Automation of Lease Equipment.

8/8/2019 Automation of Lease Equipment.

1/17

Chapter 16Automation of Lease EquipmentG.R. Burrell, Exxono.U.S.A.*

IntroductionAutomation in the oil and gas producing industry coversa broad spectrum of supported functions. In a simple ap-plication, automation may be defined as linking togetherinstruments and controls to perform lease-operating pro-cedures automatically in a predetermined manner.Automation in a more complex environment will havedigital computers in some form of a supervisory controland data acquisition (SCADA) system. Automation inthe industry has tended to evolve as new tools becomeavailable and ate accepted by industry and regulatoryagencies. Generally, automation has advanced by a morecomplex linkage of instruments and control devices.Some of the more important tools and/or techniques thathave enhanced lease automation are (1) solid-state elec-tronics, (2) lease automatic custody transfer (LACT), (3)tank battery consolidation, and (4) SCADA.

Solid-State ElectronicsThe development of solid-state electronics first asdiscrete components and then as integrated circuits hasbeen a key factor in advancing lease automation. Elec-tronics have provided the base for improvements in in-strumentation, control elements, communication, anddigital computers that form the primary components ofenhanced automation facilities. Pneumatic and elec-tromagnetic (relay) logic have been, and will continue tobe, used in various forms of automation, but the extentof logic implementation is limited substantially com-pared with that available for electronics. Pneumaticand/or electromagnetic functions are effective as com-plementary features to electronic forms of automationand as stand-alone automation for less complexapplications.Microprocessors and their extension to microcom-puters are having an impact on automation that may wellAuthorof theoriginal chapler on this topic in the 1962 edition was Don R. Patterson

exceed that of integrated circuits in the initial form ofhard-wired logic. Microcomputers combine the ad-vantages of electronic components and program instruc-tions into a flexible, capable, and reliable form that hassubstantial advantages for automation. These functionaladvantages have been complemented by a reduction incost compared to implementation with integrated cir-cuits. Microcomputers are being used in almost everycomponent of automation related equipment from in-dividual instruments through digital computers.Lease Automatic Custody Transfer (LACT)LACT is the process of transferring (running) lease-produced oil into a connected pipeline on an unattendedbasis. LACT includes the capability to determineautomatically the quantity and quality of oil beingtransferred and the control functions to prevent transferof unacceptable quality and/or volumes. Before LACT,lease oil was produced into a tank, quantity and quality(opening gauge and thieving, etc.) were determined, anda valve was opened to the pipeline to initiate transfer.When the transfer was complete, the pipeline valve wasclosed and a final (closing) gauge was made as basis fordetermining net volume transferred. All these steps weremanual activities with some related duplication of effortbetween the lease operator and the pipeline gauger. Inaddition to being labor intensive, the process was in-herently inefficient in use of related treating and storagefacilities. LACT is an important tool in the evolution oflease automation. LACT is a significant automation ele-ment and has been widely accepted and implemented byindustry. In addition, it has become an importantbuilding block for other forms of automation in leaseoperations.Tank Battery ConsolidationMany oil and gas fields have multiple operators or work-ing interest owners. In addition, most fields consist of anumber of separate leases (common royalty ownership,


2/17

16-Z PETROLEUM ENGINEERING HANDBOOK

etc.) that require individual oil and gas processing(separation, treating, storage and transfer, etc.) facilitiesto account for production to each owner.

LACT initially was applied to these separate leaseoperations. The automatic transfer of produced oil andrecycling of unacceptable quality oil [high basic sedi-ment and water (BS&W) content] to treating facilities in-creased the effectiveness of treating and storage equip-ment. In addition, tire incremental cost of larger meters,pumps, and related equipment of LACTs was low com-pared to the increased oil volume transfer capability.Thus, a technical basis was available to process andtransfer much higher produced-oil volumes than presenton the average lease.Historically, individual lease oil-production volumeshad been treated to pipeline quality (2 % BS&W or less)before custody transfer from the lease. In the 1960s,regulatory agencies began to approve operator requeststo commingle wet-oil (not pipeline quality) productionfrom multiple leases into a common or central oil proc-essing and custody transfer facility. Oil production fromeach lease was determined by measuring the wet-oilvolume (separator positive-volume or positive-displacement meters, etc.) and correcting for water con-tent with automatic samplers and later with capacitanceprobes and related net-oil computers. Final sales volumeto each separate lease was determined by allocating thecustody transferred (sales) volume back to each lease onthe basis of its proportion of total wet-oil leasemeasurements. In other cases, tank battery consolidationwas implemented when a field was unitized under asingle operator for initiation of secondary recoveryactivities.

Tank battery consolidation eliminated oil treating andstorage facilities on the individual lease. In some fields,the pipeline trunk lines used to gather individual lease oilvolumes were converted to wet-oil gathering lines for theconsolidated tank battery operation. Tank battery con-solidation converts a fields operation from a number ofstand-alone lease functions to a central process withmultiple inputs. Oil treating and storage, water treatingand disposal, vapor recovery facility, etc., became moreefficient and controllable in the consolidatedenvironment.Supervisory Control and DataAcquisition (SCADA)SCADA is a common name applied to computer-drivenautomation systems used in oil and gas production opera-tions. Basic functions generally include status/alarmreporting, production volume accumulation/reporting,well testing, and control. These systems vary from smallunits that are applied to only a few leases in a single fieldto large units that serve multiple fields containing severalthousand total wells.

SCADA systems are tied directly to the instrumenta-tion and control devices on the process equipment usedin oil and gas production. This provides timely and con-tinuous access to the operational information beingsensed by the instrumentation. Some SCADA systemsemphasize data gathering and reporting to operating per-sonnel for open-loop control while others use pro-gram logic to analyze input information and initiate con-trol actions directly (close-loop control). SCADA

systems may be oriented primarily to operating person-nel needs, or they may be multipurpose by providingfunctions for operating, accounting, engineering, andmanagement groups.SCADA is a logical extension of automation in the se-quence from manual lease operation, to use of LACT,and then to centralized treating, storage, and automaticcustody transfer (ACT) with tank battery consolidation.This sequence moved from essentially independent in-dividual lease operations to a single overall process thathas a number of closely related functions. SCADA pro-vides the ability to obtain timely operational informationfor optimization of the interrelated process functions.For example, if a compressor outage reduces the gasprocessing capacity below a fields gas-producing rate,well-test information from SCADA allows shutting-in ofwells with high GORs and thus minimizes reduction ofthe related oil producing rate. In general, timely and ac-curate operational information can be used to obtainmaximum utility of existing process equipment andminimize need for stand-by capacity.Some form of automation is used on every lease thatproduces oil and gas. The extent of practical automationdepends primarily on economics. Some of the benefits ofautomation that may be used in the economic justitica-tion are as follows:

1. Capital investment in lease production equipment isreduced.

2. Operating expenses are reduced through savings inlabor costs, maintenance expenses, travel expenses, andpower and fuel costs.3. Ability to initiate and document actions required for

regulatory compliance is improved.4. Surveillance capability of management and support-ing staff groups is improved.5. The quantity and quality of operational informationavailable for making business decisions is increased,which results in revenue increases and operating costdecreases.

Automation in oil and gas production activities willcontinue to evolve as additional tools ate developed andapplied. Most advances (including improved com-munications and smart end devices) will take theform of (1) improvements in existing devices, (2) newdevices with improved capability/reliability to replaceolder equipment, and, less frequently, (3) new deviceswith new features/functions that are applicable to theproduction process. Much of the basic instrumentationand control equipment (primarily pneumatic-based) thathas been used for years with oil and gas processingfacilities will continue to be applicable. Implementationof some form of enhanced automation (as describedearlier) will be a primary force to increase use of elec-tronic and electronic/pneumatic equipment. On thisbasis, it appears reasonable to elucidate the topic ofautomation first by discussing some of the commonlyused equipment and then by depicting equipment ap-plication in automation systems.Automatic Production-Control EquipmentAutomatically Controlled Valves and AccessoriesAutomatic control valves can be classified in a numberof ways, but classification by the energy medium that ac-tuates the valve operator is most pertinent to automation.


3/17

AUTOMATION OF LEASE EQUIPMENT 16-3

By using this method of classification, automatic controlvalves can be grouped into three major categories: fluid-controlled valves, electrically controlled valves, andfluid-electric-controlled valves. In the latter category afluid energy generally is used to operate the valve andelectric energy is used to control the fluid-energy source.Fhdd-Controlled Valves. The most common types ofautomatic fluid-controlled valve operators arc diaphragmoperators and fluid cylinders. Both of these valveoperators can be used on any style of valve body whoseinner valve can be positioned by longitudinal displace-ment of the valve stem. The fluid cylinder operator nor-mally is used with valve-body styles requiring 90 rota-tion for operation. Diaphragm operators most commonlyare applied to valves that have globe, angle, butterfly,and Saunders-type valve bodies. Fluid-cylinderoperators are more commonly used with plug valves.

