US20200171410A1 - Oil and Gas Well Primary Separation Device - Google Patents
Oil and Gas Well Primary Separation Device Download PDFInfo
- Publication number
- US20200171410A1 US20200171410A1 US16/787,006 US202016787006A US2020171410A1 US 20200171410 A1 US20200171410 A1 US 20200171410A1 US 202016787006 A US202016787006 A US 202016787006A US 2020171410 A1 US2020171410 A1 US 2020171410A1
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- Prior art keywords
- screen
- gas
- housing
- perforations
- sand
- 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
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- 238000000926 separation method Methods 0.000 title claims abstract description 28
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 34
- 239000004576 sand Substances 0.000 claims abstract description 29
- 238000004519 manufacturing process Methods 0.000 claims abstract description 20
- 238000005520 cutting process Methods 0.000 claims abstract description 18
- 239000003345 natural gas Substances 0.000 claims abstract description 17
- 238000002955 isolation Methods 0.000 claims abstract description 16
- 239000007788 liquid Substances 0.000 claims abstract description 13
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 9
- 239000006185 dispersion Substances 0.000 claims abstract description 4
- 239000012530 fluid Substances 0.000 claims description 49
- 239000007789 gas Substances 0.000 claims description 41
- 239000007787 solid Substances 0.000 claims description 16
- 238000000034 method Methods 0.000 claims description 12
- 239000003921 oil Substances 0.000 claims description 11
- 239000002245 particle Substances 0.000 claims description 11
- 239000013049 sediment Substances 0.000 claims description 8
- 239000000203 mixture Substances 0.000 claims description 4
- 238000004140 cleaning Methods 0.000 claims description 3
- 239000000470 constituent Substances 0.000 claims description 3
- 239000008239 natural water Substances 0.000 claims description 3
- 238000004891 communication Methods 0.000 claims description 2
- 230000001419 dependent effect Effects 0.000 claims description 2
- 230000005484 gravity Effects 0.000 claims description 2
- 230000014759 maintenance of location Effects 0.000 claims description 2
- 238000001914 filtration Methods 0.000 claims 1
- 230000007246 mechanism Effects 0.000 claims 1
- 238000005553 drilling Methods 0.000 description 5
- 230000008569 process Effects 0.000 description 5
- 229910000831 Steel Inorganic materials 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 3
- 238000005755 formation reaction Methods 0.000 description 3
- 230000033001 locomotion Effects 0.000 description 3
- 239000011435 rock Substances 0.000 description 3
- 239000010959 steel Substances 0.000 description 3
- 230000008901 benefit Effects 0.000 description 2
- 230000007423 decrease Effects 0.000 description 2
- 238000007789 sealing Methods 0.000 description 2
- 229910001220 stainless steel Inorganic materials 0.000 description 2
- 239000010935 stainless steel Substances 0.000 description 2
- 230000000638 stimulation Effects 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- 230000004888 barrier function Effects 0.000 description 1
- 230000033228 biological regulation Effects 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 239000003795 chemical substances by application Substances 0.000 description 1
- 230000001627 detrimental effect Effects 0.000 description 1
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- 239000002360 explosive Substances 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
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- 238000003860 storage Methods 0.000 description 1
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Images
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D19/00—Degasification of liquids
- B01D19/0031—Degasification of liquids by filtration
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/35—Arrangements for separating materials produced by the well specially adapted for separating solids
Definitions
- This invention relates to oil and gas well completion and production.
- a vertical hole is drilled in a formation down to a depth below the water table, and steel casing is inserted into the borehole and cemented in place, thus providing an impermeable barrier between the water table and borehole.
- Vertical drilling continues to a depth called the “kick-off” point, where the wellbore begins curving to become horizontal.
- One advantage of horizontal drilling is that it is possible to drill several wells from only one drilling pad, minimizing the impact to the surface environment.
- the drill pipe is removed from the borehole, and additional steel casing is inserted through the full length of the wellbore and cemented in place.
- the drilling rig is then removed and preparations for well completion are then undertaken.
- the first step is to create a connection between the final casing and the reservoir rock.
- a device known as a perforating gun equipped with shaped explosive charges, is lowered into the wellbore down to the layer containing oil and/or natural gas.
- the perforating gun is then fired, which creates holes through the casing, cement, and into the target reservoir rock.
- a mixture of water, sand and other chemicals is pumped into the deep underground reservoir formations, which creates fractures in the reservoir rock.
- a propping agent usually sand carried by the high viscosity fluid, is pumped into the fractures to keep them from closing when the pumping pressure is released.
- This initial stimulation segment is then isolated with a specially designed plug inserted into the steel casing to seal off the perforated (and thus the fractured reservoir) and prevent production from the isolated section.
- the perforating gun is then moved to the next stage of the wellbore to perform the same process, which is then hydraulically fractured in the same manner. This process is repeated along the entire horizontal section of the well, which may extend several miles.
