METHODS OF FRACTURING WITH AND PROCESSING LPG BASED TREATMENT FLUIDS

TECHNICAL FIELD

This document relates to the processing of liquefied petroleum gas (LPG)-containing-treatment fluids, and further to the recycle and re-use of recovered LPG frac fluid.

BACKGROUND

In the conventional fracturing of wells, producing formations, new wells or low producing wells that have been taken out of production, a formation can be fractured to attempt to achieve higher production rates. Proppant and fracturing fluid are mixed in a blender and then pumped into a well that penetrates an oil or gas bearing formation. High pressure is applied to the well, the formation fractures and proppant carried by the fracturing fluid flows into the fractures. The proppant in the fractures holds the fractures open after the pressure is relaxed and production is resumed. Various fluids have been disclosed for use as the fracturing fluid, including liquefied petroleum gas (LPG).

LPG has been advantageously used as a fracturing fluid to simplify the recovery and clean-up of frac fluids after a frac. Exemplary LPG frac systems are disclosed in WO2007098606. Some of these systems send recovered fracturing fluid straight to a flare stack for disposal. This method of disposal, while sometimes economical, results in the loss of potentially valuable fluids. Other of these systems produce the recovered LPG frac fluid to a sales line, since the recovered fluid almost always contains natural gases that have salable value. However, delivery to a sales line requires the recovered fluids to be pressurized. During pressurization the LPG may condense out, triggering closure of the gas compressor. One way to resolve this issue is to add more natural gas to the recovered frac fluid to lower the dew point. Since the recovered LPG frac fluid may contain gelling chemicals, the requirements and costs of processing the recovery stream are increased.

Based on the prior references, it is not obvious that LPG from recovered LPG frac fluid can be economically processed on-site. This is especially true when the LPG frac fluids contain gelling chemicals.

SUMMARY

A method of processing liquefied petroleum gas used in a treatment fluid previously injected into a hydrocarbon reservoir is disclosed, the method comprising: recovering at least a portion of the treatment fluid from the hydrocarbon reservoir to produce recovered treatment fluid; and separating liquefied petroleum gas in the form of a gas or liquid from the recovered treatment fluid using a separator.

An apparatus for processing liquefied petroleum gas used in a treatment fluid previously injected into a hydrocarbon reservoir is also disclosed, the apparatus comprising: a separator; a recovery line for recovering treatment fluid from the hydrocarbon reservoir, the recovery line connected to supply recovered treatment fluid to the separator, the separator being to separate a liquefied petroleum gas portion in gas or liquid form from the recovered treatment fluid.

An apparatus is also disclosed for processing liquefied petroleum gas previously injected as at least a portion of a treatment fluid into a hydrocarbon reservoir through a well penetrating the hydrocarbon reservoir, the apparatus comprising: a separator connected to a recovery line to receive fluids flowed back from the well for separating the fluids into at least a liquefied petroleum gas portion, and a natural gas portion; and the separator further being connected to supply the liquefied petroleum gas portion to at least one of a storage tank for storing liquefied petroleum gas, a flare, and a pipeline.

A method is also disclosed of processing liquefied petroleum gas used in the treatment of a hydrocarbon reservoir penetrated by a well, the method comprising: flowing fluid from the well, the fluid comprising liquefied petroleum gas that has been previously injected into the well; providing the fluid to a separator, the liquefied petroleum gas being provided at least partially as a gas; and with the separator, separating the fluid into at least a liquefied petroleum gas portion, and a natural gas portion, for at least one of further processing, sale, disposal, delivery, storage, or re-use of each respective portion.

A method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir penetrated by a well is also disclosed. Fluid is flowed from the well, the fluid comprising liquefied petroleum gas that has been previously injected into the well. The fluid is provided to a separator, the liquefied petroleum gas being provided at least partially as a gas. With the separator, the fluid is separated into at least a liquefied petroleum gas portion, a natural gas portion, an aqueous portion, a liquid hydrocarbon portion and a solids portion for at least one of sale, disposal, delivery, storage, or re-use of each respective portion.

An apparatus is also provided for recycling liquefied petroleum gas previously injected as at least a portion of a treatment fluid into a hydrocarbon reservoir through a well penetrating the hydrocarbon reservoir, the apparatus comprising one or more storage tanks and a separator. The one or more storage tanks are for storing liquefied petroleum gas. The separator is connected to a recovery line to receive fluids flowed back from the well for separating the fluids into at least a liquefied petroleum gas portion, a natural gas portion, an aqueous portion, a liquid hydrocarbon portion and a solids portion. The separator is further connected to supply the liquefied petroleum gas portion to at least one of the one or more storage tanks.

A method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir is disclosed. Liquefied petroleum gas is injected as at least a portion of a treatment fluid into the hydrocarbon reservoir. At least a portion of the treatment fluid injected into the hydrocarbon reservoir is recovered. At least a portion of the liquefied petroleum gas is separated from the recovered treatment fluid. Liquefied petroleum gas separated from the recovered treatment fluid is re-used by injecting it into at least one subsequent hydrocarbon reservoir.

A method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir is also disclosed. Treatment fluid previously injected into the hydrocarbon reservoir is recovered, the treatment fluid comprising liquefied petroleum gas. At least a portion of the liquefied petroleum gas is separated from the recovered treatment fluid. The separated liquefied petroleum gas is then stored.

An apparatus for recycling liquefied petroleum gas previously injected as at least a portion of a treatment fluid into a hydrocarbon reservoir through a well penetrating the hydrocarbon reservoir is also disclosed. The apparatus comprises one or more storage tanks, and a separator. The one or more storage tanks are configured to store liquefied petroleum gas, at least one of the one or more storage tanks containing liquefied petroleum gas and being connected to supply the liquefied petroleum gas to the well. The separator is connected to receive recovered treatment fluids from the well and further adapted to separate and supply at least a portion of the liquefied petroleum gas from the recovered treatment fluid to at least one of the one or more storage tanks.

An apparatus for recycling liquefied petroleum gas previously injected as at least a portion of a treatment fluid into a hydrocarbon reservoir through a well penetrating the hydrocarbon reservoir is also disclosed. The apparatus comprises a separator. The separator is connected to receive recovered treatment fluids comprising liquefied petroleum gas previously injected into the well. The separator is also adapted to separate at least a portion of the liquefied petroleum gas from the recovered treatment fluid. The separator is further connected to supply the separated at least a portion of the liquefied petroleum gas to at least one storage tank adapted to store liquefied petroleum gas.

