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PAPER 2005-006

Advances in Production AutomationB.Y.P. FUNG

Land Petroleum International Inc.

K.T. O’BRIENPrologic Controls Ltd.

This paper is to be presented at the Petroleum Society’s 6th Canadian International Petroleum Conference (56th Annual TechnicalMeeting), Calgary, Alberta, Canada, June 7 – 9, 2005. Discussion of this paper is invited and may be presented at the meeting iffiled in writing with the technical program chairman prior to the conclusion of the meeting. This paper and any discussion filed willbe considered for publication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject tocorrection.

AbstractProcess Control & Automation Technology (PCAT) has

been well understood and utilized by the downstream petroleumindustry for years. The upstream is a somewhat different story.Rig-site or wellsite automation, for instance, had been and stillis perceived by many as impractical or an overkill. Undeniably,results of past experimentation with production automation hadbeen far from conclusive. The primary reasons for such acheckered past are mostly technical and partially human. How-ever, substantial technological advances in recent years arechanging the picture. If the current trends hold, in a matter ofsay 5 to 10 years, the majority of wellsites in Canada will beautomated. Operating wells and fields with automated controlsystems will become the norm, and PCAT will eventually evolveinto yet another standard tool for the upstream oilpatch. As aresult, production personnel - engineers, technicians, field op-erators, and even administration and supporting staffs mustlearn to adapt to survive. Production automation is a tedious,and at times, confusing subject because it combines a widerange of engineering disciplines from production to processdesign, to instrumentation, control, and electronics, with theconstantly evolving computer technologies. This paper willattempt to shed some light on this PCAT subject from a user’sand non-specialist’s perspective, and explore some of the recentdevelopments that will likely have a significant impact on thepetroleum industry.

IntroductionInstrumentation and process control are standard technolo-

gies for any fluid flow operation in the oilpatch, from the reser-voirs all the way to the consumers, passing through wellbores,wellheads, wellsites, pipelines and various levels of treating andhandling facilities. Prior to the 1940s, all process control de-vices were mechanical (pneumatic or hydraulic) or electromech-anical in nature.

The invention of transistor in 1947 ushered in the electronicage, whereby sophisticated electronic sensors and control de-vices were quick to follow, and would eventually become indis-pensable in the industrial world. The petroleum industry hasalways been a leader in nurturing new technologies, and PCATwas no exception. By 1959, an oil refinery in Texas would turnout to be the first commercial deployment of a full-fledgedcomputer-based control system in human history.

With the heavy development of integrated circuit and main-frame computer during the 1960s and 1970s, and with the intro-duction of programmable logic controller (PLC) in 1969,automation quickly spread to all segments of the downstreambusiness. All sorts of processing plants, oil refineries, petro-chemical plants, pipeline and truck-based transportation net-works, right down to the point-of-sale systems in our friendlyneighbourhood gas stations would be automated in time. Now-adays, it would be a real oddity to find any such downstream

PETROLEUM SOCIETYCANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUM

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facilities not operated by some forms of automation, and it ishard to imagine how such facilities could have been operated onwhat was largely a manual basis back then.

On the upstream side though, progress had been very slow,and at times, nonexistent. Although electronic devices debutedin field metering facilities as early as the 1950s, such as variousforms of LACT, development and deployment of PCAT for thewellsites had been restricted by both technology and economics.It would take two full decades (until the 1970s) for artificial liftcontrollers, and another decade (in the 1980s) for the electronicchart reader replacement, to stake out a limited presence. Figure1 depicts the current range of deployment of PCAT among vari-ous segments of the petroleum industry. In general, the degreeof automation is less and less as one goes further and further up-stream. The only notable exceptions to this trend are in the off-shore and the oil sand mining arenas.

As of today, most of the upstream work in onshore conven-tional oil and gas fields, from the routine day-to-day wellsiteoperation to the various forms of well intervention, is still, byand large, done manually. For oil companies looking for waysto improve the bottom-line quickly and significantly, increasedPCAT deployment in the upstream, production and wellsiteautomation in particular, should deserve a closer look. Thetechnology is mature enough to be virtually risk-free, andthanks to the PC revolution, the majority of the oil companystaffs, including an expanding contingent of field operators, iswell equipped to handle such challenges.

Amongst the many obstacles hindering the progress of pro-duction automation, two were absolutely pivotal, namely wire-less linkage and the control system computer. Before gettinginto why they were such roadblocks in the past, and how theyare now being resolved, let’s review some of the basics first.

Control System BasicsTo the oil companies, PCAT is just a tool, no more special

than say logging, testing, workover, drilling, or computers ingeneral. Oil companies are not in the business to R&D suchtools (vendor companies are), therefore petroleum engineersand field operators are not normally required to know the de-tailed inner workings of any such tools to be effective users.

From a big-picture perspective, one should always rememberthat there must be a process first, the control system is merelyan add-on to assist the operation of that process. Therefore,control and IT specialists must always cooperate with, and in-deed rely on, the production personnel to understand the processfirst, and then design the control system accordingly, and notthe other way round.