In oilfield applications, the most common fluid used toactuate both valve operators is natural gas, generallytaken directly off a separator or heater-treater on thelease. If natural gas is not available, or if for some reasonthe available natural gas supply is not suitable, a bottledgas (nitrogen, etc.), compressed air, or hydraulic fluidcould be used. Diaphragm operators normally requireonly 15- to 30-psi fluid pressure to actuate the valve.Pressures up to 100 psi and over often are desired for thefluid cylinders because, the higher the fluid pressureavailable to operate the cylinder, the smaller size thecylinder may be, and consequently the lower the cost.Valves using these types of operators, as a class, are fre-quently called pneumatic control valves even thoughthe control fluid may be something other than air.Some fluid-controlled valves can be controlled withthe fluid flowing in the line in which the valve is located.These types of valves generally use the differentialpressure principle for control purposes. A reference con-trol pressure is established by spring-loading or prcssure-loading the valve operator. The control valve is actuatedwhen the line pressure upstream and/or downstreamsensed by the valve operator algebraically exceeds thereference control pressure-i.e., the valve can be ac-tuated by pressures either excessively high or excessive-ly low, or both. This feature makes this type of valveparticularly suited for use as safety shut-in valves onwellheads.

Electrically Controlled Valves. Automatic electricallycontrolled valve operators arc of two general types,electric-solenoid (or magnetic) and electric motor.Magnetic operators are used for valves requiringlongitudinal motion to position the inner valve. The useof magnetic operators generally is limited to valves 2 in.and smaller in size and of relatively low workingpressures. Electric-motor operators can be used with anytype of valve but in all cases must include accessoriesthat provide a torque-limiting means and a limit switch toprevent damaging the motor when either extreme valveposition is reached. On valves requiring longitudinal mo-tion to seat the inner valve electric-motor, operators alsomust include a gear rack and pinion to convert themotors rotary motion to longitudinal displacement.Because of the relative expense of electric-motor

operators, they normally are used only on large-sizedvalves and/or valves having high working pressures.Fluid-Electric Controlled Valves. Self-contained valveoperators in the third category are generallyhydroelectric-type operators. Operators of this typeessentially consist of a self-contained reservoir ofhydraulic fluid, a small electric motor, a pump, and afluid-cylinder device-all within a single housing. Thefluid-cylinder principle limits this type of operator tovalves requiring longitudinal motion or 90 rotation toseat the inner valve. Valve operators of this type areavailable for a wide variety of valve sizes and working-pressure ranges.In addition to the hydroelectric-type operators, any ofthe fluid-controlled operators mentioned can be madecombination-type operators. By the addition of electric-solenoid valves in the fluid-control lines, an electricsignal can be used to control the release of fluid energyto the valve operator. Combination-type operators of thiskind are commonly called electropneumaticoperators. Valve Switches. It is frequently essential that anautomatic control system be able to sense the position ofcertain valves whether automatically or manuallyoperated. This is accomplished by means of a valveswitch coupled directly to the stem of the valve in ques-tion. In electrical control systems, the valve switch maybe a mercury switch, a microswitch, or a position-sensing switch. In pneumatic control systems, thevalve switch is a three-way pilot valve. The switchesmay be adjusted to open or close a circuit as the valveopens and closes. One of the most common applicationsof valve switches is on tank-run valves, in which casethey are generally called pipeline valve switches.Another common use of valve switches is to indicateremotely the operational position (open, closed, etc.) ofautomatic control valves on wellheads, well manifolds,metering-tank inlets and outlets. In these general ap-plications, valve switches normally will be referred to aslimit switches. When interlocked with an automaticcontrol system, valve switches perform the very impor-tant function of preventing subsequent steps in anautomatic operation from proceeding unless certainvalves are in the proper position. Other type devices canbe used to sense control valve positions at in-termediate points (or continuously) between the openand closed positions.Automatic Production ProgrammersTime-Cycle Controller. Automatic production pro-grammers are scheduling devices that control the par-ticular times and lengths of time that operating functionsare performed. The simplest form of automatic produc-tion programmer is a time-cycle controller. A time-cyclecontroller basically consists of a clock with a timingwheel or wheels, containing a number of programmingpoints at regular intervals around its circumference. Theclock may be electrically driven, gas driven, ormechanically driven by a spring. It may have a l-, 2-, 4-,6-, 8-, 12-, or 24-hour rotation period, the rotationperiod being the time required for the timing wheel(s) to


4/17

16-4 PETROLEUM ENGINEERING HANDBOOK

make one complete revolution. Programming is ac- equipment nearly always is made to be fail safe-i.e.,complished by positioning the contacts on the timing upon loss of power from the controlling energy medium,wheel(s) such that the rotation of the wheel(s) generates the controls return to the position that will result in thethe proper control signal to open or close valves con-trolled by the time-cycle controller at the proper times.

As commonly applied, a time-cycle controller in con-junction with a diaphragm control valve compose astopcock controller and/or an intermitter con-troller. The primary difference in a stopcock controllerand an intermitter controller is in the application. A stop-cock controller generally is installed in a wells flowlineat the Christmas tree. It controls the times that the well isopened for production, normally for short intervalsseveral times a day. An intermitter controller is in-stalled in high-pressure-gas supply line at the wellheadof a well being gas lifted intermittently. It controls thetimes that gas is admitted to the well to actuate the gas-lift valves and lift the fluid to the surface. A time-cyclecontroller in conjunction with any type of automatic con-trol valve may be used to produce a naturally flowingwell where it is desired to produce the well less than 24hours per day and/or 7 days a week.A time-cycle or percentage-time controller plus amotor starter basically compose an automatic productionprogrammer for an electrically driven rod-pumping unit.The rod-pumping unit controls also generally containseveral safety devices: undervoltage relay, which dropsout on power failure, overload relays to prevent burningup the motor, lightning arrester, circuit-breakingdevices, etc.The electronic (solid state) timer frequently is used innew installations that require timer functions.Mechanical and electro-mechanical timers will continueto be used in many existing installations.

Any time that these automatic production-programming devices are actuated electrically, the con-trol point for individual wells may be centralized at thewell manifolds, a central point on the lease, or even apoint remote from the field. The time-cycle controllers,automatic control valves, motor starters, etc. still mayremain located at the wellheads while control is exer-cised remotely. This is not true for similar devices thatare actuated pneumatically unless the pilot gas for thesedevices is controlled electrically. Too much dampeningand distortion occurs in pneumatic control signals for ef-fective control when transmitted distances of more thanabout 150 ft.Other ProgrammersThe programmers discussed previously have been usedin oil and gas production facilities for many years. Cur-rently, the more complex sequential control will beelectronic- and combined electronic/pneumatic-based inmany applications. This trend is expected to increase asgeneral-purpose programmable controllers, developedinitially in the plant applications, find more use in oil andgas production. The functions of the programmable con-troller and the remote terminal unit (RTU) may well becombined into a more capable unit for oil and gas pro-duction monitoring and control applications.Production Safety ControlsIn some respects, virtually all automatic control equip-ment is also safety-control equipment: automatic control

safest condition. Some automation controls, however,primarily perform safety functions rather than normaloperational functions. These include high- /low-pressuresafety shut-in valves, excess-flow valves, pressure andtemperature switches, and pump-off controls.Safety Shut-In ValvesHigh- /low-pressure safety shut-in valves and excess-flow valves are both fluid-controlled valves of the typethat is actuated by line fluid. This valve type wasdiscussed briefly in the section on automatic controlvalves. The use of an excess-flow valve or low-pressurecontrol with a safety shut-in valve primarily safeguardsagainst a flowline break and the resultant loss of oil andsurface property damage. High-pressure control with asafety shut-in valve guards against pressures in excess ofthe allowable limit building up in the flowline. Either ofthese two kinds of valves normally would be installed atthe wellhead.Pressure SwitchesAnother means of protecting against excessive flowlinepressures and/or flowline breaks is the use of a pressureswitch and an automatic control valve. Pressure switchesare available that produce either an electric or pneumaticsignal, as required, to actuate the automatic controlvalve. On rod-pumped wells, the control signal from thepressure switch also must shut down the pumpingunit-i.e., turn off the switch on an electric motor orground the magneto on an internal-combustion engine.On rod-pumped wells that have no tendency to heador flow when the pumping unit is shut down, theautomatic control valve may be omitted.A pressure switch in the sense it is used here con-sists primarily of a pressure-sensing element, limitpressure contact(s), and an electrical, mechanical, orpneumatic means to transmit the control signal to the ob-ject(s) controlled by the pressure switch. The pressure-sensing element is commonly a bourdon tube, thoughsome requirements could necessitate the use of ahelical-, spiral-, diaphragm-, piston-, or bellows-typepressure-sensing element. In electrical control systems,the displacement of the pressure-sensing element is madeto make or break an electrical switch, normally amercury or microswitch, when the line pressure reachesthe preset pressure limit(s). In pneumatic controlsystems, reaching the preset pressure limit(s) may ac-tuate a pneumatic transmitter, relay, or slide valve.Liquid-Level ControlsAnother automatic safety-control device, which also fre-quently performs an operational-control function, is aliquid-level controller. These devices commonly areused to control liquid levels in separators, heater-treaters, storage tanks, surge tanks, accumulator vessels,metering vessels, etc. They may be used (1) to controlhigh liquid levels to prevent running over a vessel, (2) tocontrol low liquid levels to maintain pump submergence,(3) to control intermediate operational levels to open andclose dump valves, to start and stop pumps, etc., or (4)to maintain the interface of two liquids at a given level.