A method of processing fluid used in the treatment of a hydrocarbon reservoir penetrated by a well is also disclosed, the method comprising: flowing fluid from the well, the fluid comprising gaseous liquefied petroleum gas that has been previously injected into the well; liquefying the gaseous liquefied petroleum gas with the fluid and providing the fluid to a separator; and with the separator, separating the fluid into at least a natural gas portion and a liquefied petroleum gas portion for at least one of further processing, sale, disposal, delivery, storage, or re-use of each respective portion.

A method of treating a subterranean formation is also disclosed, the method comprising: introducing a hydrocarbon fracturing fluid into the subterranean formation, the hydrocarbon fracturing fluid comprising a gel of at least liquefied petroleum gas and a gelling agent; subjecting the hydrocarbon fracturing fluid to pressures above the formation pressure; and at least partially vaporizing the liquefied petroleum gas in order to break the gel.

In various embodiments, there may be included any one or more of the following features: Separating may comprise separating an aqueous portion and a liquid hydrocarbon portion from the recovered treatment fluid. Separating may comprise separating a solids portion from the recovered treatment fluid. Separating may comprise vaporizing the liquefied petroleum gas in the recovered treatment fluid. Separating may comprise separating a natural gas portion from the recovered treatment fluid. Separating may comprise a first stage comprising separating gases from the recovered treatment fluid, the gases comprising gaseous liquefied petroleum gas and natural gas, and a second stage comprising separating the gases into a liquefied petroleum gas portion and the natural gas portion. The second stage may comprise liquefying the gaseous liquefied petroleum gas to separate the gases into the liquefied petroleum gas portion and the natural gas portion. The liquefied petroleum gas portion and the natural gas portion may be separated as a cooled stream of LPG and a cooled stream of natural gas, respectively, and in which liquefying comprises cooling a stream of the gases by transferring heat from the stream of the gases to one or more of the cooled stream of LPG and the cooled stream of natural gas. The separator may be a multi phase separator, such as a five-phase separator having as output liquefied petroleum gas in gas or liquid form, natural gas, an aqueous portion, a liquid hydrocarbon portion, and a solids portion. At least part of the natural gas portion may be supplied to a sales line. Liquefied petroleum gas may be separated from the recovered treatment fluid in the form of a liquid. The liquefied petroleum gas separated from the recovered treatment fluid may be re-used as a well treatment fluid. The separator may be connected to supply the liquefied petroleum gas separated from the recovered treatment fluid to at least one of a storage tank for storing liquefied petroleum gas, a flare, and a pipeline. A heater may be on the recovery line. The separator may be adapted to separate a natural gas portion from the recovered treatment fluid. The separator may comprise a first separator stage adapted to at least separate gases from the fluids, the gases comprising gaseous liquefied petroleum gas and natural gas; and a second separator stage connected to receive the gases from the first separator stage and adapted to separate the gases into the liquefied petroleum gas portion and the natural gas portion. The second separator stage may comprise a liquefier connected to liquefy the gaseous liquefied petroleum gas from the gases. At least partially vaporizing may comprise reducing the pressure the hydrocarbon fracturing fluid is subjected to. The hydrocarbon fracturing fluid may exclude a breaker. Separating may comprise separating the fluid into and a liquids portion comprising at least one of water and liquid hydrocarbons. Separating the fluid into a liquids portion may comprise separating the fluid into an aqueous portion and a liquid hydrocarbon portion. The liquefied petroleum gas portion may be stored. Providing may comprise vaporizing the liquefied petroleum gas in the fluid flowed from the well. Vaporizing may comprise heating the fluid. Separating may comprise a first stage comprising separating gases from the fluid flowed back from the well, the gases comprising gaseous liquefied petroleum gas and natural gas, and a second stage of separating the gaseous liquefied petroleum gas from the natural gas. The gaseous liquefied petroleum gas may be liquefied to create the liquefied petroleum gas portion. The liquefied petroleum gas portion may be re-injected into at least one of the well and another well as part of a process of treating the well and the other well, respectively. Separating may comprise separating the gases, the aqueous portion, the liquid hydrocarbon portion, and the solids portion using a four phase separator. At least part of the natural gas portion may be supplied to a sales line. The separator may comprise a first separator stage adapted to at least separate gases from the recovered treatment fluid, the gases comprising gaseous liquefied petroleum gas and natural gas; and a second separator stage connected to receive the gases from the first separator stage and adapted to separate and supply liquefied petroleum gas from the natural gas. The second separator stage may comprise a liquefier connected to liquefy the gaseous liquefied petroleum gas separated from the first separator stage. Liquefying may comprise at least one of pressurization and cooling. Liquefying may comprise cooling with a refrigeration unit.

These and other aspects of the device and method are set out in the claims, which are incorporated here by reference.

BRIEF DESCRIPTION OF THE FIGURES

Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which:

FIG. 1 is a side elevation view, of a treatment system designed to process LPG treatment fluids.

FIG. 2 is a side elevation view, of a further treatment system designed to process LPG treatment fluids.

FIG. 3 is a flow diagram of a method of processing liquefied petroleum gas used in the treatment of a hydrocarbon reservoir penetrated by a well.

FIG. 4 is a side elevation view, partially in section, of a further treatment system designed to recycle LPG treatment fluids.

FIG. 5 is a flow diagram of a further method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir.

FIG. 6 is a flow diagram of a method of processing liquefied petroleum gas used in a treatment fluid previously injected into a hydrocarbon reservoir.

FIGS. 7-9 are schematics of various embodiments of treatment systems for processing LPG treatment fluids.

FIG. 10 is a flow diagram of a further method of processing liquefied petroleum gas used in the treatment of a hydrocarbon reservoir penetrated by a well.

FIG. 11 is a flow diagram of a method of treating a subterranean formation.

FIGS. 12A-C together form a schematic that illustrates a further embodiment of an apparatus for processing liquefied petroleum gas used in a treatment fluid.

DETAILED DESCRIPTION

Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims.

LPG may include a variety of petroleum and natural gases existing in a liquid state at ambient temperatures and moderate pressures. In some cases, LPG refers to a mixture of such fluids. These mixes are generally more affordable and easier to obtain than any one individual LPG, since they are hard to separate and purify individually. Unlike conventional hydrocarbon based fracturing fluids, common LPGs are tightly fractionated products resulting in a high degree of purity and very predictable performance. Exemplary LPGs include ethane, propane, butane, or various mixtures thereof. As well, exemplary LPGS also include isomers of propane and butane, such as iso-butane. Further LPG examples include HD-5 propane, commercial butane, and n-butane. The LPG mixture may be controlled to gain the desired hydraulic fracturing and clean-up performance. LPG fluids used may also include minor amounts of pentane (such as i-pentane or n-pentane), and higher weight hydrocarbons.

