as) United States
`a2) Patent Application Publication (0) Pub. No.: US 2015/0368566 Al
`
` Younget al. (43) Pub. Date: Dec. 24, 2015
`
`
`US 20150368566A1
`
`(54) SYSTEMS AND METHODS FOR
`CONTROLLING, MONITORING, AND
`OPERATING REMOTEOIL AND GAS FIELD
`EQUIPMENT OVER A DATA NETWORK
`WITH APPLICATIONS TO RAW NATURAL
`GAS PROCESSING AND FLARE GAS
`CAPTURE
`
`(52) U.S.C.
`CPC veesesssseeseee C10G 5/06 (2013.01); HO4W 76/02
`(2013.01); GOSB 15/02 (2013.01); CIOL 3/10
`(2013.01); CIOL 2290/30 (2013.01); CIOL
`2290/46 (2013.01); CIOL 2290/58 (2013.01);
`CIOL 2290/60 (2013.01)
`
`(71) Applicant: Pioneer Energy Inc., Lakewood, CO
`(US)
`
`(57)
`
`ABSTRACT
`
`(72)
`
`Inventors: Andrew Young, Wheat Ridge, CO (US);
`Matthew Lewis, Lakewood, CO (US);
`Gevorg Sargsyan, Lakewood, CO (US);
`Kevin Hotton, Arvada, CO (US);
`Robert M Zubrin, Golden, CO (US)
`
`(21) Appl. No.: 14/835,673
`
`(22)
`
`Filed:
`
`Aug. 25, 2015
`
`Related U.S. Application Data
`
`(63) Continuation-in-part of application No. PCT/US2014/
`042437, filed on Jun. 14, 2014, which is a continuation
`of application No. 14/086,031, filed on Nov. 21, 2013.
`
`(60) Provisional application No. 61/836,220, filed on Jun.
`18, 2013.
`
`Publication Classification
`
`(51)
`
`Int. Cl.
`C10G 5/06
`GOSB 15/02
`C10L 3/10
`HOAW 76/02
`
`(2006.01)
`(2006.01)
`(2006.01)
`(2006.01)
`
`An intelligent controls system for a field-deployable system
`for producing dry natural gas (NG) and natural gas liquids
`(NGLs) from a raw gas stream is disclosed. The control
`system is usedto ensure correct specifications ofboth dry NG
`(above a desired minimum methane number) and NGLs(be-
`low a desired maximum vaporpressure) from any supplied
`raw natural gas source by controlling three system param-
`eters: inlet gas flow rate, system operating pressure, and sepa-
`rator-reboiler temperature set point. The input parameters
`include: heat content of the input gas stream, volumeofthe
`input gas stream, desired methane number of the NG, and
`desired vapor pressure of the NGLs. The controls system
`allows any piece of remote field equipment for performing
`complex chemical processing to be monitored, controlled,
`and operated remotely. A large array of distributed field
`equipmentsituated around the world can all be controlled
`primarily through a single interface provided in a central
`control center.