5/17


There arc many types of liquid level controls. Some ofthe more common types of level control devices used inproduction equipment are float operated, pressureoperated, ground-level tank gauges, electric and/or elec-tronic, sonic, and vibration. A float-operated levelswitch generally consists of a spherical or cylindricalfloat attached to one end of a mechanical lever witheither an electrical switch or a pneumatic relay on theother end. The switch or relay is located in a separateportion of the device housing and is isolated from thefloat area with a pressure seal. The float is displaced bythe rise and/or fall of the liquid level being controlledand the motion is transmitted through the pressure seal toactivate the switch/relay. A pressure level control switchmay control liquid level on the basis of either differentialor static pressure. The differential type devices common-ly are used as a form of pilot operated dump valves onpressure vessels. The static pressure devices frequentlyare used for well shut-down service and level control intankS.

Ground level tank gauges consist of tape, tape drum,and a tank gauge float that are linked to cause the tape tobe spooled on and off the tape drum as the liquid levelrises and falls within the tank. By extending the tapedrum shaft and using appropriate cams, gears, etc., elec-trical or pneumatic control systems may be activated tocontrol liquid levels in the tank. One type of sonic levelcontrol consists of a sound transmitter and receiver thatare suitably arranged for separation by the liquid beingcontrolled. The transmitter and receiver are driven withan electronic circuit that can measure the intensity of thesound reaching the receiver. The change in the receivedsound intensity between airigas and the liquid as theseparation material can be used to sense and control aliquid level. Ultrasonic level devices sense the reflectionof a sound wave from the gas/liquid interface and use thedelay time between transmitting and receiving to deter-mine distance from sensor to liquid level.

Some liquid level devices induce vibration into adetecting element. The degree of vibration dampeningcaused by the medium surrounding the element can besensed to differentiate between gas and liquid materials.Electric and/or electronic level controls depend on thedifferent electrical properties (capacitance, conductance,etc.) of the liquid to be controlled and that of the relatedmedium (air, gas, and/or other liquid). An electronic cir-cuit is used to sense the change in electrical property asthe liquid level changes and thus controls the level asrequired.

Other types of level controls are available for specificinstallation needs. Level controllers should be selected toprovide the required function in the least complex andmost reliable form. It is advantageous to select equip-ment that has demonstrated satisfactory application ex-perience within the operating environment that is to becontrolled.Automatic Quantitative MeasurementGross volumes frequently must be adjusted by quan-titative measurements such as water content,temperature, pressure, and density before net volumes atstandard conditions can be determined. Several of thesequantitative pammeters are necessary for automation oflease operations.

Liquid MeasurementThere are three types of quantitative (volume) devicescommonly used for automatic liquid measurement on thelease: positive-volume meters, positive-displacementmeters, and inferential meters. Positive-volume metersare essentially extensions of tank measurement withautomatic filling and running functions. Positive-displacement meters trap a fixed volume of liquidwithin moving elements of the meter. Inferential metersmeasure liquid by detecting some property of the movinstream that is a basis for determining volume indirectly. Q

Positive-Volume Meters. Positive-volume metersoperate on a fill and dump cycle rather than beinga continuous operation. This type meter is essentially theautomatic gauging of a tank by using level controls tomove a fixed volume through the tank on each completecycle. The volume that is dumped or measured isrelated to the displacement volume in the meter betweenthe high fill point and the low dump point in themeter. Various types of level controls are used to controlthe fluid levels in the meter. Each complete fill anddump cycle is registered on a counter as a basis fortotal volume determination. Since the positive-volumemeter is cyclic with a separate fill and dumpperiod, allowance for handling produced volumes whilethe meter is in the dump cycle must be made. Con-tinuous operation is possible by having a pair of metersthat are sequenced to have alternating cycles. This essen-tially requires duplication of facilities and some in-creased complexity in the controls. A more common ar-rangement is to provide surge volume capacity upstreamof a single meter.

Volume-type dump tanks or meters have been built ina variety of shapes and volumes. Capacities per dumphave ranged from less than V bbl to several hundred bar-rels. The metering chamber may be in a stand-alonevessel or it may be an integral portion of a vessel such asa separator or heater treater. The positive-volume meteris not as compatible with qualitative measurement as thepositive-displacement and inferential meters since thevolume measurement cannot be separated easily intosmaller increments to drive sampling and otherqualitative measurement devices.Positive-Displacement Meters. A positive-displacement meter, regardless of specific type, consistsof two primary elements: a stationary case and a mobileelement, which acts to isolate within the case fixedvolume of fluid each cycle of operation. The mobile ele-ment may be a rotor with sliding vanes, rotatable vanes,or rotatable buckets. It may be two rotors that meshsomewhat similarly to two helical or cycloidal gears asthey rotate. The mobile element may be a disk thatnutates about a camlike follower in three-dimensionalmotion or a cylinder that oscillates about a cam followerin two-dimensional motion. Or, finally, the mobile ele-ment could be a conventional piston such as that found ina power pump. Most positive-displacement meters are,in fact, closely akin to positive-displacement pumps.

Positive-displacement meters rapidly became the stan-dard for ACT use. The positive-displacement meter pro-vided a less costly and less complex facility than the


6/17


positive-volume meter. In addition, the positive-displacement meter provides a means to drive samplersand/or net oil computers with signals on a small incre-ment of volume that is more compatible with automaticqualitative measurement requirements.

Care must be exercised in the installation design for apositive-displacement meter. All free gas must beremoved upstream to avoid spinning the meter, whichwould cause erroneous readings and, possibly, damageto the meter. For greatest accuracy, a constant flow rateshould be maintained through the meter and at a rate atleast 15% or greater of the rated capacity of the meter.Standards for calibration frequency, methods, etc., areset forth in API Std. 1101. Inferential Meters. The turbine meter and the orificemeter are commonly used inferential meters for liquidmeasurement. These meters indirectly determine volumeby sensing some property of the moving stream that canbe related to volume. For example, the rotation of theturbine blades in the turbine meter and the differentialpressure developed across the orifice plate in an orificemeter can be used as basis of volume determination.Turbine meters became important in volume measure-ment when electronics were accepted as an element of ameasuring device. The rotation of the turbine blades canbe sensed electronically without need for any mechanicalconnection to the turbine rotor. This provides a simplearrangement that is inherently reliable and particularlysuitable for high-pressure service. Thus, turbine metersinitially were applied to measure injection watervolumes. However, high-viscosity fluids drasticallyreduce the range of turbine meters.

Turbine meters are being used for well testing and wet-oil lease production measurements when combined withnet-oil computers. These meters tend to be more tolerantof short over-range periods and sandy fluid than arepositive volume meters. Turbine meters also arc beingused for ACT, particularly for high-volume and/or high-pressure service.Orifice meters are used more commonly for gasmeasurement but they have some applications in liquidmeasurement. Compressible liquids that require pressurecorrection for volume determination frequently aremeasured with orifice meters.Gas MeasurementThe primary device for lease gas volume measurementhas been and continues to be the orifice meter, which in-itially measured gas volume by using a mercurymanometer before development of the bellows-type chartrecorder. Orifice meters have these advantages: (1) nomoving parts in the gas stream, (2) the ability to handlewide range of flow rates (long term) by means of platesize changes, (3) reliable and nonexternal poweredrecorder, and (4) a reliable sensor (bellows). The chartrecorder is not compatible with automatic data acquisi-tion; other types of gas measurement devices are usedwith SCADA. These gas measurement devices includepositive-displacement meters, gas-flow computers, tur-bine meters, and vortex meters. Positive-Displacement MetersThe installation of SCADA systems with automatic well

testing generated a need for gas measurement over awide flow range with direct readout capability. Therotary positive-displacement gas meter is similar tothe liquid lobed-impeller or gear-type meter. Therotary gas meter has the capability to measure gas ac-curately over a range of about 15 to 1 compared withabout 4 to 1 for an orifice meter with a fixed orifice platesize. The rotary meter can be equipped with mechanicalcompensation on indicated volume for static pressureand flowing temperature corrections. The rotary meterneeds to be protected from over-range and liquid ac-cumulation within the measuring elements. These metersare usually applied to low-pressure gas measurementservice.Gas-Flow ComputersGas-flow computers were developed to use existingorifice-meter runs and to provide a direct readout of gasvolume that was compatible with SCADA. Thesedevices use static and differential pressure electricaltransducers on a standard orifice meter as a basis for gasmeasurement. The computer integrates the signals fromthe transducers and combines with fixed data on meterrun size, plate size, etc. to develop a gas volume. Thevolume readout will be in the form of a switch closurethat will register on an internal counter and provide inputto electronic counter in an RTU.Some gas-flow computers can accept a temperaturetransducer input to measure temperature of flowing gasstream for improved accuracy of volume measurement.Computers also may have capability to use two differen-tial pressure transducers (e.g., 0 to 20 and 0 to 200 in.)and to select input from the unit providing most accurateinstantaneous reading for integration. Early gas-flowcomputers were analog devices. Many current designsare digital units based on a microcomputer. The flowcomputer integration function also is being done by themicrocomputer-based RTU. All designs have integrationaccuracy compatible with the basic measurementcapability of the orifice meter,Gas Turbine MetersGas turbine meters also are used to obtain direct readouton gas volume measurement that is compatible withSCADA. Turbine meters can measure gas volumes ac-curately over a range of about 20 to 1 at mediumpressures. Rangeability tends to increase with increasingstatic pressure. These meters are usually somewhat lesssubject to over-range damage than the positive-displacement meter if over-range period is of short dura-tion. Meter proving and checking may require installa-tion of prover loop for a master meter. Gas turbinemeters can be equipped with temperature and staticpressure volume compensation capability. Many gas (orliquid) turbine meters are destroyed when they are over-ranged while pressuring up the system.Vortex MeterVortex meters have a bluff body that spans the flowarea through the meter and causes vortices to form in theflowing medium. There vortices are shed off the bluffbody at a frequency that is proportional to the volumetricflow rate through the meter. The vortices can be


7/17


counted with suitable pressure or other flow patternsensors, which are connected to an electronic componentfor flow accumulation. Vortex meters have rangeabilitycharacteristics similar to positive displacement and tur-bine meters without the moving parts of these devices.