LPGs tend to produce excellent fracturing fluids. LPG is readily available, cost effective and is easily and safely handled on surface as a liquid under moderate pressure. LPG is completely compatible with formations and formation fluids, is highly soluble in formation hydrocarbons and eliminates phase trapping—resulting in increased well production. LPG may be readily and predictably viscosified to generate a fluid capable of efficient fracture creation and excellent proppant transport. After fracturing, LPG may be recovered very rapidly, allowing savings on clean up costs. In some embodiments, LPG may be predominantly propane, butane, or a mixture of propane and butane. In some embodiments, LPG may comprise more than 80%, 90%, or 95% propane, butane, or a mixture of propane and butane.

Referring to FIG. 1, an embodiment of an apparatus 11 for processing liquefied petroleum gas used in a treatment fluid previously injected into a hydrocarbon reservoir 24, for example through a well 22 penetrating the hydrocarbon reservoir 24, is illustrated. Referring to FIGS. 7, 8, and 9, various embodiments of apparatus 11 are illustrated. Referring to FIG. 7, apparatus 11 has a separator 81 and may have a recovery line 34, recovery line 34 being for recovering treatment fluid from the hydrocarbon reservoir 24 (shown in FIG. 1), the recovery line 34 being connected to supply recovered treatment fluid to the separator 81, the separator 81 being to separate a liquefied petroleum gas portion in gas or liquid form from the recovered treatment fluid. Thus, the separator 81 may be connected to receive fluid, for example recovered treatment fluids, flowed back from the well 22. Recovered treatment fluids may be stored before sending to separator 81 through recovery line 34. Separator 81 may be provided for separating the recovered treatment fluids into one or more of a liquefied petroleum gas portion (line 49), and a natural gas portion (line 13). Separator 81, which may include for example one or more devices, for further example primary and secondary separators 83 and 85, respectively, may be further connected to supply separated liquefied petroleum gas to at least one of a storage tank (for example tank 10 in FIG. 1) for storing liquefied petroleum gas, a flare (for example flare 120), and a pipeline (for example sales line 113 in FIG. 1).

Referring to FIG. 1, in some embodiments, apparatus 11 comprises one or more storage tanks 10 for storing liquefied petroleum gas. Storage tank 10 is configured to store liquefied petroleum gas. Referring to FIG. 2, in some embodiments at least one of the one or more storage tank 10 contains liquefied petroleum gas and is connected to supply the liquefied petroleum gas to the well 22. Referring to FIG. 7, in some embodiments, the separator 81 is provided for separating the recovered treatment fluids into a liquids portion (line 87), for example comprising at least one of water and liquid hydrocarbons. In the embodiment illustrated, liquids, for example C6+ and water, are removed from primary separator 83 via line 87, where they are sent to pressure tank 93, and optionally vented to flare 120. The liquids portion may include various dissolved chemicals, such as gelling chemicals. The LPG portion separated into line 49 may be combined with line 87. The contents of the pressure tank 93 may be processed, for example after transport to the nearest LPG facility. Referring to FIG. 1, in some embodiments, separator 81 may separate the recovered treatment fluid into an aqueous portion (line 47B) and a liquid hydrocarbon portion (line 47A). Referring to FIG. 7, in some embodiments a solids portion may be separated out, using for example a sand catcher/separator 89 or satellite tank. The solids portion may be removed by at least one of separator 81 as shown and a separate device.

Referring to FIG. 1, in the embodiment shown separator 81 is provided for separating the fluids into at least a liquefied petroleum gas portion (line 49), a natural gas portion (line 13), a liquid hydrocarbon portion (line 47A), an aqueous portion (line 47B), and a solids portion (47C). Separator 81 may be further connected to supply the liquefied petroleum gas portion to at least one of the storage tanks 10. The recycled LPG portion can then be for example further processed, re-used, stored, sent to a sales line, disposed of, or delivered to another user. Where the LPG portion is sent to a sales line, the flow of LPG may require careful control to ensure that the minimum standards for pipe line contents are met, for example the dew point is not exceeded. Most natural gas sales lines allow methane streams with a maximum of 10% propane volume in the total gas stream. If the sales line is directed to a facility, flow of the LPG portion into the pipeline should be controlled to ensure that the facility capacity is not exceeded.

Referring to FIG. 2, LPG may be initially contained within a storage tank 10, as for example LPG or LPG and other frac fluids. Tank 10 may comprise, for example, a tanker truck or a large vessel. The LPG may be pumped from reservoir 10 down line 12, where various chemicals may be added to the fluid, for example via a chemical addition system 14. Other components may be added as well, such as gelling agent and proppant, from addition systems 16 and 18, respectively. The addition systems may be, for example, hoppers. Once the LPG is prepared and ready, a frac pressure pump 20 injects the LPG down a well 22 and into hydrocarbon reservoir 24. The liquefied petroleum gas may be initially injected as at least part of a treatment fluid containing for example lower vapor pressure hydrocarbons. The concept of reservoir treatment is well known, and the details need not be described here. In fracturing treatments, pressure may be applied to the LPG injected into the hydrocarbon reservoir 24. The pressure may be sufficient to cause fracturing of the hydrocarbon reservoir.

Referring to FIG. 3, a method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir penetrated by a well is illustrated. Referring to FIG. 7, in a stage 100 (shown in FIG. 3), fluid is flowed from the well 22, the fluid comprising LPG that has been previously injected into the well 22, for example using the system illustrated in FIG. 2. When LPG frac fluid is recovered out of well 22, it is almost always a combination of solids, liquids (including LPG), and gas (including LPG and reservoir gases).

In a stage 102 (shown in FIG. 3), the fluid is provided to a separator 81, the LPG being provided at least partially as a gas. In some embodiments, separating or providing comprises vaporizing the LPG in the fluid flowed from the well 22, for example by heating the fluid. Referring to FIG. 2, heating the fluid may be accomplished using heater 45, which may be a line heater. It is advantageous that the heating step be carried out on a moving stream of fluids, since this results in a more efficient and quick vaporization than merely heating the fluids in separator 69 for example. Referring to FIG. 7, vaporization of all LPG in the fluid also allows higher boiling liquids and gelling chemicals to be removed via deposition in for example primary separator 83. Referring to FIG. 2, in some embodiments, a vacuum source may be used to vaporize the LPG in the fluids. Where a vacuum source is used, additional heat may need to be supplied to fluids in separator 81 to offset the cooling effects of vaporizing LPG. Referring to FIG. 1, in some embodiments a heater may not be required, for example if the recovered fluid with the present LPG returned largely, and preferably entirely, as a gas, or in some cases where no gelling agents are present in the treatment fluid.