- the isolation plugs are drilled out and production begins. Initially water, and then natural gas or oil flows into the horizontal casing and up the wellbore. In the course of initial production of the well, approximately 15 to 50% of the fracturing fluid may be recovered, a process known as “flowback.” The purpose of the flowback is to safely recover these substances from the well and transition the marketable hydrocarbons of the well stream to a sales pipeline or storage tank. The fracturing fluid is then either recycled to be used on other fracturing operations or safely disposed of according to government regulations.
- the fracturing process described above requires equipment to handle and separate drilled isolation plug cuttings along with large volumes of sand, fracturing fluids, and oil and natural gas.
- the drilled isolation plug cuttings and sand need to be separated to keep from plugging other fluid clean up and separation equipment, which may cause a loss of circulation detrimental to downhole tools. Accordingly, a device is needed to efficiently separate drilled isolation plug cuttings, sand, fracturing fluids and oil and natural gas during a flowback process of production of fluids from the wellbore.
- An object of the invention is to accomplish one or more of the following:
- an apparatus for primary separation in fracking operations that combines isolation plug cutting separation, sand separation, and gas separation in a single separation assembly.
- inventions disclosed herein relate to an apparatus for separating natural gas from high pressure, high velocity production streams comprising a liquid dispersion of water, sand, natural gas, and isolation plug cuttings.
- the apparatus includes a housing having a first end and a second end, and an interior cavity extending therebetween, and an inlet port disposed at said first end of said housing.
- a flow sleeve is disposed within said interior cavity of said housing and extending from said first end to said second end of said housing, and a first screen is disposed within said flow sleeve and in fluid communication with said inlet port.
- An annulus is formed between an outer diameter of said first screen and an inner diameter of said flow sleeve.
- a baffle is disposed within said interior cavity at said second end of said housing, and said baffle is arranged and designed to enhance separation of said production stream into its constituents, a liquid drain in a lower portion of said housing, a second screen coupled to an upper portion of said housing, and a gas outlet.
- FIG. 1A illustrates a cross-section view of a primary separator in accordance with one or more embodiments of the present disclosure
- FIG. 1B illustrates an enlarged cross-section view of a second end of the primary separator of FIG. 1A ;
- FIG. 2 the primary separator of FIG. 1A on location.
- FIG. 1 illustrates a cross-section view of a primary separator 100 in accordance with one or more embodiments of the present disclosure.
- the primary separator 100 includes a generally cylindrical main housing 102 having a first flange 104 on a first end and a second flange 106 on a second end.
- the main housing 102 complies with all PSL-3 NACE H 2 S specifications.
- the main housing 102 is rated for pressures of at least 5,000 psi, 10,000 psi, 15,000 psi, and up to 20,000 psi.
- a generally cylindrical interior cavity 108 or bore is formed within the main housing 102 .
- An inlet port 110 may be coupled to the main housing 102 by way of a first adaptor 112 that is fastened to the first flange 104 with one or more threaded fasteners 114 .
- Valves 116 , 118 may be disposed between the inlet port 110 and adaptor 112 .
- Valves 116 , 118 may be gate valves, either manually or hydraulically operated, or other valves known to one of ordinary skill in the art for opening or closing inlet port 110 to allow production fluid to enter the primary separator 100 .
- inlet port 110 may be fastened directly to the first flange 104 of the main housing 102 .
- a pressure gauge 137 may be coupled to the inlet port 110 and arranged and designed to monitor pressure entering the inlet port 110 .
- a second adaptor 120 may be fastened to the second flange 106 of the main housing 102 by way of one or more fasteners (not shown). Further, an end cap 122 may have an internal thread that engages an external thread of the second adaptor 120 and is threaded thereon. The end cap 122 is preferably removable from the second adaptor 120 . Alternatively, the end cap 122 may be attached directly to the second flange 106 of the main housing 102 by way of one or more threaded fasteners.
- the main housing 102 further includes a top flange 124 .
- a top flow adaptor 126 is disposed within the top flange 124 and secured therein by way of one or more threaded fasteners 128 .
- the top flow adaptor 126 may have a flow channel therein that decreases in diameter from a bottom surface of the flow adaptor to the top surface.
- One or more sealing members 130 may be installed between the top flow adaptor 126 and the top flange 124 .
- the main housing 102 also includes a bottom flange 130 .
- a bottom flow adaptor 132 or flow block is disposed within the bottom flange 130 and secured therein by way of one or more threaded fasteners 134 .
- the bottom flow adaptor 132 may have a flow channel therein that decreases in diameter from a top surface of the flow adaptor to a bottom surface.
- One or more sealing members 136 may be installed between the bottom flow adaptor 132 and the bottom flange 130 .
- the bottom flow adaptor 132 includes an outlet port 138 or drain through which fluid or sediment may flow out of the main housing 102 .
- a pressure gauge 139 may be coupled to the main housing 102 and arranged and designed to monitor pressure within the interior cavity 108 of the main housing 102 .
- a screen assembly 140 is disposed within the interior cavity 108 of the main housing 102 .