`
`
`
`CRUSOE-1014
`
`CRUSOE-1014
`
`1
`
`

`

`Patent Application Publication
`
`Dec. 24,2015 Sheet 1 of 21
`
`US 2015/0368566 Al
`
`II
`
`NATURAL
`GAS
`
`
`
`MIXTURE
` 102
`
`INTERNAL POWER
`GENERATION
`
`
`
`1
`
`05
`
`ETHANE
`
`
`
`EXTERNAL POWER
`GENERATION
`
`POWER TO
`CUSTOMER
`
`108
`
`109
`
`2
`
`

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`Patent Application Publication
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`Dec. 24, 2015 Sheet 2 of 21
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`US 2015/0368566 Al
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`Patent Application Publication
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`Dec. 24,2015 Sheet 3 of 21
`
`US 2015/0368566 Al
`
`Fig. 3
`
`coo
`
`BRING PORTABLE MAGS
`SYSTEM TO OIL FIELD FLARE
`
`RECEIVE RAW NATURAL
`GAS FROM THE FLARE SITE
`
`COMPRESS THE NATURAL GAS
`STREAM UTILIZING ACOMPRESSOR
`
`REMOVE WATER
`UTILIZING A DEHYDRATOR
`
`LOWER THE GAS TEMPERATURE UTILIZING
`A CASCADE/AUTOCASCADE REFRIGERATOR
`
`SEPARATE THE GAS STREAM
`INTO 3 PRODUCT STREAMS
`
`COLLECT THE NGLs
`FOR TRANSPORT
`
`304
`
`306
`
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`SO
`
`310
`
`312
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`314
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`316
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`GENERATE ELECTRICITY
`UTILIZING THE LEAN METHANE STREAM
`
`318
`
`UTILIZE ETHANE STREAM
`FOR SELF-POWER
`
`(OPTIONAL) USE CHa STREAM TO CREATE
`CNG, LNG, OR LIQUID FUELS
`
`(OPTIONAL) USE CH4 STREAM TO
`CREATE CO2 AND H2 FOR EOR
`
`(OPTIONAL) TRANSMIT
`ELECTRICITY TO GRID
`
`END
`
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`Patent Application Publication
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`Dec. 24,2015 Sheet 4 of 21
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`US 2015/0368566 Al
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`Patent Application Publication
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`Dec. 24,2015 Sheet 10 of 21
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`Patent Application Publication
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`Dec. 24,2015 Sheet 11 of 21
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`Patent Application Publication
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`Dec. 24,2015 Sheet 12 of 21
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`Patent Application Publication
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`Patent Application Publication
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`Dec. 24,2015 Sheet 20 of 21
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`US 2015/0368566 Al
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`
`|_-~ 1906 INPUT
`DEVICES(S)
`
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`SYSTEM
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`Patent Application Publication
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`Dec. 24, 2015 Sheet 21 of 21
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`US 2015/0368566 Al
`
`HEAT CONTENT OF
`INPUT GAS
`
`VOLUME OF INPUT GAS
`
`DESIRED METHANE
`NUMBER
`
`DESIRED VAPOR
`PRESSURE
`
` INLET FLOW RATE
`
`CONTROL
`SYSTEM/
`METHOD/
`MODULE
`
`SYSTEM PRESSURE
`
`SEPARATOR TEMPERATURE
`SETPOINT
`
`22
`
`22
`
`

`

`US 2015/0368566 Al
`
`Dec. 24, 2015
`
`SYSTEMS AND METHODS FOR
`CONTROLLING, MONITORING, AND
`OPERATING REMOTEOIL AND GAS FIELD
`EQUIPMENT OVER A DATA NETWORK
`WITH APPLICATIONS TO RAW NATURAL
`GAS PROCESSING AND FLARE GAS
`CAPTURE
`
`REFERENCE TO RELATED APPLICATIONS
`
`[0001] This application is a Continuation-In-Part (“bypass
`CIP”) and claims the benefit of earlier-filed International
`Application No. PCT/US2014/042437, filed Jun. 14, 2014
`and entitled “Systems And Methods For Separating Alkane
`Gases WithApplications To Raw Natural Gas Processing And
`Flare Gas Capture”, which itself claims priority from U.S.
`Ser. No. 14/086,031, filed on Nov. 21, 2013, entitled “Sys-
`tems And Methods For Separating Alkane Gases With Appli-
`cations To Raw Natural Gas Processing And Flare Gas Cap-
`ture,” as well as claims priority from U.S. Ser. No. 61/836,
`220, filed on Jun. 18, 2013, entitled “Mobile Alkane Gas
`Separator,” the entirety of all of which are hereby incorpo-
`rated by reference herein.
`
`NOTICE OF COPYRIGHTS AND TRADEDRESS
`
`[0002] A portion ofthe disclosure of this patent document
`contains material which is subject to copyright protection.
`This patent document may show and/or describe matter
`which is or may become tradedress of the owner. The copy-
`right and tradedress owner has no objection to the facsimile
`reproduction by anyoneofthe patent disclosure as it appears
`in the U.S. Patent and Trademark Office files or records, but
`otherwise reserves all copyright and tradedress rights what-
`soever.