Referring to FIG. 7, in a stage 104 (shown in FIG. 3), the fluid is separated with the separator 81 into at least a liquefied petroleum gas portion and a natural gas portion for at least one of further processing, sale, disposal, delivery, storage, or re-use of each respective portion. Referring to FIG. 1, as discussed herein, the fluid may be separated within the separator 81 further into at least one of a solids portion, and a liquids portion for further example a liquid hydrocarbon portion, and an aqueous portion, for at least one of further processing, sale, disposal, delivery, storage, or re-use of each respective portion. Further processing may be achieved for example at a processing facility. Sale may be achieved by for example the transfer of liquid hydrocarbons into a sales line 113. Disposal may be achieved for example by flaring natural gases from a flare stack 120, or by dumping the solids portion at a dump site according to applicable environmental standards. Delivery may be achieved by for example loading the aqueous portion into a tanker truck for transport to a processing facility. Storage may be achieved by for example storing the liquid hydrocarbon portion in a storage tank. Re-use may be achieved by for example re-using the LPG portion in a subsequent fracturing operation. The liquefied petroleum gas portion, natural gas portion, liquid hydrocarbon portion, aqueous portion, and solids portion are illustrated as being separated into exemplary lines 49, 13, 47A, 47B, and 47C, respectively.

Separating may comprise a first stage comprising separating gases from the recovered treatment fluid flowed back from the well, the separated gases comprising gaseous liquefied petroleum gas and natural gas, and a second stage of separating the gases into a liquefied petroleum gas portion and the natural gas portion. This effectively separates the gaseous liquefied petroleum gas from the natural gas. Referring to FIG. 2, the first separator stage may be adapted to at least separate gases from the fluids and may be a multi phase separator, for example a four phase separator 69. The four phase separator 69 may be used to separate the aqueous portion, the liquid hydrocarbon portion, the gas portion, and the solids. Four phase separators are known, and may be purchased commercially, for example those units sold by Canadian Sub-Surface™ or Grant Production Testing Services Ltd. A 4-phase separator 69 may separate out gas, oil, water, and solids for example through lines 36, 47A, 47B, and 47C, respectively. Such multi-phase separators may use augers, weirs, and centrifuges for example.

The second separator stage, which may be accomplished using for example at least a liquefier 116, may be connected to receive the gases from the first separator stage and adapted to separate and supply liquefied petroleum gas from the natural gas. Referring to FIG. 8, the second separator stage may include liquefier 116 and secondary separator 85, with liquefier 116 supplying a stream of fluids through line 122 comprising liquefied petroleum gas and natural gas to the separator 85, where the liquid and gas streams are then separated into lines 49 and 13, respectively. In this and other embodiments, liquefier 116 may be an on stream refrigeration unit, for example at least one of a chiller unit or Joule-Thompson unit made by DPC. A refrigeration unit may cool the gas stream to a suitable dew point level. In some embodiments, the stream of fluids is dehydrated in association with the use of liquefier 116. In other embodiments, suitable water control methods may be used, such as methanol injection to prevent freezing in the refrigeration unit. In some embodiments, the liquefier 116 is connected to liquefy the gaseous liquefied petroleum gas separated from the natural gas. Gas liquefaction may be carried out using known techniques. The liquefier may be carried out using at least one of high pressure and low temperature, for example using at least one of a refrigeration circuit/device, a compressor, a distiller, a cooler, and a condenser. The natural gases are generally reservoir gases, and may include methane, carbon dioxide, nitrogen, helium and hydrogen sulfide. In one embodiment, natural gas means predominantly methane. It should be understood that low boiling gases, for example ethane and carbon dioxide, which were used as part of the treatment fluid may also be present, and hence removed in this stage as well. The vapors may be at least one of pressurized to the maximum and cooled to conditions required to liquefy only the liquefied petroleum gas, for example propane or butane, separated as a gas, in order to separate LPG from undesired higher boiling gases. This way, lower boiling gas molecules such as nitrogen, carbon dioxide, methane, and sometimes ethane for example may be separated as gases and not liquefied with the LPG. In some embodiments the liquefying conditions, and indeed the process as a whole, is tailored to reduce or exclude the amount of ethane that liquefies along with the desired LPG portion to be separated. This may be the case for example if the LPG portion desired to be separated is predominantly propane, butane, or propane and butane. Referring to FIG. 1, these gases, particularly methane, may be removed for example to a flare stack 120 or to a sales line 113 for disposal or sale, respectively. In general it is advantageous to supply at least part of the natural gas portion to a sales line. Meanwhile, the LPG produced can be transferred to storage tanks 10, 46 via lines 49. A compressor (not shown) may be required prior to the sales line. Wherever pressurization is required, the fluid may require conditioning such as for example dehydration or dew point control to prevent freezing and damage of various pressurization equipment. Most natural gas sales lines require a maximum water dew point of −10° C. at operating pressure.

Referring to FIG. 2, in some embodiments the method further comprises liquefying the gaseous liquefied petroleum gas to create the liquefied petroleum gas portion and re-injecting the liquefied petroleum gas portion into at least one of the well 22 and another well (not shown) as part of a process of treating the well and the other well, respectively. In this way, the LPG is recycled and re-used as an LPG frac fluid. This represents an advantage over traditional LPG frac-ing where the recovered fluid is disposed of or sold, because up to 90, 95, and 99% of the LPG fluid used in the treatment can be recycled into a re-usable form.

Embodiments of the processes disclosed herein may be used to remove contaminants from the LPG fluid to produce a re-usable fluid. Exemplary contaminants may include those from the injected treatment fluid, for example particulates such as proppant, gelling chemicals, and non LPG gases such as CO₂. Exemplary contaminants also include those introduced from the hydrocarbon reservoir 24 such as particulates, water, and non-LPG gases such as formation gases. Removing may further comprise at least one of settling, phase-separating, centrifuging, and filtering.

Other embodiments of the processes disclosed herein may be used to produce salable natural gas from the recovered treatment fluids. During the fracturing process, natural gases mix with the injected LPG treatment fluids, and the mixed natural gases may represent a valuable commodity once they reach the surface. By separating and producing the natural gas from the recovered fluids, the natural gas may be used to offset the cost of the fracturing treatment.