Temperature MeasurementTypes of temperature-sensing devices commonly used inoil and gas production include filled-thermal, resistancethermal detection, thermocouple, thermister, and solid-state. The filled-thermal device operates on the basis ofthe principle that a fluid expands or contracts withchanges in temperature. The device consists of atemperature-sensitive bulb connected by capillary tubingto an expansible element that is sensitive to pressurechange. The bulb may be filled with a liquid, a liquidand its vapors, or a gas. The expansible element may bea diaphragm, a bellows, or a bourdon tube.The$lled-thermal device has sufficient output force tobe used directly for temperature compensation onpositive-displacement meters used for LACT. Thebellows assembly is connected to an infinitely variabletransmission, which corrects the meters volume outputto a base temperature of 60F.

A resistance thermal detector (RTD) works on theprinciple that a change in resistance of a wine is relateddirectly to a change in temperature of the wire. Thedevice consists of a resistance element (sensing element)and a related electrical circuit, which uses the changingresistance of the element to control an output signal. Theoutput signal can drive recorders and controllers.A thermocouple works on the principle that heat ap-plied to one end of two strips of metal of different com-position, which are bonded at either end, develops anelectromotive force (EMF) that is proportional to thetemperature. Thermocouples may be of the wire type, inwhich both elements are in wire form, or of the Pyodtype, in which one element is a closed tube and the othera wire welded to the inside bottom of the tube. The ther-mocouple is connected to an electrical circuit, whichsenses the generated EMF and develops an output signalthat can drive recorders and controllers. Thermocoupledevices are used in applications where temperatures mayexceed 1,OflOF.nermister and solid-state devices exhibit a resistancechange with temperature change. Both these devices re-spond rapidly to a temperature change because of thesmall mass of the sensing element. Electrical circuits arerequired to convert the sensed resistance change intoan output signal that is proportional to temperature.Automatic SamplerAn automatic sampler is a device that removes arepresentative volume of fluid from a moving stream andretains it in a container for later processing and analysis.Factors that improve probability of obtaining a represen-tative sample include the following: (1) sampling probeshould be located in a vertical downrun of pipe at thecenter of the pipe and with probe opening facingupstream; (2) the total flowstream should be in turbulentflow; (3) sample size and sampling interval should besuch that the sample is proportional to the total streamflow; (4) sample metering chamber should be closelycoupled to sampler probe and located below the center

line of sample probe; and (5) samples should be collected and stored at pressures exceeding the vaporpressure of the sample liquid to prevent evaporation anddeterioration during storage.Samplers also are used with positive-volume andpositive-displacement meters in well testing and wet-oil(not pipeline quality) lease volume measurements.Representative sampling becomes more difficult with in-creasing water content in the oil stream. For improvedaccuracy, fluid mixtures that may have both free waterand oil emulsion (oil-external phase) components shouldbe processed through a three-phase separator before theremaining oil emulsion stream is sampled.The capacitance probe and net-oil computer have notreplaced the automatic sampler on most LACT installa-tions because (1) crude oil value frequently is based ongravity (determined on sample volume), (2) the gross-oilvolume available directly from LACT counters issatisfactory for daily operating needs, and (3) the poten-tial operating cost reduction by eliminating sampler useis not significant. Most major purchasers will have arecommended (or required) design for automatic samplerinstallation.BS&W MonitorPipelines specify the maximum BS&W content that acrude oil may contain to be acceptable for transfer. Thedevelopment of LACT equipment required a means tomonitor the quality of crude oil as it was being measuredand transferred automatically to a pipeline. The com-monly accepted device for this function is a capacitanceprobe BS&W monitor. The dielectric constants of crudeoil and water are about 2 and 80, respectively. TheBS&W monitor uses a concentric probe, which sensesthe apparent dielectric constant of a fluid stream bymeasuring its capacitance between the probe electrodes.

The capacitance probe generally is installed in a ver-tical riser on the premise that a more uniform mixing ofstream components will result and thus, that a more ac-curate sensing of water content is ensured. Temperaturecompensation is required since dielectric constants of oiland water vary with temperature. The BS&W monitorsused with LACT generally have a 0 to 3 % BS&W range.The monitors have a variable set-point that is used todivert the oil stream back through the treating facilitieswhen the selected BS&W content is reached and/or ex-ceeded. In this application, a BS&W monitor controlsthe crude oil stream being transferred to the pipeline, butit does not determine the BS&W content as basis forgross volume adjustment.Net-Oil ComputerThe application of SCADA systems to production opera-tions increased the need to read directly the net-oil con-tent of an emulsion stream for well testing and lease oilproduction measurements. The basic principle of thecapacitance probe used in BS&W monitors was extendedto oil emulsions of higher water content by proberedesign.

The capacitance probe, with modification to give alinear output, provides a technique to obtain instan-taneous value of water content in an oil emulsion stream.By combining the probe output with volume output froma positive-displacement or turbine meter, the net-oil and


8/17


water volumes in an emulsion stream can be determined.The device that combines the capacitance probe andmeter volume information to obtain net-oil and watervolumes is designated as a net-oil computer.The net-oil computer can determine the oil/water con-tent of an emulsion stream with reasonable accuracy (Ito 2% in oil measurement to about 35% water). Thecapacitance probe will continue to indicate water contentabove this value (if in an emulsion form), but thedecreasing oil percentage of the total stream causes in-creased error in the measured oil fraction. A limitation ofthe capacitance probe is that any free water movingacross a probe with oil emulsion will distort the indicatedwater content and cause substantial errors. Applicationswith water cuts above 35% can be measured by usingthree-phase separators (for well testing and/or lease oilproduction). Treating chemicals can be used with three-phase separators, if necessary, to keep water content inthe emulsion to 35% or less. With these procedures, welltesting and lease oil production can be processed withtotal water production of more than 99 %Supervisory Control and Data Acquisition(SCADA) SystemsSCADA systems applied to oil and gas producing opera-tions vary in function and overall capability. Somesystems am oriented primarily to local operating person-nel needs and may only monitor/control a few wells in asingle field. Other systems are applied to multiple fieldsthat have several thousand total wells. Even with thewide variations, SCADA systems consist of the follow-ing basic elements: (1) supervisory control/data acquisi-tion equipment, (2) field instrumentation and cablingsystems, (3) communication facilities, and (4) digitalcomputer systems.SCADA EquipmentThis equipment functions to interconnect digital com-puter systems and instrumentation and control devicesthat are related to the oil and gas producing process. Theequipment consists of a communication adapter andRTUs. A communication adapter is attached directly tothe digital computer by a high-speed data link and at-tached indirectly to RTUs by communication circuits.The communication adapter serves as a data concentratorfor the digital computer, which can drive several com-munication circuits simultaneously. A number of RTUsgenerally share a common communication circuit.The communication adapter and the RTUs are de-signed to use a specific message protocol or structure forthe transmission of information. This message structuregenerally will contain the RTU address, function beingrequested, function modifiers, and supplemental infor-mation used for checking validity of message transfer. Aprimary feature shared by the communication adapterand the RTUs is the checking for valid messagetransmission between the devices. Manufacturers usedifferent techniques to ensure receipt of valid messagesand most of these have a high probability of detecting in-valid transmissions. Earlier communication adapterswere designed with hard-wire logic and were separatedevices. Many of the current designs are microcomputer-based units that may be an integral part of the digitalcomputer rather than a separate unit. These units fre-

quently can handle multimessage protocols to allowmote flexibility in attached devices.RTUs are electronic devices that connect the SCADAsystem directly to the oil and gas production facilities

that are being automated. An RTU has the capability tostore information from several input points and totransmit this information in a serial mode over a singlecommunication circuit to a digital computer on demand.The RTU also may receive control information from thecomputer that it routes to a selected control point. TheRTU generally is located within a few thousand feet ofits connected instrumentation and control equipment butmay be up to several hundred miles from the computerlocation.

RTUs commonly sense input information related tostatus/alarm (on-off, etc.), volume accumulation (oil andgas meter counts), and instantaneous analog values(temperature, pressure, flow rate, etc.). The RTU canprovide control output in the form of relay activate (on-off, start-stop) and a set-point value. The set-point iscommonly a 4 to 20 mA or 10 to 50 mA signal that iscompatible with control devices. Although these basicRTU capabilities may appear limited, most data inputand control output functions related to oil and gas pro-duction can be implemented directly. Some specificfunctions may require supplemental logic in local controlpanels for implementation.