`
`FIELD OF THE INVENTION
`
`[0003] The present invention relates to systems and meth-
`ods for remotely controlling, monitoring, and operating oil
`and gas field equipment over a data network, such as the
`Internet. The present invention also relates to enabling the
`utilization of raw natural gas, such asflare gas, stranded gas,
`associated gas, and so on, for power generation and liquids
`capture. More specifically, this invention relates to control-
`ling a mobile system for separating raw natural gas into a
`high-quality methane gas stream, an ethane-rich gas stream,
`and a natural gas liquids stream.
`
`BACKGROUNDOF THE INVENTION
`
`[0004] The statements in this section merely provide back-
`ground informationrelated to the present disclosure and may
`not constitute priorart.
`[0005] Currently, managing, monitoring, and controlling
`remote oil and gas field equipmentis a time consuming and
`cumbersomeprocess. Systems must be controlled and moni-
`tored by multiple on-site personnel, and require significant
`labor, time, and cost. The problem is even more significant for
`large, distributed installations of multiple machinesdistrib-
`uted across multiple locations, sometimesall over the world.
`The problem becomes even more complicated with opera-
`tions in remote locations, far from personnel and located in
`places that are difficult or expensive to reach.
`[0006] Backgroundrelative to one example of application
`of the present invention to oil and gas equipment is now
`described. Currently liquids-rich raw natural gas is being
`
`flared in large quantities at numerouslocationsby oil produc-
`ers. This activity entails significant loss of incomethat could
`be earnedbyselling the flared natural gas liquids. Still more
`financial losses are entailed by failing to make use of the
`methane content of the flared gas to generate power. As a
`result, such oil producers have to buy their electric power
`from the grid, or even worse, generate it themselves at sig-
`nificant cost (typically USD$ 0.40/kWh) throughthe use of
`on-site diesel generators consuming expensive fuel. Further-
`more, the large-scale flaring of natural gas has raised envi-
`ronmental issues that could cause state and/or federal regu-
`lators to take actionto fine, shutdown,or highly regulatetheir
`operations.
`
`[0007] The United States oil and gas industry annually
`flared approximately 7.1 billion cubic meters (bem), or 250
`billion cubic feet (bef) in 2011 (Source: Global Gas Flaring
`Reduction Partnership, Estimated Flared Volumesfrom Sat-
`ellite Data, 2007-2011, 2013), and the situation has only
`gotten worse in 2014. “Flaring will escalate as oil producers
`approach the milestone of 1 million barrels a day from the
`Bakken formation, a 360-million-year-old shale bed two
`miles underground. About 10,100 wells produced 29 million
`barrels of oil in January 2014, according to the North Dakota
`Industrial Commission.Drillers flared 340 million cubic feet
`
`(mincf), or 34 percent, ofthe 1 billion cubic feet ofnatural gas
`producedper day in January 2014, about twice as muchas the
`184 million cubic feet burned per day in 2011, said Marcus
`Stewart, an analyst at Denver-based Bentek Energy. ‘The lost
`revenue adds up to $1.4 million each day,’ said Stewart.
`Energy executives say economicrealities force them tostart
`producing oil from wells before infrastructure is in place to
`haul away less-valuable natural gas. Bakken oil fetched $98.
`14 on Apr. 4, 2014 while natural gas for May 2014 delivery
`fell
`to $4.44 per MMBTU on the New York Mercantile
`Exchangethe sameday. ‘We absolutely don’t wantto flare the
`gas, that’s lost revenue,’ said Russell Rankin, a regional man-
`ager for Norway-basedStatoil. ‘But if we drill a $10 million
`well, we’ve got lots of investors and they can’t wait to get that
`revenue back,’ said Rankin.” (Source: Jennifer Oldham, 4
`Landscape of Fire Rises Over North Dakota’s Gas Fields,
`Bloomberg News, Apr. 7, 2014)
`
`[0008] Canada also hassignificant flare gas resources. It is
`estimated that Canada flared 2.4 billion m®* per year in 2011
`(Source: Global Gas Flaring Reduction Partnership, Fsti-
`mated Flared Volumes from Satellite Data, 2007-2011,
`2013.) It is estimated that the Canadian province of Alberta
`alone flared 868 million m? and vented another 333 million
`m® in 2007. (Source: Bott, R. D., Flaring Questions and
`Answers, 2nd ed., Canadian Centre for Energy Information,
`2007.) A similar situation holds around the world, with sig-
`nificant quantities of gasflared in Russia, Nigeria, and other
`parts of the world.