The liquids, including the oil and water portions, may be separated from the fluid in a liquid separation unit (not shown). The liquid separation unit may have several weirs designed to allow water to collect at the bottom of each compartment defined by the weirs, in order that the water may be removed. The solids portion may also be removed, for example by at least one of settling and filtration. In some embodiments, the liquid removal stage may also comprise one or more of decanting, centrifuging, skimming, and drying, and may include other suitable steps. Such a unit may have a gas takeoff for removing the gases from the recovered treatment fluid, such as gaseous LPG and lighter weight gases.

In some embodiments, separator 81 acts as a five-component separator. It should be understood that the function of separator 81 may be achieved in a variety of ways for example using a single separator or more than one separators. A five phase separator may have as output liquefied petroleum gas in gas or liquid form, natural gas, an aqueous portion, a liquid hydrocarbon portion, and a solids portion. For example, the separator may be three separator stages, each a different piece of equipment, one for removing gases, one for removing LPG from the gases, and another for separating the solids, oil, and water. In other examples, the four-phase separator 69 may be composed of smaller separation units or systems. The various sub-systems of separator 81 may be combined together in a single unit, for example on a mobile unit such as a trailer bed or a skid, or may be made up by several smaller distinct systems. In some embodiments, natural gas removal may be the initial step. In addition, other treating stages or units may be added as desired, for example a chemical treatment stage to remove gelling chemicals. Prior to cleaning, the recovered fluids may be stored in a suitable storage unit.

Referring to FIG. 4, an apparatus 11 for recycling liquefied petroleum gas previously injected as at least a portion of a treatment fluid into a hydrocarbon reservoir 24 through a well 22 penetrating the hydrocarbon reservoir 24 is illustrated. Apparatus 11 comprises one or more storage tanks 10, 46. Storage tanks 10, 46 are configured to store liquefied petroleum gas, at least one of the one or more storage tanks, in this case tank 10, containing liquefied petroleum gas and being connected to supply the liquefied petroleum gas to the well. A recovery line 34 may be connected to recover treatment fluid from the well 22 and supply recovered treatment fluid. Apparatus 11 further comprises a separator 81 connected to receive recovered treatment fluids from the well 22 and further adapted to separate and supply at least a portion of the liquefied petroleum gas from the recovered treatment fluid to at least one of the one or more storage tanks 10, 46. In some embodiments, separator 81 is connected to receive fluids from the recovery line 34.

Referring to FIG. 4, a further apparatus 11 is illustrated for recycling liquefied petroleum gas previously injected as at least a portion of a treatment fluid into a hydrocarbon reservoir 24 through a well 22 penetrating the hydrocarbon reservoir 24. The apparatus 11 comprises a separator, for example separator 81. The separator is connected to receive recovered treatment fluids comprising liquefied petroleum gas previously injected into the well 22, for example via line 34. The separator is also adapted to separate at least a portion of the liquefied petroleum gas from the recovered treatment fluid, and further connected, via for example line 49, to supply the separated at least a portion of the liquefied petroleum gas to at least one storage tank 10, 46, adapted to store liquefied petroleum gas. Apparatus 11 may have a heater 45 for vaporizing LPG in the recovered fluid.

Referring to FIG. 5, a further method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir 24 is illustrated. Referring to FIG. 2, in a stage 200 liquefied petroleum gas is injected as at least a portion of a treatment fluid into the hydrocarbon reservoir 24. In a stage 202 at least a portion of the treatment fluid injected into the hydrocarbon reservoir 24 is recovered. In a stage 204 at least a portion of the liquefied petroleum gas is separated from the recovered treatment fluid. In a stage 206 liquefied petroleum gas separated from the recovered treatment fluid is re-used by injecting it into at least one subsequent hydrocarbon reservoir.

Referring to FIG. 6, a method of processing, for example recycling, liquefied petroleum gas used in a treatment fluid previously injected into a hydrocarbon reservoir is illustrated. Referring to FIG. 1, in stage 208 (shown in FIG. 6) at least a portion of the treatment fluid is recovered from the hydrocarbon reservoir 24 to produce recovered treatment fluid, for example via line 34. In stage 210 (shown in FIG. 6), liquefied petroleum gas is then separated from the recovered treatment fluid in the form of a gas or liquid, or a gas and a liquid, for example using separator 81. The separated liquefied petroleum gas may be stored, for example in at least one of storage tanks 10, 46. In other embodiments, the separated LPG may be transported via a sales line (shown in FIG. 5 as line 113 for example) instead of, or in addition to being stored. The method may further comprise re-using at least a portion of the liquefied petroleum gas as a well treatment fluid, for example through storage, addition of chemicals, and then injection of the resulting fluid into at least one subsequent hydrocarbon reservoir. This further stage may be similar to stage 206.

Referring to FIG. 10, a further method of recycling liquefied petroleum gas used in the treatment of a hydrocarbon reservoir is illustrated. Referring to FIG. 9, in a stage 300 (shown in FIG. 10) fluid is flowed from the well 22, the fluid comprising gaseous liquefied petroleum gas that has been previously injected into the well 22. The fluid may flow for example through a recovery line 34, past for example sand catcher 89 and choke 91. In a stage 302, the gaseous liquefied petroleum gas is liquefied, for example with liquefier 116, with the fluid and provided to a separator, for example primary separator 83. In a stage 304, the fluid is separated with the separator 83 into at least a natural gas portion (line 13) and a liquefied petroleum gas portion (line 49) for at least one of further processing, sale, disposal, delivery, storage, or re-use of each respective portion. This method may be used for quick separation of the natural gas portion. The LPG portion may include other species, such as for example heavier hydrocarbons and water.

Referring to FIGS. 1-10, exemplary systems are illustrated for carrying out the embodiments of the methods disclosed herein. These systems are general schematics, and a skilled worker will understand that additional components that are not shown may be required to implement the system. The illustrated components are for illustration only, and therefore are not to scale.

Referring to FIG. 11, a method of treating a subterranean formation, for example hydrocarbon reservoir 24 in FIGS. 1 and 2, is illustrated. In a first stage 306, a hydrocarbon fracturing fluid is introduced into the subterranean formation, the hydrocarbon fracturing fluid comprising a gel of at least liquefied petroleum gas and a gelling agent. In a stage 308, the hydrocarbon fracturing fluid is subjected to, for example using at least one frac pressure pump (not shown), to pressures above the formation pressure, for example pressures at or above fracturing pressures. In a stage 310, the liquefied petroleum gas is at least partially vaporized, for example reduced sufficiently in density, in order to break the gel. Stage 310 may be accomplished in numerous ways, for example by at least one of allowing the frac fluid to mix with natural gases downhole to lower the critical temperature of the frac fluid, allowing the temperature of the frac fluid in the formation to rise by equalization with the formation temperature, and reducing the pressure the frac fluid is subjected to. Such methods are advantageous in that they do not require, and in some cases may exclude altogether, the use of a breaker to break the gel. Thus, the cost of preparing such a fracturing fluid is reduced, and the cost of recycling or processing flowback from such a fluid may be reduced as well.