Automation simply means the replacement of manual oper-ation by machines, or more precisely, by an automated controlsystem. However, the first golden rule of automation is that nooperation can be totally automated. An automated control sys-tem, in reality, is a well-balanced mixture of machine controland manual operation. As depicted in Figure 2, a comprehensivemodern control system would consist of the following five basiccomponents:

• Instruments (both Sensing and Actuating)

• Controllers (Site, Shopfloor or Plant-floor Controller)

• Control System Computers (CSC, also known as Host,Master or Central Computer)

• Corporate Computer

• Linkage

Only very large installations would incorporate all five com-ponents. Most small facilities such as the individual wellsiteswould have just one or two levels of the components - instru-ments only, or instruments coupled with some stand-alone sitecontrollers. Larger facilities such as gas plants or group batter-ies are likely better equipped, with tens, or even hundreds, ofelectronic instruments embedded in a variety of process equip-ment, a couple of PLCs located on the plant-floor, all hooked upto a CSC sitting in a control room. The most elaborate systemswould then have all the CSCs in the field link up with the cor-porate computer in a faraway head office.

Instrument does not mean sensor only. It can either be asensing or an actuating device, and it can be mechanical, elec-tromechanical, electronic, and even programmable or ‘intelli-gent’ as in the latest cutting-edge Fieldbus systems. The job of asensing instrument is to inform the connected controller of whatis happening at the process level, i.e. inside the process equip-ment. The job of the controller is to decide what corrective act-ions are needed if a disturbance occurs (i.e. process upset), andto dispatch the corrective instructions to some actuating instru-ments, in an attempt to reduce or eliminate the disturbance.

A process is said to be operated at its optimum level whenthe process variables (pressures, temperatures, fluid levels,quantities and qualities of the process material, etc.) at someselected locations are running at, or close to, their designedvalues. These designed values are, of course, predeterminedmathematically by the engineers responsible for the processdesign and deployment, and are to be maintained by the siteoperators at all times. With an automated system, the designedvalues are typically input into the controllers as set-points, ortarget values.

A disturbance occurs when the measured signals deviate sig-nificantly from their corresponding target values, which couldbe caused by some unexpected events such as power outage,sudden climatic change, fire, equipment failure, abnormal pres-sures or temperatures, etc. When that happens, the controllerswould automatically send out corrective instructions to someactuating instruments to act on, such as the opening mechanismof a valve (open/close/throttle) or the driving mechanism of amotor (on/off/speed-change).

To generate the appropriate corrective instructions, the con-trollers must be electronically programmed or mechanicallyconfigured to follow certain sets of predetermined rules of con-trol logic (e.g. close valve by 12% if downstream flow rate is5% too high). And, for most disturbances to subside fully, thesensing-evaluating-actuating cycle would normally have to berepeated many times at high speed to converge, perhaps under100 ms per cycle (i.e. 10 iterations per second) for the purposeof minimizing production loss, and much faster (say 20 ms, or50 iterations per second) for emergency situations such as fireor the uncontrolled release of explosive gases.

Besides speed, the hardware and software of the controllersare designed to guarantee a converged solution, i.e. the succes-sive generation of corrective instructions must work towards theultimate elimination of the disturbance within an acceptabletime frame (say under 1 s). Therefore, the design of most in-dustrial controllers tends to focus on the delivery of such real-time frontline control, and not to be burdened by the non-time-critical tasks such as logging and manipulating historic data.Such tasks are usually left to the next higher level of controlsystem components, the CSC (control system computer).

When electronically linked to a CSC, the individual sitecontrollers and the CSC would work as a team to provide thecomprehensive control for the entire system, such as those of aregional gas plant connecting to tens or hundreds of wells in the

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nearby fields. Plant-floor controllers at the various processmodules in the gas plant and the individual wellsite controllerswould provide the frontline, time-critical and reflex type controlfor the process instruments, whereas the CSC would providebackground and supervisory type control for the controllers. Ingeneral, the primary functions of a CSC are:

• Providing a central focal point for the day-to-day opera-tion and management of the entire field.

• Receiving data from the site controllers in real-time, andconverting the data into system-wide animated graphicdisplays (not just for one particular controller).

• Annunciating alarms and warnings to human workers inreal-time.

• Dispensing higher-level corrective instructions to thesite controllers, if so configured.

• Logging data (of all the site controllers) in long-termdatabase storage.

• Allowing workers to conduct on-screen data analysis.

• Printing hard-copy reports.

• Linking up, if so designed, with the corporate computer.

To perform all these functions effectively, the CSC musthave a potent CPU, abundance of memory (for both program-ming and long-term data storage), all pertinent software, and afull range of human-machine interface (HMI) features such asmultiple screen display, keyboard and mouse, various forms ofdisk drives, printers, etc. Simplified versions of some of theseHMI features, such as small LCD display window, keypad andmemory card reader, may also be found on the individual sitecontrollers.