`
`[0009] Despite the recent oil price drop in 2015, due to a
`glut ofoil from fracking flooding the world markets,flaring of
`stranded gas continues to be a problem in the U.S., Canada,
`and around the world. Therefore, there exists an important
`need for a solution to address the problem of utilizing raw
`natural gas to the maximum extent and to minimizeorelimi-
`nate flaring completely.
`
`[0010] However, often the locations of such flares and
`stranded gas are remote and far from human operations. This
`makescontrolling, monitoring, and managing such systems
`extremely complicated and expensive.
`
`23
`
`23
`
`

`

`US 2015/0368566 Al
`
`Dec. 24, 2015
`
`[0011] Accordingly, as recognized by the presentinventors,
`what are needed are a novel method, apparatus, and system
`for controlling remote oil and gas field systems.
`[0012] Therefore, it would be an advancementin the state
`of the art to provide an apparatus, system, and method for
`cost-effectively controlling, monitoring,
`and managing
`remote oil and gas field systems, allowing such systemsto be
`widely deployed to geographically remote locations around
`the world. It would also be an advancementin the state of the
`
`art to provide systems and methodsto allow such systemsto
`be cost-effectively installed, deployed, and commissioned,
`from a central control operations center located in a central
`location, capable of managing many such widely distributed
`systems.
`It is against this background that various embodi-
`[0013]
`ments of the present invention were developed.
`
`BRIEF SUMMARY OF THE INVENTION
`
`In the following description, for purposes of expla-
`[0014]
`nation, numerous specific details are set forth in order to
`provide a thorough understanding of the invention. It will be
`apparent, however, to one skilled in theart that the invention
`can be practiced without these specific details. In other
`instances, structures, devices, activities, and methods are
`shown using schematic, use case, and/or flow diagrams in
`order to avoid obscuring the invention. Although the follow-
`ing description contains many specifics for the purposes of
`illustration, anyoneskilled in the art will appreciate that many
`variations and/or alterations to suggested details are within
`the scope ofthe present invention. Similarly, although many
`of the features of the present invention are described in terms
`of cach other, or in conjunction with cach other, one skilled in
`the art will appreciate that many of these features can be
`provided independently of other features. Accordingly, this
`description of the invention is set forth without any loss of
`generality to, and without imposing limitations upon, the
`invention.
`
`[0015] One aspect of the MAGScontrol system is used to
`ensure the correct specifications of both dry methane gas
`(above a desired minimum methane number) and NGLs(be-
`low a desired maximum vaporpressure) from any supplied
`raw natural gas source.
`[0016]
`In one embodiment, this is achieved by controlling
`three key system parameters: a) inlet gas flow rate, b) system
`operating pressure, and c) separator-reboiler temperature set
`point. Certain parameters are input to the control system to
`give desired dry methane andspecific NGL specifications. In
`one embodiment, these input parameters include: 1) heat
`content
`(or equivalently, composition) of the input gas
`stream, 2) volumeofthe input gas stream, 3) desired methane
`numberof the A-gas (dry methane stream), and 4) desired
`vaporpressure ofthe NGLs Y-gradeliquid stream (C-stream).
`The heat content and volume of the input gas, the desired
`methane numberof the A-gas, and the desired vapor pressure
`of the NGLs can be expressed in either gross units (such as
`heat content, vapor pressure, etc.) or as concentration of the
`individual C1-C12+ constituents of the stream. In some
`embodiments, since the B-stream, comprising high quantities
`of ethane, is consumed internally for power generation uti-
`lizing a suitably tuned engine, the composition of this B-gas
`can be allowed to vary widely and does not need to be con-
`trolled to any specific degree. However, if the B-gas was
`being utilized for some specific purpose, it too can be con-
`trolled for ethane content.
`
`[0017] The heat content and volumeflow rate of the input
`gas stream is determined by the input gas source field char-
`acteristics, and generally cannot be controlled. These param-
`eters generally vary from well to well, as well as from time to
`time on the same well, making the controls approach neces-
`sary to achieve desired output stream characteristics.