Referring to FIG. 2, a further method of treating a subterranean formation, for example reservoir 24, is also disclosed. A first fluid part of a hydrocarbon fracturing fluid is introduced into the subterranean formation, the first fluid part comprising liquefied petroleum gas, the first fluid part for example comprising predominantly liquefied petroleum gas. The first fluid part may be for example a pad of for further example 50 cubic meters of LPG. A second fluid part of the hydrocarbon fracturing fluid is then introduced into the subterranean formation after the first fluid part, the second fluid part comprising one or more of liquid hydrocarbons with at least six carbons or LPG. In one embodiment the second fluid part comprises predominantly liquid hydrocarbons with at least six carbons. The second fluid part may be used to carry proppant. The second fluid part may comprise a gelling agent. The first part and second part may at least partially mix together downhole. The hydrocarbon fracturing fluid is then subjected to pressures above the formation pressure, for example above fracturing pressures. This method may allow cheaper heavier liquid hydrocarbon fracturing fluids to be used in a frac, while still taking advantage of the ease of removal of LPG from the formation. After squeezing the LPG into the formation, the second fluid part acts like a plunger to press the injected LPG pad further into the formation to frac. Upon flowback, the volatile LPG pad actively aids to push the second fluid part out of the formation, thus simplifying clean-up. In addition, using a pad of ungelled LPG is advantageous particularly in oil reservoirs because the LPG pad mixes with and dilutes the oil, allowing the following injection of gelled frac fluid to more effectively penetrate the reservoir.

FIGS. 12A-C illustrate a further embodiment of a process of processing liquefied petroleum gas used in a treatment fluid. In addition, Table 1 is provided below to indicate the composition of fluids at various stages in the process scheme. As LPG treatment fluids are recovered from the well, the feed mole fraction of propane drops from around 0.90 for initial recovery to zero at full recovery. Table 1 illustrate statistics for a feed recovery stream (Feed) at 0.67 mole fraction propane, eventually recovering purified LPG (Product_LPG) with a propane mole fraction of 0.9, and a butane mole fraction of 0.07, with around 0.01 mole fraction of methane. The LPG produced as Product_LPG is suitable for use in a further treatment, sale, or storage, as may be desired. The operation of the illustrated schematic will now be described. Starting at the stream referenced as “Feed”, recovered treatment fluids are fed into the system, and pass through a satellite tank (Sat 1) to remove solids, before heading as stream S1 through a heater H2, in order to fully vaporize any LPG in the fluid. Exit stream S2 is then combined in mixer MS with stream 24, which will be discussed in greater detail below. The resulting stream S6 then passes into one or more separator tanks Sep3 and Sep4. Generally, if the recovered treatment fluids contain water or heavier hydrocarbons, such components would be removed from the fluid stream from the base of Sep3 and Sep4 in streams S2_B and S_6B, respectively. Should the fluids that are removed as S2_B and S6_B contain high mole fractions of LPG components, these streams may be rerouted back into stream S24, or into the De-ethanizer D1 as desired.

The gaseous stream S3, which contains mainly methane, ethane, propane, and butane all as gases, is taken from the top of Sep3 and passed through a compressor CP1 in order to pressurize the fluids. Thus begins a series of pressurizations and temperature reductions that will eventually liquefy the LPG components and separate out methane gas. The gas stream is then passed through a forced flow air cooler AC1, and sent as stream S5 into the next separator tank Sep4, where gas stream S7 is taken off of the top of for further processing. Because of the subsequent pressurization and cooling of the gas stream, at this stage a hydrate reducing agent may be added to the stream S7. In the illustration provided, the hydrate reducing agent combined with stream S7 in mixer M1 is supplied via stream S22 as a mixture of Ethylene glycol (0.82 mole fraction) and water (0.18 mole fraction). In this case, the hydrate reducing agent is added in about 1% V/V, although other concentrations may be used as desired. In addition, the hydrate reducing agent may be added at more than one point in the stream, such as after each heat exchanger. Another example of a hydrate reducing agent is methanol. In addition, the hydrate reducing agent may be supplied as part of a hydrate reducing agent regeneration system aimed to regenerate and re-use the agent. An example of such a regeneration system is further detailed below.

The stream S9 is then sent through one or more heat exchangers Hx3, Hx1, and Hx2 in series in order to drop the temperature of the stream. Heat exchangers used herein may use recycled heat in order to make the process more economical. In general, the system shown in FIGS. 12A-C may be operated using only one gas or diesel powered generator to provide electrical energy to power all the LPG recycling equipment. Stream 13 is then sent through a chiller C4, of a refrigeration unit, where the temperature is reduced further to liquefy LPG components in the stream. Finally, the stream S16 is sent into a low temperature separator LTS, which in the example shown is a 3 phase separator. At the base of the LTS is removed stream LTS_Hvy, which is mostly a stream of hydrate reducing agent. LTS_Hvy is then fed back into the hydrate reducing regeneration system, discussed further below.

As shown, the liquefied petroleum gas portion and the natural gas portion may be separated as a cooled stream of LPG (LTS_HC_Liq) and a cooled stream of natural gas (LTSVap), respectively. Tracking the path of the natural gas, stream LTSVap is removed from the top of separator LTS, and passed through heat exchanger Hx2 in order to warm up and cool the stream of gases S12 that are in the process of being cooled. In general, liquefying the gaseous LPG may further comprise cooling a stream of the gases, such as streams S9, S10, S12 and S13, by transferring heat from the stream of the gases to one or more of the cooled stream of LPG and the cooled stream of natural gas. This recycles heat, reducing the operating costs of the systems and increasing efficiency. It also allows the LPG portion and natural gas portions to be heated to desired temperatures. It should be understood that heat exhange in any embodiment disclosed herein may recycle heat from another part of the process, or may even exchange heat with the environment. An example of the latter is shown with heater C1, which is a representation of heat transfer from the environment to the hydrate reducing agent in stream S26. Referring back to the path of natural gas in the stream LTSVap, after passing through two heat exchangers Hx2 and Hx3, the gas may be suitably heated and ready for production as sales gas. Additional processing may be carried out on the stream of Sales_Gas as desired, for example to tailor the dew point or composition. Alternatively, the natural gas produced here or at any stage of the embodiments disclosed herein could be used to power the recycling process.