- the screen assembly 140 includes a flow sleeve 142 that extends within the interior cavity 108 of the main housing from a first end to a second end of the main housing 102 .
- a first end of the flow sleeve 142 is threaded within the first flange 104 of the main housing 102 and abuts the first adaptor 112 coupled to the first flange 104 .
- a second end of the flow sleeve 142 is threaded within the second flange 106 and abuts the second adaptor 120 .
- the flow sleeve 142 is preferably a hollow cylindrical tube having an inner diameter of at least about 3 inches, 4 inches, or 5 inches, up to about 6 inches, 7 inches or 8 inches.
- the flow sleeve 142 has one or more ports 145 a and 145 b located proximate the second end of the flow sleeve 142 , which allow gas and fluid to exit the flow sleeve 142 and enter the interior cavity 108 of the main housing 102 .
- upper port 145 a may have a diameter of at least about 1 ⁇ 2 inch, 3 ⁇ 4 inch, or 1 inch, up to about 11 ⁇ 2 inches, 13 ⁇ 4 inches, or 2 inches.
- Lower port 145 b may have a diameter of at least about 11 ⁇ 2 inches, 2 inches, or 21 ⁇ 2 inches, up to about 3 inches or 4 inches.
- a screen 144 is disposed within the flow sleeve 142 .
- the screen 144 is concentrically oriented within the flow sleeve 142 and extends axially within the flow sleeve 142 .
- a first end of the screen 144 has a collar 146 attached thereto (e.g., welded).
- the collar 146 is adapted to fit within a seat or pocket 113 of the first adaptor 112 coupled to the first flange 104 .
- a second end of the screen 144 has a collar 148 attached thereto (e.g., threaded as shown, or welded).
- the collar 148 is adapted to fit within the second adaptor 120 and extend through an aperture in the end cap 122 .
- the collar 148 has a flange 149 , which abuts between surfaces of the second adaptor 120 and the end cap 122 .
- the interface between the flange 149 of the collar 148 between the second adaptor 120 and the end cap 122 prevents movement of the screen 142 in an axial direction. Removal of the end cap 122 allows the screen 142 to be removed, either for replacement or cleaning.
- the screen 144 is preferably a stainless steel hollow cylindrical tube that has a plurality of perforations to allow a fluid to enter the hollow tube and radially exit the screen through the plurality of perforations.
- the screen may have an inner diameter of at least about 1 inch, 2 inches, or 3 inches, up to about 4 inches, 5 inches, or 6 inches.
- An annulus 143 is formed between an outer diameter of the screen 144 and an inner diameter of the flow sleeve 142 .
- Perforations in the screen 144 may have a diameter of at least about 1 ⁇ 8 inch, 1 ⁇ 4 inch, or 3 ⁇ 8 inch up to about 1 ⁇ 2 inch, 9/16 inch, 5 ⁇ 8 inch, 3 ⁇ 4 inch, or 1 inch. In other embodiments, perforations in the screen 144 may have a diameter of up to about 11 ⁇ 2 inches, 2 inch, or 3 inches.
- a baffle 150 is located within the interior cavity 108 at a second end of the main housing 102 proximate the second flange 106 .
- the baffle 150 is preferably a plate welded or otherwise attached to an outer diameter of the flow sleeve 142 .
- the plate may be at least about 1 inch in thickness, and up to about 3 inches in thickness.
- the baffle 150 is extends radially outward from the outer diameter of the flow sleeve 142 towards an inner wall of the housing 102 .
- the baffle 150 is sized to have an outer diameter that is less than an inner diameter of the housing 102 so that an upper passageway 152 and a lower passageway 154 (e.g., gaps) are formed there between.
- the baffle 150 is arranged and designed to distribute fluid flow exiting from ports 145 a and 145 b into a larger pattern within the interior cavity 108 of the housing 102 and to further separate gas from fluids.
- a gas separator assembly 160 is coupled to the top flow adaptor 126 by way of one or more threaded fasteners 162 .
- the gas separator assembly 160 includes a riser spool or lower body 164 having a central bore there through.
- An outlet body 166 having one or more outlets 168 , both radial and longitudinal, may be coupled to the lower body 164 by way one or more threaded fasteners 169 .
- a blind flange 170 may be disposed over at least one of the radial outlets thereby directing fluid out remaining radial outlets 168 .
- a tree cap 170 may be fastened to the outlet body 166 by way of one or more threaded fasteners 171 .
- the gas separator assembly 160 may comprise or be formed as a single integral housing attached to the top flow adaptor 126 of the main housing 102 and comprising the individual components previously described in a single integral component.
- the gas separator assembly 160 further includes a screen 178 disposed therein.
- the screen 178 is preferably a stainless steel hollow cylindrical tube that has a plurality of perforations to allow a fluid to enter the hollow tube and radially exit the screen through the plurality of perforations.
- the screen 178 may have an outer diameter of at least about 1 inch, 2 inches, or 3 inches, up to about 4 inches, 5 inches or 6 inches.