`[0018]
`In one embodiment, in order to achieve the desired
`minimum methane number, the MAGS system controls an
`inlet gas flow rate of the input gas, and a system operating
`pressure going into the MAGSrefrigeration/separation sub-
`system. To control the inlet flow rate of the gas into the
`MAGS,a flow transmitter meters the gasinlet flow rate and a
`controller (called a VFD), controls the MAGSnatural gas
`compressorto regulate gas inflow into the MAGS. To control
`the system operating pressure, a vapor outlet valve on the
`stripping column is used to achieve the operating pressure
`setpoint. That is, the inlet gas flow-rate and the operating
`pressure determine the methane numberofthe dry gas stream
`(A-gas).
`In one embodiment, in order to achieve the desired
`[0019]
`maximum NGLsvaporpressure, a reboiler temperatureset-
`point and the sameoperating pressure setpoint are controlled.
`The reboiler temperature setpoint is controlled by a reboiler
`system control unit, and the operating pressure setpoint is
`controlled using the pressure control valve of the stripping
`column as before. That is, the reboiler temperature setpoint
`and the operating pressure determinethe vaporpressureofthe
`NGLliquids stream (C-liquids).
`[0020]
`In one embodiment, the result of the above physical
`relationships is a multi-variate expression relating the output
`parameters [a) inlet gas flow rate, b) system operating pres-
`sure, and c) separator-reboiler temperature set point] as a
`function of the input parameters [1) heat content (or equiva-
`lently, composition) of the input gas stream, 2) volumeofthe
`input gas stream, 3) desired methane number of the A-gas
`(dry methane stream), and 4) desired vapor pressure of the
`NGLsY-gradeliquid stream (C-stream)]. This mathematical
`relationship can be used for both simulation and for control
`loop code. The simulation output can be used to select an inlet
`flow rate, a system operating pressure, and a reboiler tem-
`perature setpoint, given the characteristics of the well (a heat
`content of the input gas stream, and a volumeofthe input gas
`stream), and the desired output stream characteristics (the
`desired methane numberofthe dry gas, and the desired vapor
`pressure of the NGL liquids).
`[0021]
`In one embodiment, the reboiler control unit has
`temperature sensors wiredinto the reboiler, and respondsto a
`setpoint. For example, at a setpoint of 40° C., the reboiler
`control unit will monitor the temperature sensors on the
`reboiler, increase or decrease power output as needed, and
`utilize an internal solid state relay to control heater(s) in the
`reboiler, and turns the heater(s) in the reboiler onoroff.
`[0022] According to one embodimentof the control sys-
`tem, there are four (4) input parameters to the control loop,
`and three (3) output parameters to the control loop. Thefirst
`two input parameters, namely heat content and volumeflow
`rate ofthe raw naturalgas, are determined bythe properties of
`the well. The second two input parameters, namely the
`desired methane number (minimum desired methane % in the
`dry gas) and the desired vapor pressure (maximum desired
`vaporpressure in the NGLs) are determined by the end-user
`or operator, and is based on the required specifications of the
`use-case for the dry gas (for example, whether electricity
`generation, CNG production, etc.) and the NGLs (for
`
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`example, NGL fractionator requirements, etc.). Finally, the
`three output parameters, namelytheinlet flow rate, the system
`operating pressure, and the separator temperature setpoint are
`the output parameters of the control loop that control the
`MAGSsystem to perform the required separation to achieve
`the end-useror operator desired parametersfor the given well
`properties. In one embodiment, the inlet flow rate output
`parameter controls the inlet valve and/or the compressors’
`speed to control the inlet flow rate into the MAGSto the
`control system’s setpoint. The system operating pressure out-
`put parameter controls the pressure control valve (in one
`embodiment,situated on theoutlet to the stripping column) to
`control the system operating pressure to the control system’s
`setpoint. The separator temperature setpoint output param-
`eter controls the temperature setpoint of the separation sub-
`system to control the separator operating temperature to the
`control system’s setpoint. In one embodiment, the separator
`temperature setpoint is a reboiler temperature setpoint on a
`reboiler in the separation subsystem. In one embodiment, the
`reboiler temperature setpoint is controlled by a black box
`reboiler controller.
