mixture includes about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, and about 22.7% acid soluble inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite.
if T is less than about 80°C, the solids mixture includes about 38% by weight magnesium oxide, about 38% magnesium sulphate trihydrate, and about 24%
acid soluble inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite; and if T is about 80°C or more, the solids mixture includes about 35.8% by weight magnesium oxide, about 41.5% magnesium sulphate trihydrate, and about 22.7% acid soluble inert filler, the inert filler being selected from the group comprising calcium carbonate and dolomite.
26. The method of claim 25 further including mixing with the solids mixture up to about 5% by weight of an inhibitor for inhibiting the setting time of the composition.
27. The method of claim 22 in which the magnesium oxide includes no more than about 1% by weight impurities.
28. The method of claim 22 further including the steps of:
injecting the thermosetting composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone;
removing the tubing from adjacent the zone before the thermosetting composition solidifies at its center but after the thermosetting composition has solidified in the immediate periphery of the wellbore;
and allowing the composition to set at least adjacent the zone.
injecting the thermosetting composition into the well bore adjacent the zone through tubing to fill the well bore adjacent the zone;
removing the tubing from adjacent the zone before the thermosetting composition solidifies at its center but after the thermosetting composition has solidified in the immediate periphery of the wellbore;
and allowing the composition to set at least adjacent the zone.
29. The method of claim 28 further including mixing with the solids mixture up to about 5% by weight of an inhibitor for inhibiting the setting time of the composition.
30. The method of claim 22 further including mixing with the solids mixture up to about 5% by weight of an inhibitor for inhibiting the setting time of the composition.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA002175144A CA2175144A1 (en) | 1996-04-26 | 1996-04-26 | Thermosetting well treatment composition |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA002175144A CA2175144A1 (en) | 1996-04-26 | 1996-04-26 | Thermosetting well treatment composition |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2175144A1 true CA2175144A1 (en) | 1997-10-27 |
Family
ID=4158084
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002175144A Abandoned CA2175144A1 (en) | 1996-04-26 | 1996-04-26 | Thermosetting well treatment composition |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2175144A1 (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| RU2630824C1 (en) * | 2016-06-17 | 2017-09-13 | Общество с ограниченной ответственностью "МИРРИКО" | Repair-insulating grouting composition |
| US11499085B1 (en) * | 2021-11-29 | 2022-11-15 | Baker Hughes Oilfield Operations Llc | Composition and method for controlling lost circulation |
-
1996
- 1996-04-26 CA CA002175144A patent/CA2175144A1/en not_active Abandoned
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| RU2630824C1 (en) * | 2016-06-17 | 2017-09-13 | Общество с ограниченной ответственностью "МИРРИКО" | Repair-insulating grouting composition |
| US11499085B1 (en) * | 2021-11-29 | 2022-11-15 | Baker Hughes Oilfield Operations Llc | Composition and method for controlling lost circulation |
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