- Perforations in the screen 178 may have a diameter of at least about 20 microns, 30 microns, or 40 microns, up to about 50 microns, 60 microns, 70 microns or 80 microns. In other embodiments, the perforations may have a diameter up to about 1 ⁇ 8 inch, 1 ⁇ 4 inch, 1 ⁇ 2 inch or 1 inch.
- a lower end of the screen 178 may be installed in a seat 180 attached within a lower end of the lower body 164 .
- the seat 180 may be welded within the lower body 164 .
- An upper end of the screen 178 may comprise a collar 182 , attached to the screen 178 , either welded or threaded.
- the collar 182 is adapted to fit within the tree cap 172 and extend through an aperture in the threaded cap 174 . Removal of the threaded cap 174 allows the screen 178 to be removed, either for replacement or cleaning.
- the collar 182 may have a needle valve 176 or the like installed therein for pressure adjustment within the gas separator assembly 160 .
- FIG. 2 is a simplified schematic showing the primary separator 100 installed in a flowback system 5 .
- a fracturing tree 10 (“frac tree”) is disposed on a producing well from which a production fluid containing a mixture of fracking fluids, drilled isolation plug cuttings, oil and natural gas, water, and sand or other sediment flows.
- the production fluid flows from the frac tree 10 through a fluid line 12 and enters the primary separator 100 .
- the primary separator 100 separates drilled plug cuttings, natural gas, and fluid and sand in a single integral primary separator 100 .
- the production stream enters the primary separator 100 through the inlet port 110 and flows into screen 144 .
- fluids including fracking fluids, oil and natural gas, and water, and smaller solid matter such as sand particles and similar sediment pass radially outward through the plurality of perforations in the screen 144 into the annulus 143 formed between the screen 144 and flow sleeve 142 .
- Larger solids, particularly, drilled isolation plug cuttings are caught within the screen 144 and prevented from passing through the plurality of perforations. Fluid and smaller solids continue to flow either through screen 144 or within annulus 143 (e.g., in a swirling motion as shown in FIG.
- Fluid and sand separation from the gas within the primary separation device is dependent on gravity and retention time.
- fluid may circulate through the primary separation device at a rate of between about two and three barrels per minute. In other embodiments, fluid may circulate through the primary separation device at a rate of between about two and twenty barrels per minute.
- filtered gas exiting outlet 168 flows through a gas line 14 , through a flow regulator 15 (e.g., a choke valve), and may be further processed in a three-phase separator 16 .
- Liquid and solid matter exiting liquid drain 138 may flow through a fluid-sand clean-up line 18 to one or more deposit tanks (not shown).
- the primary separator provides separation of drilled isolation plug cuttings, gas, and well fluids and sand in a single assembly before said constituents reach other fluid handling equipment not suitable for handling such a mixture.
- the combined separation capabilities of drilled isolation plug cuttings, gas, and well fluids and sand in a single assembly greatly reduces the footprint for such equipment, where floor space is often at a premium.
- the removable screens allow screens to be easily removed and cleaned or replaced, which increases the efficiency of the separation process.
- the primary separator described herein may perform as a sand trap, which may include one or more sand filters to trap trace sand.
- screen 144 may be replaced in about ten minutes or less with a sand filter having from 20 to 80 micron perforations.
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Abstract
Description
- This application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Application Ser. No. 61/813,744 filed Apr. 19, 2013, which is incorporated herein by reference in its entirety.
- This invention relates to oil and gas well completion and production.
- Geologists have known for years that substantial deposits of oil and natural gas are trapped in deep shale formations. Around the world today, with modern horizontal drilling techniques and hydraulic fracturing, the trapped oil and natural gas in these shale reservoirs is being produced, gathered and distributed to customers.
- Initially, a vertical hole is drilled in a formation down to a depth below the water table, and steel casing is inserted into the borehole and cemented in place, thus providing an impermeable barrier between the water table and borehole. Vertical drilling continues to a depth called the “kick-off” point, where the wellbore begins curving to become horizontal. One advantage of horizontal drilling is that it is possible to drill several wells from only one drilling pad, minimizing the impact to the surface environment. When the targeted distance is reached, the drill pipe is removed from the borehole, and additional steel casing is inserted through the full length of the wellbore and cemented in place.
- The drilling rig is then removed and preparations for well completion are then undertaken. The first step is to create a connection between the final casing and the reservoir rock. To do so, a device known as a perforating gun, equipped with shaped explosive charges, is lowered into the wellbore down to the layer containing oil and/or natural gas. The perforating gun is then fired, which creates holes through the casing, cement, and into the target reservoir rock. Next, a mixture of water, sand and other chemicals is pumped into the deep underground reservoir formations, which creates fractures in the reservoir rock. A propping agent, usually sand carried by the high viscosity fluid, is pumped into the fractures to keep them from closing when the pumping pressure is released. This initial stimulation segment is then isolated with a specially designed plug inserted into the steel casing to seal off the perforated (and thus the fractured reservoir) and prevent production from the isolated section. The perforating gun is then moved to the next stage of the wellbore to perform the same process, which is then hydraulically fractured in the same manner. This process is repeated along the entire horizontal section of the well, which may extend several miles.