The basic RTU functions described previously arecommon to units designed with hard-wired logic.Many of the current and most future RTU designs will bemicrocomputer-based. The microcomputer allowssubstantial increases in RTU functions with relativelysmall incremental hardware expansion and cost. For ex-ample, RTUs are being used to replace stand-alone gas-flow computers simply by adding to the microcomputerprogram logic that integrates static pressure, differentialpressure, and temperature transducer data from an orificemeter. The microcomputer in the RTU can handle allbasic RTU functions and process gas-volume accumula-tion for 30 to 50 m runs without timing constraints. Withcontinuing developments in electronic technology andimproving program support, the outlook is for significantexpansion in RTU Capability.

Initial RTU designs that incorporated microcomputerstended simply to implement hard-wired logic in themicrocomputer. In addition, microcomputers used withRTUs generally did not have any internal error checkingsuch as parity on memory, data bus, and address bustransfers. These conditions resulted in microcomputer-based RTUs that were difficult to trouble-shoot whenmalfunctions were experienced. Self-diagnosticcapabilities should be the first functional extension ofmicrocomputer-based RTUs. Good diagnostic featuresusually will require a combination of extended hardwareand software. Diagnostic checks should be run at startupand at frequent intervals during the regular operation ofthe RTU. RTUs should have a watch-dog timer thatwill attempt to restart the microcomputer if it stalls as aresult of hardware and/or software malfunction. Therestart feature also should provide a means to documentits use.

The RTU as an electronic device has two primary en-vironmental factors that adversely affect operationalreliability. These factors are heat and electrical tran-


9/17


sients. All solid-state electronic components sufferdecreased life with increasing operating temperatures.Many users of RTUs routinely have placed these unitsin air-conditioned buildings to decrease the mean timebetween failures. More recent introduction of low-powerelectronic components such as complementary metal-oxide silicon (CMOS) may minimize the need to providecooling below normal ambient temperatures.Solid-state electronic components are subject todamage by extremely short-duration (microseconds)higher voltage electrical transients (e.g., noise, spikes).These transients may enter an RTU by means of primarypower or by the many signal loops connecting the RTUto the instruments and control devices associated withthe production process. RTUs frequently are providedbattery backup power to allow for continued operationwith primary power outages. Common procedure is tooperate the RTU continuously on battery power withprimary power driving a battery charger. This arrange-ment provides relatively good isolation for the RTUfrom power line transients.All RTU input/output connections to the field cablesystem also must be protected from voltage transients.Status/alarm and accumulator input points frequently useoptical isolation between field cables and internal cir-cuitry. Each field signal loop also should use a gas tube(or similar device) to route induced voltage transients toearth ground. Lightning can induce sufficient energy toliterally evaporate protective components in extremecases but many of the otherwise damaging transients canbe suppressed with proper protection equipment. Elec-trical noise also may be caused by inductive devices suchas relay and solenoid valve coils. Inductive componentsshould have suppression diodes placed across the inputterminals to minimize electrical transient generation.Field Instrumentation and Cabling SystemsField instrumentation and control devices are selectedprimarily to meet needs of the oil and gas producingfacilities. If these devices are also to interface with theRTU of a SCADA system, some additional features maybe required. RTU status/alarm and accumulator inputsrequire an electrical switch closure to convey informa-tion to the RTU. For example, a separator high-levelfloat control may have a pneumatic switch for controlvalve activation. An electrical pressure switch may beadded to the pneumatic control line to allow the RTU tosense the position of the high-level control. In general,reliability of interface increases when the primary in-strumentation has a direct electrical connection com-pared to the example that required a pneumatic to elec-trical conversion.

Meters for liquid and gas measurement also need tohave an electrical switch activation to indicate some in-crement of volume accumulation. Liquid meters, for ex-ample, frequently will have an electrical switch closureat nominal 1-bbl volume increments. The switch closuremust be maintained for some minimum time increment(about 50 milliseconds) to ensure that electrical tmn-sients will not cause invalid volume counts. The RTUwill have a separate signal loop (wire pair) and internalelectronic counter associated with each meter beingmonitored.

Pressure, temperature, flow rate, position, and similar

operational parameters are sensed by the RTU as ananalog input value from electrical transducers. Nominalelectrical transducer output ranges of 1 to 5,4 to 20, and10 to 50 mA usually can be processed by the RTU. Acurrent output transducer is preferred since the signal isless susceptible to electrical transient distortion than avoltage output.Multiconductor cables are used to connect the RTU tothe instrumentation and control devices associated withthe production process. The signal cables consist of in-dividually insulated copper wires genemlly of 19 or 22gauge that commonly are used for commercial telephoneservice. The cables usually are buried to minimize prob-ability of mechanical damage and electrical noise intm-sion. Cables can be damaged when buried and repairsshould be made immediately to prevent further deteriora-tion. Cable lengths are controlled by cost relationshipsbetween installing more RTUs at separate locations andthe amount of cable required for interconnection. Mostcable systems will be limited by economics to a fewthousand feet.Radio communication links between RTUs and a cen-tral location within a field can reduce overall cablingcosts substantially. This technique can use a master radiostation in a polling mode to communicate with the in-dividual RTUs. Separate transmit and receive frequen-cies enhance the radio communication procedure. In thisarrangement, the master radio transmits an outboundmessage to all RTUs and the RTUs will decode the ad-dress portion of the message. The addressed RTU thenwill decode the function portion of the message and replyto the master radio by bringing up its transmit radio linkfor the period required by the return message. Themaster radio is linked to a regular four-wire communica-tion circuit for communication outside the field area.

The low-energy signals used in the cable system re-quire careful connection of wiring to instrumentation.Any damage to wiring insulation or collection ofmoisture at connection points may result in sufficientsignal leakage to cause invalid sensing of operational in-formation. Some installations are made with the signalloop power supply floating or not connected to earthground. Maintenance checks then can be made to deter-mine current leakage to the positive and negative ter-minals of the power supply from earth ground as ameasure of signal leakage. With selective isolation of thesignal loops, leakage problems usually can be identified.Common practice is to design alarm-signal loops to be innormal condition when the sensing device has a closedelectrical switch. This feature makes the alarm signalmore fail-safe in that any failure of the signal path willcause indication of an alarm condition also. Less criticalstatus loops frequently are open in the normal state tominimize total power needs.Communication FacilitiesSCADA systems require capable and reliable com-munication facilities to connect the communicationadapters on the digital computer system with the RTUsthat are located in fields being automated. Most SCADAsystems use dedicated or nonswitched communicationcircuits that have a four-wire configuration. The four-wire designation provides two independent communica-tion paths that will support simultaneous data transfer in


10/17

16-10

CHRISTMASTREE

-I I-a EXCESS FLOW

SHUT-INCONTROL VALVE

c-- I

-1 -c%+I

b---fb HI-LOW PRESSURE

SHUT-INCONTROL VALVE

-,z,Ec AUTOMATIC CONTROLVALVE WITHPRESSURE SWITCH

Fig. 16.1-Automatic wellhead safety controls.

two directions (full duplex). Data transmission inSCADA generally is operated in one direction at a time(half duplex) with transmit over one path and receiveover the other path but at different time periods. Data aretransmitted over the communication circuits with the aidof modems. Modems are electronic devices that convertvoltage or current level from the communication adapterinto analog signals that can be transmitted over the com-munication circuit. A similar modem at the RTUreceives the analog signals and converts them intovoltage or current levels that are compatible with theelectronic circuitry in the RTU. A data transmissionfrom an RTU to the communication adapter operates inthe reverse cycle.

SCADA can use commercially available voice-grade(telephone) communication circuits. Communicationspeeds of 1,200 bits/see can be used with long termreliability over these circuits by using conventionalmodem equipment. Higher communication rates can beobtained by using more complex modems and higherquality communication circuits if the application beingmonitored requires more critical timing responses. In-creased communication rates tend to require moremaintenance time or tine tuning of communicationequipment to achieve a constant reliability ofperformance.SCADA communication circuits may require multipleownership and maintenance responsibility links to reachparticular locations. Circuits with divided maintenanceresponsibility tend to have more reliability problems. Inthese cases, adequate test facilities at the computer sitecan aid in defining the particular link causing problems.The four-wire circuit is compatible with testing since itcan be turned around to receive a transmitted test signalfrom the computer site. If remotely operated turn-around

PETROLEUM ENGINEERING HANDBOOK

devices are located at each link interconnection, the cir-cuit can be tested and problems isolated to the responsi-ble maintenance group.Digital Computer SystemsSCADA became possible with the development ofprocess-control-type computer systems in the late1950s. The process control computer was a specialhardware implementation that provided for direct con-nection to plant instrumentation and control equipment.This same hardware also provided a means to intercon-nect with the communication adapter of a SCADAsystem. The SCADA equipment then allowed the proc-ess control computer to be connected indirectly to oil andgas facility instrumentation at remote locations.Process control computers had software operatingsystems with program execution control that was com-patible with SCADA needs. The operating systems weredesigned to recover automatically from minor programmalfunctions to minimize computer operator needs in thecontinuously operating SCADA applications. Earlyprocess control computers had limited memory size thattended to require assembler language routines for somefunctions. Frequently, bulk storage (disk or drum)devices also were limited in capacity. Most earlierSCADA systems were based on a central computersystem concept.