`
`In short, in one embodiment,there is a set of input
`[0023]
`parameters that are determined by the well, a set of input
`parameters that are determined by the operator/end-user/ap-
`plication, and a set of output parameters that control the
`MAGSorotherpiece of field equipmentgiven the twosets of
`input parameters.
`[0024] Other aspects of the MAGS Control System allow
`any piece of oil and gas equipment of whatever nature to be
`remotely controlled, monitored, and managed utilizing a
`graphical user interface (GUI) displayed on any end-user
`device whatsoever.
`
`[0025] Accordingly, embodimentsof the present invention
`include a method, process, system, apparatus, and/or non-
`transitory digital storage medium storing executable program
`code, which when executed by a hardware processor, causes
`the hardware processor to perform a process of controlling
`separation ofa raw natural gas stream into at least two useable
`streams comprising a dry natural gas stream (NG) having a
`desired minimum methane numberanda natural gas liquids
`stream (NGLs) having a desired maximum vaporpressure.
`The method, process, system, apparatus, and/or the program
`code include steps comprising: (1) controlling an inlet flow
`rate of raw natural gas streamto track a predetermined flow
`rate; (2) controlling a system operating pressure to track a
`predetermined system operating pressure; and (3) controlling
`a temperature setpoint of a separation subsystem to track a
`predetermined temperature setpoint, wherein the inlet flow
`rate, the system operating pressure, and the temperatureset-
`point are controlled to maintain the desired minimum meth-
`ane number and the desired maximum vapor pressure, and
`wherein the inlet flowrate, the system operating pressure, and
`the temperature setpoint are determined by a heat content of
`the raw natural gas stream, a volume flow rate of the raw
`natural gas stream, the desired minimum methane number,
`and the desired maximum vaporpressure.
`invention
`[0026] Other embodiments of the present
`include, wherein the inlet flow rate is controlled by control-
`ling an inlet control valve or a compressor speed on one or
`more compressors.
`
`invention
`[0027] Other embodiments of the present
`include, wherein theinlet flow rate is between about 120 mcf
`per day to about 1200 mefper day.
`
`invention
`[0028] Other embodiments of the present
`include, wherein the system operating pressure is controlled
`by controlling a pressure control valve in the separation sub-
`system.
`invention
`[0029] Other embodiments of the present
`include, wherein the system operating pressure is between
`about 6 bar to about 35 bar.
`
`invention
`[0030] Other embodiments of the present
`include, wherein the temperature setpoint of the separation
`subsystem is a reboiler temperature setpoint of a reboiler in
`the separation subsystem.
`invention
`[0031] Other embodiments of the present
`include, wherein the reboiler temperature setpoint is con-
`trolled by a reboiler controller.
`invention
`[0032] Other embodiments of the present
`include, wherein the reboiler temperature setpoint is between
`about 0 degrees C. to about 120 degrees C.
`invention
`[0033] Other embodiments of the present
`include, wherein a composition ofa third stream, comprising
`an ethane-rich stream, is allowed to vary in composition.
`[0034] Other embodiments of the present
`invention
`include, wherein the desired minimum methane number of
`the dry natural gas stream corresponds to a methane content
`selected from the group consisting of 60% methane, 65%
`methane, 70% methane, 75% methane, 80% methane, 85%
`methane, 90% methane, and 95% methane.
`invention
`[0035] Other embodiments of the present
`include, wherein the desired maximum vaporpressure of the
`NGLsstream is no more than 17 barat 38° C.
`
`invention
`[0036] Other embodiments of the present
`include, wherein the desired maximum vaporpressure of the
`NGLsstream is between about 5 bar to about 20 bar at 38° C.,
`and more preferably between about14 bar and about 17 bar at
`38°C.
`
`invention
`[0037] Other embodiments of the present
`include, wherein the heat content of the raw natural gas
`stream is between about 1100 BTU to about 1800 BTU.
`
`invention
`[0038] Other embodiments of the present
`include, wherein the volumeflow rate of the raw natural gas
`stream is between about 100 mef per day to about 5000 mcf
`per day.