- Once the stimulation is complete, the isolation plugs are drilled out and production begins. Initially water, and then natural gas or oil flows into the horizontal casing and up the wellbore. In the course of initial production of the well, approximately 15 to 50% of the fracturing fluid may be recovered, a process known as “flowback.” The purpose of the flowback is to safely recover these substances from the well and transition the marketable hydrocarbons of the well stream to a sales pipeline or storage tank. The fracturing fluid is then either recycled to be used on other fracturing operations or safely disposed of according to government regulations.
- The fracturing process described above requires equipment to handle and separate drilled isolation plug cuttings along with large volumes of sand, fracturing fluids, and oil and natural gas. The drilled isolation plug cuttings and sand need to be separated to keep from plugging other fluid clean up and separation equipment, which may cause a loss of circulation detrimental to downhole tools. Accordingly, a device is needed to efficiently separate drilled isolation plug cuttings, sand, fracturing fluids and oil and natural gas during a flowback process of production of fluids from the wellbore.
- An object of the invention is to accomplish one or more of the following:
- Provide an apparatus for primary separation in fracking operations that combines isolation plug cutting separation, sand separation, and gas separation in a single separation assembly.
- In one aspect, embodiments disclosed herein relate to an apparatus for separating natural gas from high pressure, high velocity production streams comprising a liquid dispersion of water, sand, natural gas, and isolation plug cuttings. The apparatus includes a housing having a first end and a second end, and an interior cavity extending therebetween, and an inlet port disposed at said first end of said housing. A flow sleeve is disposed within said interior cavity of said housing and extending from said first end to said second end of said housing, and a first screen is disposed within said flow sleeve and in fluid communication with said inlet port. An annulus is formed between an outer diameter of said first screen and an inner diameter of said flow sleeve. A baffle is disposed within said interior cavity at said second end of said housing, and said baffle is arranged and designed to enhance separation of said production stream into its constituents, a liquid drain in a lower portion of said housing, a second screen coupled to an upper portion of said housing, and a gas outlet.
- The invention is illustrated in the accompanying drawings wherein,
-
FIG. 1A illustrates a cross-section view of a primary separator in accordance with one or more embodiments of the present disclosure; -
FIG. 1B illustrates an enlarged cross-section view of a second end of the primary separator ofFIG. 1A ; and -
FIG. 2 the primary separator ofFIG. 1A on location. - The aspects, features, and advantages of the invention mentioned above are described in more detail by reference to the drawings, wherein like reference numerals represent like elements.
FIG. 1 illustrates a cross-section view of aprimary separator 100 in accordance with one or more embodiments of the present disclosure. - Main Housing
- The
primary separator 100 includes a generally cylindricalmain housing 102 having afirst flange 104 on a first end and asecond flange 106 on a second end. Themain housing 102 complies with all PSL-3 NACE H2S specifications. Themain housing 102 is rated for pressures of at least 5,000 psi, 10,000 psi, 15,000 psi, and up to 20,000 psi. A generally cylindricalinterior cavity 108 or bore is formed within themain housing 102. Aninlet port 110 may be coupled to themain housing 102 by way of afirst adaptor 112 that is fastened to thefirst flange 104 with one or more threadedfasteners 114. One ormore valves inlet port 110 andadaptor 112.Valves inlet port 110 to allow production fluid to enter theprimary separator 100. Alternatively,inlet port 110 may be fastened directly to thefirst flange 104 of themain housing 102. Apressure gauge 137 may be coupled to theinlet port 110 and arranged and designed to monitor pressure entering theinlet port 110. - A
second adaptor 120 may be fastened to thesecond flange 106 of themain housing 102 by way of one or more fasteners (not shown). Further, anend cap 122 may have an internal thread that engages an external thread of thesecond adaptor 120 and is threaded thereon. Theend cap 122 is preferably removable from thesecond adaptor 120. Alternatively, theend cap 122 may be attached directly to thesecond flange 106 of themain housing 102 by way of one or more threaded fasteners. - The
main housing 102 further includes atop flange 124. Atop flow adaptor 126 is disposed within thetop flange 124 and secured therein by way of one or more threadedfasteners 128. Thetop flow adaptor 126 may have a flow channel therein that decreases in diameter from a bottom surface of the flow adaptor to the top surface. One ormore sealing members 130 may be installed between thetop flow adaptor 126 and thetop flange 124. - The
main housing 102 also includes abottom flange 130. A bottom flow adaptor 132 or flow block is disposed within thebottom flange 130 and secured therein by way of one or more threadedfasteners 134. The bottom flow adaptor 132 may have a flow channel therein that decreases in diameter from a top surface of the flow adaptor to a bottom surface. One ormore sealing members 136 may be installed between the bottom flow adaptor 132 and thebottom flange 130. The bottom flow adaptor 132 includes anoutlet port 138 or drain through which fluid or sediment may flow out of themain housing 102. - Finally, a