Tracking the path of purified LPG from separator LTS, stream LTS_HC_Liq has thus far had the mole fraction of propane raised from the Feed stream from 0.66 to 0.85. Additional processing may be carried out at this stage, such as further purification achievable by passing the LPG stream through a De-ethanizer D1. Stream LTS_HC_Liq is first passed through De-Ethanizer Feed Pump D2, and heat exchanger Hx1, before being sent into the De-ethanizer D1. From the base of De-ethanizer D1, a stream of purified LPG (Product_LPG) is removed with a combined propane/butane mole fraction of 0.97. Various components such as a re-boiler (not referenced) may be used with De-Ethanizer as desired. Gases from the top of De-ethanizer D1 may still have relatively high mole-fractions of methane or propane, and may be re-circulated back into the system through stream S24.

The Hydrate reducing agent regeneration system will now be described, with reference to the exemplary hydrate reducing agent of ethylene glycol and water. Various mole ratios of ethylene glycol and water may be used, such as 4:1 or 1:1, as examples. From separator LTS, stream LTS_Hvy, which is largely water and ethylene glycol, is heated by the environment at heater C1, before being passed as stream S25 through heat exchanger Hx4. Stream 30_1 is then passed through a flash separator tank EF_FlashSep, where a relatively small amount of gases is removed as stream S31_1, and liquids are removed as stream S27 and passed into an ethylene glycol regenerator EG-Regen. EG-Regen may have, for example condensers and reboilers as desired. Vapors are removed from EG-Regen as stream EG-RegenVap, and may largely consist of water vapor in the example shown. The liquid leaving EG-Regen as stream EGRegenLiq has roughly the same Ethylene Glycol/Water composition as the input stream “Makeup”, and is thus combined with stream “Makeup” and cycled again through the system.

Chiller C4 may be part of a suitable refrigeration system such as the one shown. The exemplary refrigeration system shown here is a propane system, with a Chiller C4, a Suction Scrubber (RefSnScrbr), a heater H1, a compressor RefCompr, an air-cooler AC3, an accumulator RefAccum, and other components as required and known in the art, such as valve V11. Other components used in the system as a whole, such as lines, valves (example V1-4, 6, 7, and 11) are understood to be conventional components.

TABLE 1

Properties of fluid at various stages of Recycling.

Name
EGRegenLiq
EG_RegenVap
Feed
LTS-Hvy
LTSVap
LTS_HC_Liq

VapFrac
0
1
1
0
1
0

T [C]
134
110.9
16
−38.5
−38.5
−38.5

P [kPa]
135
132.45
800
1135.53855
1135.53855
1135.53855

MoleFlow [kgmole/h]
2.85
0.23
189.95
3.08
56.05
73.09

StdLiqVolumeFlow [m3/hr]
0.112
0.004
15.53
0.116
3.74
6.232

StdGasVolumeFlow [SCMD]
1.62E+03
1.30E+02
1.08E+05
1.75E+03
3.19E+04
4.16E+04

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0

NITROGEN
0
0
0.07
0
0.24
0.01

CARBON DIOXIDE
0
0
0
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0

METHANE
0
0
0.19
0
0.61
0.07

ETHANE
0
0
0.03
0
0.03
0.04

PROPANE
0
0
0.67
0
0.11
0.85

ISOBUTANE
0
0
0.02
0
0
0.01

n-BUTANE
0
0
0.03
0
0
0.02

ISOPENTANE
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0
0

C7+*
0
0
0
0
0
0

MassFraction [Fraction]

WATER
0.1838
0.9796
0
0.21
4.10E−06
5.24E−07

ETHYLENE GLYCOL
0.8162
0.0102
0
0.7893
9.63E−09
1.97E−06

Name
Makeup
Product_LPG
S1
S2
S2_B
S3
S4

VapFrac
0
0
1
1
0
1
1

T [C]
20
29.8
16
67.4
60
60
112.7

P [kPa]
150
1245
800
765
765
765
1835

MoleFlow [kgmole/h]
0
134.09
190.37
190.37
0
214.67
214.67

StdLiqVolumeFlow [m3/hr]
0
11.793
15.537
15.537
0
17.385
17.385

StdGasVolumeFlow [SCMD]
8.00E−01
7.62E+04
1.08E+05
1.08E+05
5.69E−38
1.22E+05
1.22E+05

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0
0

NITROGEN
0
0
0.07
0.07
0
0.07
0.07

CARBON DIOXIDE
0
0
0
0
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0
0

METHANE
0
0.01
0.19
0.19
0.03
0.2
0.2

ETHANE
0
0.02
0.03
0.03
0.01
0.03
0.03

PROPANE
0
0.9
0.67
0.67
0.8
0.66
0.66

ISOBUTANE
0
0.03
0.02
0.02
0.04
0.02
0.02

n-BUTANE
0
0.04
0.03
0.03
0.07
0.02
0.02

ISOPENTANE
0
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0.01
0
0

C7+*
0
0
0
0
0.03
0
0

MassFraction [Fraction]

WATER
0.2
5.77E−04
0.001
0.001
3.02E−04
0.0018
0.0018

ETHYLENE GLYCOL
0.8
1.01E−06
0
0
4.77E−08
6.77E−09
6.77E−09

Name
S5
S6
S6_B
S7
S9
S10
S12

VapFrac
0.60261
1
0
1
0.97656
0.96768
0.75397

T [C]
25
60
25
25
25
24
13.5

P [kPa]
1800
765
1800
1800
1800
1765
1730

MoleFlow [kgmole/h]
214.67
214.67
85.31
129.36
132.21
132.21
132.21

StdLiqVolumeFlow [m3/hr]
17.385
17.385
7.408
9.976
10.088
10.088
10.088

StdGasVolumeFlow [SCMD]
1.22E+05
1.22E+05
4.85E+04
7.36E+04
7.52E+04
7.52E+04
7.52E+04

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0
0

NITROGEN
0.07
0.07
0.01
0.11
0.11
0.11
0.11

CARBON DIOXIDE
0
0
0
0
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0
0

METHANE
0.2
0.2
0.04
0.3
0.3
0.3
0.3

ETHANE
0.03
0.03
0.02
0.04
0.03
0.03
0.03

PROPANE
0.66
0.66
0.85
0.53
0.52
0.52
0.52

ISOBUTANE
0.02
0.02
0.03
0.01
0.01
0.01
0.01

n-BUTANE
0.02
0.02
0.04
0.01
0.01
0.01
0.01

ISOPENTANE
0
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0
0
0

C7+*
0
0
0
0
0
0
0

MassFraction [Fraction]