`[0039] Yet other embodiments of the present invention
`include a method, process, apparatus, and/or a system for
`remotely monitoring and controlling a chemical process, the
`system comprising a piece of remote field equipment for
`performing the chemical process; a user device; a server
`comprising a hardware processor, a memory, and a non-tran-
`sitory digital storage medium storing executable program
`code; a communications-link between said user device and
`said server; and a plurality ofprogram code embodiedonsaid
`non-transitory digital storage medium,said plurality of pro-
`gram code which when executed causes said hardware pro-
`cessor to execute a process performing thesteps of: (1) estab-
`lishing an equipment-server connection betweensaid piece of
`remote field equipment and said server; (2) establishing a
`client-server connection between said user device and said
`server; (3) providing an interface to allow a userto display a
`plurality of parameters onsaid user device; (4) receiving a set
`of input chemical process parameters corresponding to
`parameters of an input chemical stream; (5) receiving a set of
`desired chemical process output parameters corresponding to
`desired parameters of an output chemical stream; (6) control-
`ling a set of chemical process control parameters to achieve
`the desired chemical process output parameters given the
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`input chemical process parameters and the desired chemical
`process output parameters; and (7) providing an interface to
`allow an operator to manually control and/or manually over-
`ride the set of chemical process control parameters.
`[0040] Other embodiments of the present
`invention
`include, wherein the chemical process is processing a raw
`natural gas stream into two output product streams.
`[0041] Other embodiments ofthe present invention include
`further steps to: controlling an inlet flow rate of the raw
`natural gas stream to a track a predetermined flow rate; con-
`trolling a system operating pressure to track a predetermined
`system operating pressure; and controlling a temperature set-
`point of a separation subsystem to track a predetermined
`temperature setpoint, wherein the inlet flow rate, the system
`operating pressure, and the temperature setpoint are con-
`trolled to maintain a minimum methane numberofa dry gas
`output stream and a maximum vaporpressure a natural gas
`liquids stream (NGLs), and wherein the inlet flow rate, the
`system operating pressure, and the temperature setpoint are
`determined by a heat content and a well flow rate of the raw
`natural gas stream.
`[0042] Yet other embodiments of the present invention
`include a method, process, apparatus, and/or a system for
`controlling separation of a raw natural gas stream into atleast
`two useable streams comprising a dry natural gas stream
`(NG) having a minimum methane number and a natural gas
`liquids stream (NGLs) having a maximum vaporpressure, the
`system comprising one or more compressors adapted to com-
`press the raw natural gas stream; a refrigeration subsystem
`adapted to lower a temperature ofthe compressednatural gas
`stream; a separation subsystem adapted to separate the com-
`pressed and refrigerated natural gas stream into the at least
`two product streams comprising the dry natural gas stream
`thatis at least 65% methane,and the naturalgasliquids stream
`(NGLs) having a vaporpressure of no more than 17 bar at 38°
`C.; and a control subsystem for controlling an inlet flow rate
`of the raw natural gas stream, a system operating pressure,
`and a temperature setpoint of the separation subsystem.
`[0043] Other embodiments of the present
`invention
`include, wherein a third stream, comprising an ethane-rich
`stream, is allowed to vary in composition.
`[0044] Other embodimentsofthe present invention include
`a powergeneration subsystem tunedto run onthe ethane-rich
`stream adaptedto provide electricity to run the system.
`[0045] Other embodiments of the present
`invention
`include, wherein the natural gas liquids stream has a vapor
`pressure of no more than 14 barat 38° C.
`[0046] Other embodimentsofthe present invention include
`a chassis for holding the system for field deployment, said
`chassis mountable to a trailer, a truck,a train, a boat,a floating
`platform,or an airplane.
`[0047] Other embodimentsofthe present invention include
`a dehydration subsystem to dehydrate the raw natural gas
`before compression.
`invention
`[0048] Other embodiments of the present
`include, wherein the dehydration subsystem removesa trace
`humidity from the natural gas stream to achieve an aqueous
`dewpoint below at least -40° C. to -80° C.
`invention
`[0049] Other embodiments of the present
`include, wherein the refrigeration subsystem further com-
`prises a high-stagerefrigeration loop for lowering a tempera-
`ture of the dehydrated, compressed natural gas stream; and a
`low-stage refrigeration loop for further loweri