pressure gauge 139 may be coupled to themain housing 102 and arranged and designed to monitor pressure within theinterior cavity 108 of themain housing 102. - Plug Cuttings Screen Assembly
- A
screen assembly 140 is disposed within theinterior cavity 108 of themain housing 102. Thescreen assembly 140 includes aflow sleeve 142 that extends within theinterior cavity 108 of the main housing from a first end to a second end of themain housing 102. A first end of theflow sleeve 142 is threaded within thefirst flange 104 of themain housing 102 and abuts thefirst adaptor 112 coupled to thefirst flange 104. A second end of theflow sleeve 142 is threaded within thesecond flange 106 and abuts thesecond adaptor 120. Theflow sleeve 142 is preferably a hollow cylindrical tube having an inner diameter of at least about 3 inches, 4 inches, or 5 inches, up to about 6 inches, 7 inches or 8 inches. Theflow sleeve 142 has one ormore ports flow sleeve 142, which allow gas and fluid to exit theflow sleeve 142 and enter theinterior cavity 108 of themain housing 102. As best illustrated inFIG. 1B ,upper port 145 a may have a diameter of at least about ½ inch, ¾ inch, or 1 inch, up to about 1½ inches, 1¾ inches, or 2 inches.Lower port 145 b may have a diameter of at least about 1½ inches, 2 inches, or 2½ inches, up to about 3 inches or 4 inches. - A
screen 144 is disposed within theflow sleeve 142. Thescreen 144 is concentrically oriented within theflow sleeve 142 and extends axially within theflow sleeve 142. A first end of thescreen 144 has acollar 146 attached thereto (e.g., welded). Thecollar 146 is adapted to fit within a seat orpocket 113 of thefirst adaptor 112 coupled to thefirst flange 104. A second end of thescreen 144 has acollar 148 attached thereto (e.g., threaded as shown, or welded). Thecollar 148 is adapted to fit within thesecond adaptor 120 and extend through an aperture in theend cap 122. Thecollar 148 has aflange 149, which abuts between surfaces of thesecond adaptor 120 and theend cap 122. When theend cap 122 is installed over thecollar 148 and threaded onto thesecond adaptor 120, the interface between theflange 149 of thecollar 148 between thesecond adaptor 120 and theend cap 122 prevents movement of thescreen 142 in an axial direction. Removal of theend cap 122 allows thescreen 142 to be removed, either for replacement or cleaning. - The
screen 144 is preferably a stainless steel hollow cylindrical tube that has a plurality of perforations to allow a fluid to enter the hollow tube and radially exit the screen through the plurality of perforations. The screen may have an inner diameter of at least about 1 inch, 2 inches, or 3 inches, up to about 4 inches, 5 inches, or 6 inches. Anannulus 143 is formed between an outer diameter of thescreen 144 and an inner diameter of theflow sleeve 142. Perforations in thescreen 144 may have a diameter of at least about ⅛ inch, ¼ inch, or ⅜ inch up to about ½ inch, 9/16 inch, ⅝ inch, ¾ inch, or 1 inch. In other embodiments, perforations in thescreen 144 may have a diameter of up to about 1½ inches, 2 inch, or 3 inches. - Further, a
baffle 150 is located within theinterior cavity 108 at a second end of themain housing 102 proximate thesecond flange 106. Thebaffle 150 is preferably a plate welded or otherwise attached to an outer diameter of theflow sleeve 142. The plate may be at least about 1 inch in thickness, and up to about 3 inches in thickness. Thebaffle 150 is extends radially outward from the outer diameter of theflow sleeve 142 towards an inner wall of thehousing 102. Thebaffle 150 is sized to have an outer diameter that is less than an inner diameter of thehousing 102 so that anupper passageway 152 and a lower passageway 154 (e.g., gaps) are formed there between. Thebaffle 150 is arranged and designed to distribute fluid flow exiting fromports interior cavity 108 of thehousing 102 and to further separate gas from fluids. - Gas Separator Assembly
- A
gas separator assembly 160 is coupled to thetop flow adaptor 126 by way of one or more threadedfasteners 162. Thegas separator assembly 160 includes a riser spool orlower body 164 having a central bore there through. Anoutlet body 166 having one ormore outlets 168, both radial and longitudinal, may be coupled to thelower body 164 by way one or more threadedfasteners 169. In certain embodiments, ablind flange 170 may be disposed over at least one of the radial outlets thereby directing fluid out remainingradial outlets 168. Atree cap 170 may be fastened to theoutlet body 166 by way of one or more threadedfasteners 171. Finally, a threadedcap 174 having internal threads may be threaded onto external threads of thetree cap 172. Alternatively, thegas separator assembly 160 may comprise or be formed as a single integral housing attached to thetop flow adaptor 126 of themain housing 102 and comprising the individual components previously described in a single integral component. - The