WATER
0.0018
0.0018
0.0028
9.39E−04
0.0059
0.0059
0.0059

ETHYLENE GLYCOL
6.77E−09
6.77E−09
1.46E−08
1.48E−11
0.0223
0.0223
0.0223

Name
S13
S14
S15
S16
S17
S18
S19

VapFrac
0.71206
0
0.3915
0.42392
0
1
0

T [C]
10.3
4.2
−34
−38.5
4.2
8.5
−38.1

P [kPa]
1695
104.999
1660
1135.53855
104.999
1100.53855
1550

MoleFlow [kgmole/h]
132.21
2.85
132.21
132.21
2.85
56.05
73.09

StdLiqVolumeFlow [m3/hr]
10.088
0.112
10.088
10.088
0.112
3.74
6.232

StdGasVolumeFlow [SCMD]
7.52E+04
1.62E+03
7.52E+04
7.52E+04
1.62E+03
3.19E+04
4.16E+04

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0
0

NITROGEN
0.11
0
0.11
0.11
0
0.24
0.01

CARBON DIOXIDE
0
0
0
0
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0
0

METHANE
0.3
0
0.3
0.3
0
0.61
0.07

ETHANE
0.03
0
0.03
0.03
0
0.03
0.04

PROPANE
0.52
0
0.52
0.52
0
0.11
0.85

ISOBUTANE
0.01
0
0.01
0.01
0
0
0.01

n-BUTANE
0.01
0
0.01
0.01
0
0
0.02

ISOPENTANE
0
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0
0
0

C7+*
0
0
0
0
0
0
0

MassFraction [Fraction]

WATER
0.0059
0.1838
0.0059
0.0059
0.1838
4.10E−06
5.24E−07

ETHYLENE GLYCOL
0.0223
0.8162
0.0223
0.0223
0.8162
9.63E−09
1.97E−06

Name
S20
S21
S22
S24
S25
S26
S27

VapFrac
0.09838
0.09838
0
0.96676
0.00045
0.00035
0

T [C]
16
16
4.6
14.8
−24
−38.3
100

P [kPa]
1515
1515
1800
1241
480.01042
515.01042
445.01042

MoleFlow [kgmole/h]
73.09
73.09
2.85
24.3
3.08
3.08
3.08

StdLiqVolumeFlow [m3/hr]
6.232
6.232
0.112
1.847
0.116
0.116
0.116

StdGasVolumeFlow [SCMD]
4.16E+04
4.16E+04
1.62E+03
1.38E+04
1.75E+03
1.75E+03
1.75E+03

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0
0

NITROGEN
0.01
0.01
0
0.04
0
0
0

CARBON DIOXIDE
0
0
0
0
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0
0

METHANE
0.07
0.07
0
0.3
0
0
0

ETHANE
0.04
0.04
0
0.06
0
0
0

PROPANE
0.85
0.85
0
0.57
0
0
0

ISOBUTANE
0.01
0.01
0
0.01
0
0
0

n-BUTANE
0.02
0.02
0
0.01
0
0
0

ISOPENTANE
0
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0
0
0

C7+*
0
0
0
0
0
0
0

MassFraction [Fraction]

WATER
5.24E−07
5.24E−07
0.1838
0.0087
0.21
0.21
0.21

ETHYLENE GLYCOL
1.97E−06
1.97E−06
0.8162
6.60E−08
0.7893
0.7893
0.7896

Name
S30
S30_1
S31
S31_1
S34
S42
S43

VapFrac
0
0.00088
0
1
0
1
1

T [C]
134
100
4.2
100
4.6
−37
−37

P [kPa]
134.999
445.01042
104.999
445.01042
2000
126.69348
126.69348

MoleFlow[kgmole/h]
2.85
3.08
2.85
0
2.85
86.85
86.85

StdLiqVolumeFlow [m3/hr]
0.112
0.116
0.112
0
0.112
7.592
7.592

StdGasVolumeFlow [SCMD
1.62E+03
1.75E+03
1.62E+03
1.55E+00
1.62E+03
4.94E+04
4.94E+04

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0
0

NITROGEN
0
0
0
0.02
0
0
0

CARBON DIOXIDE
0
0
0
0.07
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0
0

METHANE
0
0
0
0.79
0
0
0

ETHANE
0
0
0
0.02
0
0
0

PROPANE
0
0
0
0
0
1
1

ISOBUTANE
0
0
0
0
0
0
0

n-BUTANE
0
0
0
0
0
0
0

ISOPENTANE
0
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0
0
0

C7+*
0
0
0
0
0
0
0

MassFraction [Fraction]

WATER
0.1838
0.21
0.1838
0.1013
0.1838
0
0

ETHYLENE GLYCOL
0.8162
0.7893
0.8162
0.0085
0.8162
0
0

Name
S44
S45
S46
S47
S48
S49
Sales_Gas

VapFrac
0
1
1
0
0
0.36977
1

T [C]
−37
−34
61.5
25
25
−37
18

P [kPa]
126.69348
126.69348
987.63929
952.63929
952.63929
126.79348
1065.53855

MoleFlow [kgmole/h]
0
86.85
86.85
86.85
86.85
86.85
56.05

StdLiqVolumerFlow [m3/hr]
0
7.592
7.592
7.592
7.592
7.592
3.74

StdGasVolumeFlow [SCMD
5.69E−38
4.94E+04
4.94E+04
4.94E+04
4.94E+04
4.94E+04
3.19E+04

MoleFraction [Fraction]

HYDROGEN
0
0
0
0
0
0
0

HELIUM-4
0
0
0
0
0
0
0

OXYGEN
0
0
0
0
0
0
0

NITROGEN
0
0
0
0
0
0
0.24

CARBON DIOXIDE
0
0
0
0
0
0
0

HYDROGEN SULFIDE
0
0
0
0
0
0
0

METHANE
0
0
0
0
0
0
0.61

ETHANE
0
0
0
0
0
0
0.03

PROPANE
1
1
1
1
1
1
0.11

ISOBUTANE
0
0
0
0
0
0
0

n-BUTANE
0
0
0
0
0
0
0

ISOPENTANE
0
0
0
0
0
0
0

n-PENTANE
0
0
0
0
0
0
0

n-HEXANE
0
0
0
0
0
0
0

C7+*
0
0
0
0
0
0
0

MassFraction [Fraction]

WATER
0
0
0
0
0
0
4.10E−06

ETHYLENE GLYCOL
0
0
0
0
0
0
9.63E−09

In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.

METHODS OF FRACTURING WITH AND PROCESSING LPG BASED TREATMENT FLUIDS

Information

Publication Number

Date Filed

Date Published

Inventors

CPC

US Classifications

International Classifications

Abstract

Description

Claims

PCT Information