Currently, SCADA systems have extremely capablecomputer systems available for system implementation.Process-control-type computers are available with fewpractical limitations on memory size, speed of execu-tion, and random access storage capacity. In addition,many of the general-purpose-type computers (businessand scientific applications) now have extensive com-munication capabilities and operating system featuresthat are compatible with most SCADA requirements.Distributed computing, which uses multiple computersat remote sites, became practical in the mid- to late1970s as manufacturers developed capable networksoftware. The network software provided capability todevelop application programs at central locations anddownload through communication links into computersystems at field locations. Increased use of distributedcomputers in SCADA is anticipated.

Basic application software is generally available frommanufacturers of the SCADA systems. The rapidlychanging technology, however, has made it difficult forsuppliers to develop general purpose application soft-ware that is transportable to new computer systems.Most larger SCADA systems have tended to bespecialized software applications that have continuingprogram development to meet the changing operationalneeds. Application software for both small and largeSCADA systems should have flexibility to allowchanges/additions to the implemented functions.Typical Automatic-Control InstallationsAutomatic Well ControlAutomatic Wellhead Controls. Wells may be con-trolled at the wellhead or at the well manifold. Frequent-ly, it is necessary or desirable to control them at bothplaces. Fig. 16.1 depicts three different types of


11/17


iTUBING PRESSURE GAUGE TIME CYCLE

CASING PRESSURE GA UGE CONTROLLERt-GAS METER 7

Fig. 16.2-Automatic controls for rod-pumped wells. Fig. 16.3-Typical automatic control of gas-lift well.

places. Fig. 16.1 depicts three different types ofautomatic control valves that could be installed at thewellhead immediately adjacent to the tubing wing valve.Although Fig. 16.1 pictures a naturally flowing well, thesame types of automatic controls would be applicable forartificially lifted wells of all types, if required. Theexcess-flow valve shown in Fig. 16. la generally is usedonly to protect against flowline breaks when the wellsate choked and controlled at the well manifold. Thehigh/low pressure shut-in valve in Fig. 16.lb may beused whether the well is choked at the wellhead or at thewell manifold. It is protection against both flowlinebreaks and chokes cutting out or plugging. The controlvalve and separate pressure-sensing element shown inFig. 16.1~ perform exactly the same functions as thehigh/low pressure shut-in valve.Rod-Pumped-Well Control. The typical automatic-control system for a rod-pumped well is shown in Fig.16.2. The high-low pressure safety shut-in valve isnecessary only when the well has a tendency to flownatumlly when the pumping unit is shut down. Theexcess-flow valve, again, is protection against flow-linebreaks. Some operators use them; others do not. Theyam not always effective unless line pressures are highenough, and the size of the break large enough, to createa substantial pressure drop. The pressure switch is themost common automatic safety control used with rod-pumped wells, particularly where the wells are remotelycontrolled. Regardless of which of these three types ofcontrols are used, when the control pressure is reached,that automatic control must furnish a signal to shut downthe pumping unit. This is accomplished by grounding themagneto of a gas engine or shutting off an electric motor.A pump-off control, if used, would be installed in theflow line immediately adjacent to the pumping tee.Gas-Lift-Well Control. Fig. 16.3 shows a typical ar-rangement of controls on the gas-supply line to a wellthat is produced by an intermitter-type gas-lift installa-tion. The time-cycle controller shown on the right isan automatic production programmer. It automaticallyopens and closes the diaphragm control valve, to whichit is connected by instrument lines, according to theschedule manually created in the programmer. Theflow-control valve is a manually actuated valve usedto control the mte at which gas is admitted to a well.Automatic-control valves on the flow line, if required,would be one of the types shown in Fig. 16.1.Hydraulic-Pumped-Well Control. Fig. 16.4 depictsthe typical automatic controls for a hydraulic pumping

POWER OIL TANK mCONTROL

PANEL

OW PRESSURET-DOWN SWITCH

MANIFOLD TO SUMP

Fig. 16.4-Typical hydraulic-pumping-system control.

system. A high/low pressure switch protects the triplexpump and its prime mover against overloading from ab-normally low suction pressures and/or high dischargepressures. In either case, the pressure switch would shutdown the prime mover. Automatic Control Valve V-l inthe manifold bypass is generally a diaphragm-typeregulator valve which is normally closed. It would openat a pressure slightly under the setting of the high/lowpressure shutdown switch and divert sufficient power oilback to the power-oil tank to maintain system pressure ata safe level. Automatic Control Valves V-2 and V-3 arein the power-oil lines to individual wells. They would beclosed automatically in the event the pressure switch shutdown the triplex and prime mover. With an appropriateprogrammer, they could also be used to produce in-dividual wells selectively on an intermittent schedule.Automatic Well Manifolds. In Figs. 16.5 and 16.6 areshown two typical automatic well manifolds designed forcontrolling the wells at the well manifold rather than atthe wellhead. The single-wing well manifold shown inFig. 16.5 has a maximum of flexibility to meet anysystem of stage separation and/or treating that mightarise. It has another advantage in that it could be in-stalled initially on new leases as they are developedwithout the automatic-control valve and still add thevalve later with a minimum of expense. The dual-wingwell manifold shown in Fig. 16.6 is limited to situationswhere all production in a well manifold is processedthrough a single vessel or a common sequence ofvessels. Both these manifold designs would require flowlines capable of withstanding full wellhead pressure and


12/17


PRESSURETE (fti~~~,

F;;;a TESd d iPRODUCTION IONE REQD FOR EACHSEPARATION AND/ORTREATING VESSEL

Fig. 16.5-Typical single-wing automatic well manifold.

PRESSURE GAUGE 3-WAY 3-POSITIONCONTROLVALVE

PRODUCTION

Fig. 16.6-Typical dual-wing automatic well manifold.

would choke and control the wells at the manifold. Allmanifold designs should provide for monitoring valveleakage.Some operators prefer to use three-way, two-position

control valves in the well manifold and to control thewells at the wellhead. Automatic-control valves of thetypes shown in Fig. 16.1 then would be installed at thewellhead in addition to the control valves in the wellmanifold. Other operators would prefer to use a two-waycontrol valve in each riser to each pressure vessel servedby the well manifold.Automatic Well TestingA typical automatic well-testing system is illustrated inFig. 16.7. The sequence control logic for conducting thetest and for calculating test results may be self-containedin the control panel or it may originate in a SCADAsystem that is remote fmm the site. In either case, athree-way control valve in the test/production manifoldis activated to divert the selected well to the test vesselwhen the related signals are received from the controlpanel. The test vessel may be either a separator or aheater treater. The liquid-metering elements commonlywill be either positive-displacement or turbine meters.The oil meter will be combined with a capacitance probeand net-oil computer to provide measurement of net-oiland emulsion-water volumes. The free water volumewill be measured by a separate water meter. Well-testcontrol logic will combine the emulsion-water and freewater measurements to obtain total test water volume.

Fig. 16.7-Typical automatic well-testing system

The test-gas volume can be determined with apositive-displacement meter, turbine meter, or gas-flowcomputer. The three-way control valves should beequipped with position switches that can be used to con-firm that only the selected well is in the test vessel. Thetest vessel normally will have a high-level float switchthat will automatically divert the on-test well back toproduction status when a high liquid level is detected.The same switch can be used to notify the SCADAsystem of the test vessel malfunction.

Some operators have extended the use of measurementequipment, as described for well testing, to total leaseproduction. For example, with more logic in the controlpanel and manifolding of dump lines from test and pro-duction vessels, the oil-measurement equipment can betime-shared to measure both test and production oilvolumes. The control panel determines (one at a time)which vessel dumps through the oil-measurement equip-ment and mutes the volume counts to the related counter.Separate gas-measurement facilities are required for testand production volume determination.The time-sharing concept has been extended further incettain instances. For example, a number of separateleases, each having only a few wells, were arranged tohave all production separators located at a common site.The oil production from each separate lease productionseparator was determined by time-sharing a single oil-measurement facility. In addition, a single test separatorwas used to test all wells at the site. The site controlpanel muted test volume counts to the test counters andto the appropriate lease counters related to the well ontest.LACTThe first efforts to design an acceptable LACT installa-tion tried to incorporate the existing equipment on thelease and familiar operating principles insofar as possi-ble. Thus, understandably, the first officially acceptedLACT system was a weir-tank system installed by GulfOil Corp. on its Ames Lease in the Bloomer field, KS, in1955. Shell Oil Co. also pioneered in the development ofthe weir-tank-type LACT system on its leases in theAntelope and Wasson fields in Texas, beginning unof-ficial experiments as early as 1948. The next significantdevelopment in LACT system design was the meter-tank-type system.


13/17


Fig. l&8-Typical weir-tank-type automatic-custody-transfersystem.

The meter-tank-type system is closely akin t6 the weir-tank system in many respects, but perhaps it deservesconsideration as a separate category because thesevessels were designed solely as measuring vessels. Thegreat similarity between measurement with the larger-sized positive-volume dump meters and conventionallease tanks assured their early acceptance. Officially ac-cepted LACT installations of this type of the PhillipsPetroleum Co. and Amoco in Oklahoma and Texasfollowed closely on the heels of the Gulf weir-tank-typesystem in Kansas. The third type of LACT design whichhas gained wide acceptance to date is the positive-displacement-meter-type system. Exxon Co. U.S.A.was perhaps the strongest early proponent of this type ofsystem, and they performed much development work ontheir leases in south Texas.The positive-displacement-meter-type equipmentrapidly became the LACT standard primarily because ofsubstantial cost and operating reliability advantages overthe other two units. The positive-displacement-meterLACT assembly was skid-mounted for relatively simpleinstallation within existing production facilities. Figs.16.8 and 16.9 are included for reference to the historicaldevelopment of LACT as an important element of leaseautomation.