gas separator assembly 160 further includes ascreen 178 disposed therein. Thescreen 178 is preferably a stainless steel hollow cylindrical tube that has a plurality of perforations to allow a fluid to enter the hollow tube and radially exit the screen through the plurality of perforations. Thescreen 178 may have an outer diameter of at least about 1 inch, 2 inches, or 3 inches, up to about 4 inches, 5 inches or 6 inches. Perforations in thescreen 178 may have a diameter of at least about 20 microns, 30 microns, or 40 microns, up to about 50 microns, 60 microns, 70 microns or 80 microns. In other embodiments, the perforations may have a diameter up to about ⅛ inch, ¼ inch, ½ inch or 1 inch. - A lower end of the
screen 178 may be installed in aseat 180 attached within a lower end of thelower body 164. For example, theseat 180 may be welded within thelower body 164. An upper end of thescreen 178 may comprise acollar 182, attached to thescreen 178, either welded or threaded. Thecollar 182 is adapted to fit within thetree cap 172 and extend through an aperture in the threadedcap 174. Removal of the threadedcap 174 allows thescreen 178 to be removed, either for replacement or cleaning. In certain embodiments, thecollar 182 may have aneedle valve 176 or the like installed therein for pressure adjustment within thegas separator assembly 160. - Methods of Use
-
FIG. 2 is a simplified schematic showing theprimary separator 100 installed in aflowback system 5. A fracturing tree 10 (“frac tree”) is disposed on a producing well from which a production fluid containing a mixture of fracking fluids, drilled isolation plug cuttings, oil and natural gas, water, and sand or other sediment flows. The production fluid flows from thefrac tree 10 through afluid line 12 and enters theprimary separator 100. Theprimary separator 100 separates drilled plug cuttings, natural gas, and fluid and sand in a single integralprimary separator 100. - In reference to
FIGS. 1A and 1B , the production stream enters theprimary separator 100 through theinlet port 110 and flows intoscreen 144. As the production fluid flows through thescreen 144, fluids, including fracking fluids, oil and natural gas, and water, and smaller solid matter such as sand particles and similar sediment pass radially outward through the plurality of perforations in thescreen 144 into theannulus 143 formed between thescreen 144 and flowsleeve 142. Larger solids, particularly, drilled isolation plug cuttings are caught within thescreen 144 and prevented from passing through the plurality of perforations. Fluid and smaller solids continue to flow either throughscreen 144 or within annulus 143 (e.g., in a swirling motion as shown inFIG. 1B ) until they reach a second end of thescreen assembly 140 andports annulus 143 through cyclonic separation (i.e., swirling motion), which will be understood by one of ordinary skill in the art. - Once the swirling flow reaches a second end of the
flow sleeve 142 andannulus 143, fluids and smaller solid matter within theannulus 143 flow downward throughlower port 145 b, while gas particles flow upward throughupper port 145 a. Fluids and smaller solid matter as well as gas particles then encounter theflow baffle 150, which is arranged and designed to cause flow distribution and encourage further separation of gas from well fluids such as oil, water, and/or fracking fluids, and sand or sediment. - Fluid and sand separation from the gas within the primary separation device is dependent on gravity and retention time. In certain embodiments, fluid may circulate through the primary separation device at a rate of between about two and three barrels per minute. In other embodiments, fluid may circulate through the primary separation device at a rate of between about two and twenty barrels per minute. Once separated from the gas, fluids and solid matter flow downward through the
lower port 154 of theflow baffle 150 to theliquid drain 138 at the bottom of themain housing 102. Once separated from fluids and solid matter at the baffle, the gas flows through theupper port 152 of theflow baffle 150 to an upper portion of themain housing 102. The gas enters thegas separator assembly 160, where the gas flows into thescreen 178. As gas flows radially outward through the plurality of perforations in thescreen 178, sand and other small sediment is filtered and remains in thescreen 178. Filtered gas then exits thegas separator assembly 160 by way ofoutlet 168. - As shown in
FIG. 2 , filteredgas exiting outlet 168 flows through agas line 14, through a flow regulator 15 (e.g., a choke valve), and may be further processed in a three-phase separator 16. Liquid and solid matter exitingliquid drain 138 may flow through a fluid-sand clean-upline 18 to one or more deposit tanks (not shown). - Advantageously, the primary separator provides separation of drilled isolation plug cuttings, gas, and well fluids and sand in a single assembly before said constituents reach other fluid handling equipment not suitable for handling such a mixture. What's more, the combined separation capabilities of drilled isolation plug cuttings, gas, and well fluids and sand in a single assembly greatly reduces the footprint for such equipment, where floor space is often at a premium. Additionally, the removable screens allow screens to be easily removed and cleaned or replaced, which increases the efficiency of the separation process. Furthermore, once the isolation plugs are drilled and the well is being cleaned up, the primary separator described herein may perform as a sand trap, which may include one or more sand filters to trap trace sand.
- In other words,
screen 144 may be replaced in about ten minutes or less with a sand filter having from 20 to 80 micron perforations.
Claims (17)
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US16/787,006 US20200171410A1 (en) | 2013-04-19 | 2020-02-10 | Oil and Gas Well Primary Separation Device |
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201361813744P | 2013-04-19 | 2013-04-19 | |
US14/245,819 US9937442B2 (en) | 2013-04-19 | 2014-04-04 | Oil and gas well primary separation device |
US15/948,824 US10556194B2 (en) | 2013-04-19 | 2018-04-09 | Oil and gas well primary separation device |
US16/787,006 US20200171410A1 (en) | 2013-04-19 | 2020-02-10 | Oil and Gas Well Primary Separation Device |
Related Parent Applications (1)
Application Number | Title | Priority Date | Filing Date |
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US15/948,824 Continuation US10556194B2 (en) | 2013-04-19 | 2018-04-09 | Oil and gas well primary separation device |
Publications (1)
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US20200171410A1 true US20200171410A1 (en) | 2020-06-04 |
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ID=51728009
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Application Number | Title | Priority Date | Filing Date |
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US14/245,819 Expired - Fee Related US9937442B2 (en) | 2013-04-19 | 2014-04-04 | Oil and gas well primary separation device |
US15/948,824 Expired - Fee Related US10556194B2 (en) | 2013-04-19 | 2018-04-09 | Oil and gas well primary separation device |
US16/787,006 Abandoned US20200171410A1 (en) | 2013-04-19 | 2020-02-10 | Oil and Gas Well Primary Separation Device |
Family Applications Before (2)
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US14/245,819 Expired - Fee Related US9937442B2 (en) | 2013-04-19 | 2014-04-04 | Oil and gas well primary separation device |
US15/948,824 Expired - Fee Related US10556194B2 (en) | 2013-04-19 | 2018-04-09 | Oil and gas well primary separation device |
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Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20190201817A1 (en) * | 2017-12-29 | 2019-07-04 | Enercorp Sand Solutions Inc. | Horizontal sand separator assembly |
Families Citing this family (8)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9937442B2 (en) | 2013-04-19 | 2018-04-10 | Stuart Petroleum Testers, Inc. | Oil and gas well primary separation device |
CA2916272A1 (en) * | 2015-12-23 | 2017-06-23 | Jay R. Morris | High pressure sand trap with screen |
CA3018134C (en) * | 2017-09-19 | 2023-10-31 | Resource Rental Tools, LLC | In-line mud screen manifold useful in downhole applications |
US11173427B2 (en) | 2017-09-25 | 2021-11-16 | Sand Separation Technologies Inc. | Device for separating solids from a fluid stream |
US10895141B2 (en) | 2018-01-11 | 2021-01-19 | Encline Artificial Lift Technologies LLC | Controlled high pressure separator for production fluids |
WO2020047649A1 (en) | 2018-09-06 | 2020-03-12 | 1460798 Alberta Ltd. | Counterflow vortex breaker |
CN110984953B (en) * | 2019-11-19 | 2022-03-29 | 东北石油大学 | Harmful gas treatment method in fracturing flow-back process |
CN112048330B (en) * | 2020-09-01 | 2021-09-10 | 北京奥博斯工程技术有限公司 | Process and device for reducing coke powder of delayed coking fractionating tower |
Family Cites Families (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CA2188839C (en) * | 1996-10-25 | 2001-01-02 | David Speed | Recovery of gas from drilling fluid returns in underbalanced drilling |
US6315813B1 (en) * | 1999-11-18 | 2001-11-13 | Northland Energy Corporation | Method of treating pressurized drilling fluid returns from a well |
EP2445603B1 (en) | 2009-06-26 | 2016-03-02 | Universiteit Antwerpen | Phase separator |
US7785400B1 (en) | 2009-06-30 | 2010-08-31 | Sand Separators LLC | Spherical sand separators |
US9937442B2 (en) | 2013-04-19 | 2018-04-10 | Stuart Petroleum Testers, Inc. | Oil and gas well primary separation device |
-
2014
- 2014-04-04 US US14/245,819 patent/US9937442B2/en not_active Expired - Fee Related
-
2018
- 2018-04-09 US US15/948,824 patent/US10556194B2/en not_active Expired - Fee Related
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2020
- 2020-02-10 US US16/787,006 patent/US20200171410A1/en not_active Abandoned
Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20190201817A1 (en) * | 2017-12-29 | 2019-07-04 | Enercorp Sand Solutions Inc. | Horizontal sand separator assembly |
US11679348B2 (en) * | 2017-12-29 | 2023-06-20 | Enercorp Engineered Solutions Inc. | Horizontal sand separator assembly |
Also Published As
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US20140311343A1 (en) | 2014-10-23 |
US20180221789A1 (en) | 2018-08-09 |
US10556194B2 (en) | 2020-02-11 |
US9937442B2 (en) | 2018-04-10 |
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Owner name: JPMORGAN CHASE BANK, N.A., TEXAS Free format text: SECURITY INTEREST;ASSIGNOR:STUART PETROLEUM TESTERS, LLC;REEL/FRAME:054195/0822 Effective date: 20201027 |
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