EMERGENCYHIGH LEVELFLOAT SW ITCH

t TRANSFER PUMP&- L-^. r-GAS ELIMINATR

RETURNLINE DIVERTING VALVE

Fig. 16.9-Typical automatic-custody-transfer system usingmetering dump tanks.

Positive-Displacement-Meter LACT System. Fig.16.10 shows a positive-displacement-meter LACT in-stallation. Option B indicates a two-meter arrangementthat was recommended strongly in earlier installationsfor improved measurement reliability. Operational ex-perience found the single meter arrangement (Option A)to have satisfactory reliability and most LACTs were in-stalled with the single meter. Some LACTs have twometers but most of these operate the second meter in astand-by mode rather than simultaneous measurementthrough both meters. Most major purchasers haverecommended (or required) certain designs for LACTinstallations.

The routine operation of crude-oil transfer is con-trolled by the normal operating high-level float switchwith an override to shut down on emergency with thelow-level float switch. The BS&W monitor will divertfluid stream to the treating facility on detection of highBS&W content. The strainer is used to protect the meterfrom particles that could damage the meter. The meter istemperature-compensated to indicate oil volume at 60Fstandard condition. Daily and monthly volume limitswitches prevent overrun of lease on either daily ormonthly allowable volumes. A calibration loop islocated downstream of the meters to allow convenient

OPTION ASINGLE PD METER SYSTEM

SAMPLER CALIBRATION

,TICKET PRINTER 8 COUNTERMlLY VOLUME LIMIT SWITCH

MONTHLY VOLUME LIMIT SWITCH

OPTION 8TWO P 0 METERS IN SERIES

Fig. l&10-Typical automatic-custody-transfer systems using positive-displacement meters.


14/17

PETROLEUM ENGINEERING HANDBOOK

Fig. 16.11-Automatic backwash of rapid sand nlters in water-treatment plant.

Fig. 16.12-Typical method of controlling injection-pumpingrate.

meter-proving or calibration with a master meter. Asampler is used to collect sample volumes for basis ofBS&W correction and oil gravity determination. Theback-pressure valve is used to minimize gas break-out orflashing in the crude stream prior to being metered. Acheck valve (not shown) should be located downstreamfrom the back-pressure valve (or combined with it). APIStandards 1101, 2502,253 1,2542,2544, and 2546, andsupplements thereto provide recognized industry codesfor liquid petroleum measurement. 2Automatic Lease Process ControlThere are many normal lease-operating processes thatmay be automated or that already are automated com-pletely and not recognized as such by the average in-dividual. Space limitations will permit only a brief lookat a few of these control systems to show what can beand is being done.Automatic Water-Treating Plant. Fig. 16.11 depicts arather elaborate automatic backwash system for rapidsand filters in water-treating plants. Normal flow is fromthe precipitator and oil remover through the sand filtersinto the accumulator. When the differential pressureacross the bank of filters reaches a predetermined value,the backwash cycle is initiated automatically. Valves

Fig. l&13-Automatic control of water-supply wells.

P-3, F-l, F-3, F-4, and A-l are closed; Valve A-2 isopened; and the backwash pump is started. After a slightdelay, Valves F-l and B-l are opened and Filter 1 isbackwashed into the backwash-settling tank for apredetermined, but adjustable, time. At the end of thistime, Valves B-l and A-2 are closed and Valves P-3 andF-5 arc opened. Normal flow is permitted through Filter1 into the backwash-settling tank for a short interval tosettle the filter bed. At the end of this interval, ValvesP-3 and F-5 are closed, Valves A-2 and F-4 are opened,and the backwash pump is started. After a slight delay,Valve F-3 opens and the same cycle is completed forFilter 2.Four float switches are required in the accumulator.Float Switch FS-1 is an emergency low-level floatswitch, which maintains a flooded pump suction andprevents gas from locking the pump since the ac-cumulator normally will be gas-blanketed. The volumebetween Float Switches FS-1 and FS-2 is large enough tobackwash the filters. Normally the fluid level is not per-mitted to fall below FS-2. If it should, the injectionpump is shut down if it has an electric prime mover, orValve A-6 is opened and the injection-pump output isbypassed back into the accumulator if the injection pumphas a gas-engine prime mover. When the fluid levelreaches Float Switch FS-3, the normal injection processis resumed. Float Switch FS-4 is an emergency high-level control that would cause Valve S-l to close to pre-vent running over the accumulator.

Valve A-3 is shown as a backpressure valve that is in-tended to keep a constant head on the backwash pump.The backwash pump probably will be a centrifugal pumpbecause of the high rate normally recommended forproper backwashing. If the injection process ceases forthe backwash cycle, then gas pressure applied to the topof the accumulator can be used in place of the backwashpump.After all the filters have been backwashed and settledinto the backwash-settling tank, the solids in the waterare permitted to settle out in the bottom of the tank. ThenValve B-2 is opened automatically to permit the solids tobe washed out to the pit. Then Valve B-2 closes, ValveB-3 opens, and the transfer pump returns the clear waterback through the system. Float switch FS-5 is for thepurpose of maintaining a flooded suction on the transferpump, and Float Switch FS-6 is to prevent running overthe vessel.The system just described represents a compositesituation. All automatic water-treating plants would nothave to be this elaborate. For example, a backwash-settling tank would be desirable only where it wasnecessary to keep the water going into the pit at aminimum. On the other hand, by a few small changes,


15/17

AUTOMATION OF LEASE EQUIPMENT 16-15D/P CELL B- REGENERATION FLOW

Fig. 16.14-Automatic cycling of desiccant beds in dry-desiccant-type gas dehydrators

the systems shown in Fig. 16.11 could also be altered toprovide for continuous through-put and injection whileone of the filters was being backwashed.Automatic Control of Injection-Pumping Rate. Fig.16.12 shows a typical method of controlling theinjection-pumping rate of a gas-engine-driven injectionpump. A float switch and pilot valve, acting through asnap-active pneumatic relay, controls the position of (1)a low-level bypass regulator, and (2) a bellows-operatedpneumatic motor that adjusts the engine throttle linkagerelative to the position of the float switch in the clean-water tank. In the event the fluid level drops too low inthe clean-water tank, the pilot valve sends a signal to alow-level shutdown switch, which grounds the magnetoon the engine and shuts it down.Automatic Control of Water-Supply Wells. Fig.16.13 shows a method of using float switches to controlthe operation of several water-supply wells to maintainan adequate supply of water in the raw-water tank. Asalways, high- and low-level emergency float switchesare provided. Additional float switches are included toprogram the addition and subtraction of supply wellsfeeding the system to assure an adequate volume ofwater is always in the raw-water tank. The well-on floatswitches would be actuated by a dropping fluid level,and the well-off float switches by a rising fluid level.At the water-supply wells, there are several ways tocontrol the pumping equipment. If the pump is drivenelectrically, it might be necessary to start up and shutdown the pump motor only as called for. If the water-supply well were artesian or had a tendency to flownaturally, it would be necessary, of course, to furnish ashut-in valve. If the pump is driven by a gas engine, itwould be necessary either to provide the engine with anelectric ignition system (battery or electric motor) and astartup sequence programmer or to install a divertingvalve and leave the engine running while diverting pro-duction back into a casing annulus.Automatic Control of Dry-Desiccant-Type GasDehydrators. As a final example, let us consider a lease

process that has been fully automatic since its inception,but one which is rarely thought of in terms of automa-tion: the automatic cycling of desiccant beds in dry-desiccant-type gas dehydrators. Fig. 16.14 is aschematic of a typical dry-desiccant-type dehydrator.The wet gas stream enters the horizontal separator and isdivided, with a part of the gas going to the regenerationstream and the remainder continuing in the main gasstream through the dehydrating tower. The proportioningof the flow between the two streams is controlled by theregeneration-rate controller. The rate of flow in theregeneration gas line is measured by a differential-pressure cell and transmitted to the regeneration-ratecontroller. The regeneration-rate controller, in turn, actsto position Automatic-Control Valve V-10 to maintainthe predetermined rate of flow of gas through theregeneration system.Automatic-Control Valve V-l 1 in the regeneration gasline is controlled by Controller B. Each time the con-troller rotates until the pin on the next trip clamp unlatch-es the pilot arm, Valve V-l 1 reverses its position. In theone position, it diverts gas through the heater to providehot gas for expelling moisture from the desiccant bed ofthe tower being regenerated. In the other position, itbypasses the heater and provides unheated gas to cool thedesiccant bed in the same tower before placing it back in-to service. By the time the controller rotates one moreposition, the regeneration valves on the towers will haveswitched so that the hot gas goes to the other tower.

Automatic-Control Valves V-l, V-2, V-3, and V-4control the flow of regeneration gas to dehydratingtowers, and Valves V-5, V-6, V-7, and V-g control theflow of the main gas stream. Valves V-l, V-3, V-6 andV-S are always in the opposite position from Valves V-2,V-4, V-5, and V-7. The main-stream valves and theregeneration-stream valves are manifolded in such amanner that only one tower at a time receives the main-stream gas and that tower is blocked off from theregeneration gas. The other tower receives the regenera-tion gas and is blocked off fmm the main-stream gas.The position of all these valves is controlled by Con-troller A acting through relay Valve V-9 and the pilot-


16/17


gas-control manifolds. Each time the controller rotatesuntil the pin on the next trip clamp unlatches the pilotarm, instrument gas will flow through the bleed orificeinstead of flowing to the Relay Valve V-9. Relay ValveV-9 then will reposition itself and allow instrument gasto flow to the other pilot-gas-control manifold and ventthe gas from the pilot-gas-control manifold supplied inits original position. This, in turn, will cause each ofthese control valves to reverse their positions, and thusthe flows of main and regeneration gas streams will alsoreverse. The length of each cycle is controlled by thespacing of the trip clamps on the controller.

References1. API Manual of Petroleum Measurement Standards, first edition,

API, Dallas (1981) Chaps. 1, 5, and 6.2. Specifications for Lease Automotive Custody Transfer (LACT)Equipment, second edition, API Spec. 1 lN, API, Dallas (March

1979).General ReferencesAnderson, G.L. and Reed, G.A.: Automation in the South Swan

Hills Unit, J. Cdn. Pet. Tech. (Oct.-Dec. 1981) 20, 105.Atkinson, M.H., and Newberg, A.H.: Cmde-oil Measurement 1s

Going Automatic. Oil and Gas J. (June 4, 1956) 102.Automatic Custody Transfer. Oi l and Ga s J. (July 11. 1956) 110.Automatic Sale Slated, Oil and Gas J. (Feb. 13, 1956) 90.AutomatIon, Per. W eek (Nov. 16, 1956) 71Barrett, M.L. Jr.: Meter Proving, Oil and Gas J. (Feb. 24, 1958)153 (March IO, 1958) 201 (March 24, 1958) 213 (April 21, 1958)

179 (May 5, 1958) 133.Bayless, C.R., and Mlkeska, F.J.: Automatic Control of Produc-tion, Oil and Gas J. (June 4, 1956) 78 (June 11, 1956) 129 (June

25, 1956) 110.Beach, F.W.: Fail-safe LACT Unit; Heres How It Works, World

Oi[ (Nov. 1957) 133.Brainerd, H.A. and Piros, J.J.: New Controller RecorderGravitometer, Oil and Gus J. (Dec. 2, 1957) 78.Case, R.C. and Fritsch, D.R.: Automation for the Ekofisk Offshore

Operation, paper presented at the 1976 Automation in Offshore OilField Operations Symposium, Bergen, Nonvay, June 14-17.DeVerter, P.L. and Scovill, W.E.: Pan I: Continuous Automatic

Sampling, Oil and Gas J. (April 2, 1956) 125. Warren, F.H.:Part 11: Continuous Automatic Sampling, Oil and Gas J. (April9, 1956) 124. Johnson, R.P.: Part III: Continuous AutomaticSampling, Oil and Gas J. (April 23, 1956) 119. Berglund, J.H.:Part IV: Continuous Automatic Sampling, Oil and Gas J. (April30, 1956) 210.

Doble, P.A.C.: Computer-Assisted Operations in a Northern NorthSea Operation, J. Pet. Tech. (April 1983) 701-08.

Dunham, C.L.: A Distributed Computer Network for Oilfield Com-puter Production Control, J. Pet. Tech. (Nov . 1977) 1417-26.EnDean, H.J.: Oil Field Watchman Checks BS&W Content, World

Oil (Nov. 1957) 151.First LACT System for Low Gravity, Viscous Crudes. Oil and Gas

J. (Dec. 2, 1957) 82.Foster, K.W.: Centmlia Water Flood: Preplanned Automation Pays

Off, Pet. Engr. (March 1958) B-l 16.

Hebard, G.G.: Automatic Lease Custody Transfer, Oil and Gas J.(Nov. 5, 1956) 86.

Hill, R.W.: Factory-built LACT Unit Is Gas Operated, Oiland GasJ. (May 6, 1957) 98.

Hubby, L.M.: Automatic Production Controls, Paper API 926-l-Cpresented at the 1956 Southern District Spring Meeting, Division ofProduction, San Antonio, Mar. 9.

LACT: A Youngster Now, Soon a Giant, Oil nnd Gas J. (Sept. 22,1958) 74.

LACT Is for Stripper Leases, Too, Oil and Gas J. (Dec. 15, 1958)70.Lease Automatic Custody Transfer, Bull. 2509A, API, Dallas

(Aug. 1956)Lease Is Fully Automatic, Pet. Week (Feb. 15, 1957) 11LeVelle, J.A.: New Production Programming System, Pet. Engr.

(April 1956) B-30.

Matheny, S.L. Jr.:Computer Production Control Expands, Oil andGus J. (March 23, 1981).McGhee, E.: Automatic Switching, 9-mile Radio Link, Oil and

Gus J. (Sept. 10, 1956) 114.McGhee, E.: How Cities Service 1s Using P.D. Meten for LACT,

Oiland Gas J. (Jan. 13, 1958) 74.McGhee, E.: How Shells Antelope LACT Works, Oil and Gas J.(June 3, 1957) 90.McGhee, E.: Its Automatic-Even to Sample Taking, Oil and Gas

J. (Feb. 13, 1956) 104.McGhee, E.: LACT-And Why We Like It, Oil and Gas J. (Jan.20, 1958) 131.McGhee, E. : When a Field Ourgrows Its Facilities, Oil and Gas J.(Apr. 15, 1957) 108.McKinley, D.C.: P.D. Meters Get the Job Done, Oil and Gas J.

(Oct. 1, 1956) 87.Meyers, D.C.: How Shell Designs an Automatic Lease, Oil andGus J. (Oct. 17, 1955) 111.Northern, T.P.: Automatic Lease Operations-Weeks Island Field,

J. Pet. Tech. (Jan. 1954) 21-24.Packard, H.C., Kelley, H.S., and Newburg, A.H.: Automatic

Custody Transfer of Crude Oil. Part I: General Considerations. Part11: From the Producers Viewpoint. Part III: From the PipelinersViewpoint, paper presented at the 1956 API Annual Meeting,Chicago, Nov. 13.

Patterson, D.R.: Production Automation, Pet.Engr. (Jan. 1959)B-31.Pope, S.H. and Stutz, R.M.: Lease Automatic Custody Transfer

Becomes a Reality, Oil and Gas J. (April 23, 1956) 96.Pneumatic LACT System, Pet. Engr. (Jan. 1957) B-104Principles of Lease Automation, Pet. Equipm ent (1957) 21Production Automation Forges Ahead, Pet. Wee& (July 26, 1957)21.Reese, C.P.: Automatic Control of the Wattenberg Gas

Field-Colorado, paper SPE 11111 presented at the 1982 SPE An-nual Technical Conference and Exhibition, New Orleans, Sept.26-29.


17/17


Resen, L.: Humble Tries LACT, Gives A Stamp of Approval. Oiiand Gas J. (March 4. 1957) 94.

Saye, H.A.: Automatic Well Testing, CM and Gus J. (Jan 6. 1958)102.

Scott. J.O.: Automation Pays Off in Big Mineral Producing Open-tions, Oil and Gus J. (Sept. 19, 1955) 114.

Scott, V.B.: Automatic Lease Operation. paper presented at WestTexas 011 Lifting Short Course, Texas Technological C., Lubbock.April 11-12, 1957.

Shatto, H.L.: Comments on the Status and Future of ACT from theProduction Viewpoint, paper presented at the 1958 ASMEMechanical Engineering Conference. Denver, Sept. 21-24

Shatto, H.L. and Hall, A.H.: Greater Rewards from LACT. Oiiand Gas J. (April 7. 1958) 133.

Stormont, D.H.: Tank Bottoms Are Recycled, Oil and Gas .I.(Nov. 12, 1956) 173.

Taylor, D-M.: New Auto-pneumatic Lease Programming System,Per. Engr. (Dec. 1956) B-28.

Todd, M.: Automation Applied to Flooding at Naval Reserve Pool,Oil and Gas J. (March 4, 1957) 84.

Travis, R.H.: Complete Automation in Water lnjcctwn. Pvt. Enx.(Feb. 1957) B-76.

Warren, F.H.: Automatic Gaging, Sampling. and Testing. 011 onclGas. J. (Nov. S, 1951) 271.

Wasicek, J.J., Kleppinger, K.B., and Grownburg, W W : An In-tegrated Design of Lease Programming and Custody TransferFacdities, paper 1125-G presented at the 33rd Annual Fall Meetingof the Society of Petroleum Engineers. AIME. in Houston, Tex.,Oct. 3-8. 1958.

Water-flood Project Is Fully Automatic, Oil and Gas J. (July 7,1958) 135.

Weaver, E.G. and Hildebrand, S.M.: Unique Automation SystemMonitors South Florida Production Operations, J. Per. Tech. (June1982) 1307-12.

Weight MeasuresFlow in New Unit, Oiland Gas J. (Sept. 8, 1958)66.

Whats Ahead for Oil in Automation, Oil and Gus J. (June 27.1955) 62.

Wrightsman, L.S.: Experience with P.D. Meters and Fixed-volumeT&measurement Procedures in LACT, paper presented at the1958 ASME Mechanical Engineering Conference. Denver, Sept.21-24.

Date post:	09-Apr-2018
Category:	Documents
Upload:	franklyn-frank
View:	213 times
Download:	0 times

Automation of Lease Equipment.

Documents