For the typical day-to-day operation, field operators wouldinteract with the site controllers, whereas production manage-ment would interact with the CSC. Supervisors, foremen orcontrol technicians would sit in front of the CSC screens tooversee the entire operation. If a disturbance occurs in the field,the first line of defense would be the site controllers. If the dis-turbance persists beyond the range of the controllers, the CSCwould then step in. If the CSC fails to correct the situationautomatically, a management decision would have to be madeat that point to manually adjust some of the control parameterssuch as set-points, error tolerances, and specific tuning para-meters. Beyond that, the affected operation may have to be shutdown, and the control system retooled.

Besides the routine operation, engineering staffs would usethe historic databases to study production performance anddevise short- and long-term enhancement work. Some CSCsoftware may even include ambitious subprograms such assimulation and artificial intelligence. Simulation is normally auseful tool because expensive fieldwork can be tested quitethoroughly ahead of time to provide additional guidance fortheir actual field implementation. Artificial intelligence coupledwith fuzzy mathematics, on the other hand, or the so-calledexpert systems, must be approached with caution. Many un-assuming production problems are extremely complex mathe-matically, such as those associated with artificial lift or wellborehydraulics in general, and the over-reliance on computers couldvery well lead to catastrophic results.

Linking up all the field level CSCs with the corporate com-puter would allow further cooperation and better coordinationbetween the field and upper management. Access to such inte-grated systems is normally personalized and prioritized using anelaborate user identification and password set-up. Differentgroups of users within the company, such as field operators,engineers, and accountants, would be given different levels of

access to view specific types of data, and to perform the specifictypes of tasks under their respective jurisdictions.

To make the entire system work, all system componentsmust be linked up properly. There are two general forms oflinkage: wired and wireless. Wire can be metal (mostly copper)or fibre-optic based. Wireless can be licensed or license-freeradio, various forms of cellular, or satellite. Linkage can be assimple as the hardwiring of sensors, or as complicated as thewide area networking of computers. Linkage could also be con-sidered as either private or common carrier. Hardwiring andlicensed airways are examples of private linkage, whereas cellu-lar and the Internet are examples of common carriers. Obvi-ously, data security and integrity are impossible technical issueswhen using common carrier linkage.

Even fully automated control systems are operated by hu-mans. Therefore, training at all levels of staffs is a must, and notjust at the user’s instruction manual level of the specific soft-ware and hardware, but also at the basic understanding level ofPCAT in general. Field operators must feel comfortable withthe assortment of electronic devices to be effective frontlineworkers, engineers must have sufficient comprehension to beeffective designers and managers, and the administrative andsupporting staffs must be adequately trained in order to take thefull advantage of such powerful and valuable tools.

Acronyms and jargons are necessary devils in most technicalfields. On the one hand, they do facilitate communicationamongst practitioners with similar backgrounds, but on theother hand, the meanings and connotations of many acronymsand jargons are not necessarily universal or unique. As a con-verging discipline, PCAT is exceptionally dreadful in this. Thecontrol system depicted in Figure 2 could be called by a varietyof names such as DCS, SCADA, centralized control, decentral-ized control, telemetry system, digital control system, etc., andthe same is also true for each of the system components.

A case-in-point would be the PLC. When they first came outin the 1970s, they were mostly limited to digital (on/off) typecontrol. For a long period of time, PLC was considered bymany not suitable for regulatory control such as fluid flow,which normally required the more precise analog type controlfor things like pressure, temperature, flow rate, etc. This con-notation that PLC is limited to digital control is seriously out-dated as most modern PLCs would have both digital and analogI/O modules housed in the same unit.

Before the acronym PLC became popular, for many yearsthe acronym PC was actually used by the control industry todenote any type of “programmable controller”, including ofcourse the programmable logic controller (PLC). Nowadays, PCis strictly reserved for denoting “personal computer”.

Therefore, as a user of this technology, it is always a goodpolicy to ask questions, no matter how seemingly trivial thequestions may appear, and trying to factor in the background ofthe users of such jargons and terminology. Miscommunicationcould easily lead to misunderstood control systems and unsafeoperation, potential damages to properties and, most seriously,endangering human lives.

Production AutomationA typical production department (or production engineering

group of a business unit) of an oil company is responsible forthe cost-effective operation of a number of processes in thereservoirs, wellbores, wellheads, wellsites and field processingfacilities. These processes typically involve the multiphase andmultidimensional fluid flow through a wide range of media,

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from near-wellbore reservoir rock, to tubing, casing annulus,line pipe, all kinds of pressure vessels, storage tanks, pumpingand temperature-altering equipment.

Production automation simply means equipping some ofthese processes with automated control systems as depicted inFigure 3, hopefully improving the overall efficiency and profitof the operation. Obviously, not all processes are created equalas far as automation is concerned, whereby a candidate processshould exhibit some of the following characteristics:

• Repetitive

• Short-Cycled

• Complex

• Hazardous

Reservoir processes are highly complex and can only becontrolled indirectly through wells. Wellbore processes nearsandface are among the toughest to automate because of thetight workspace (effective wellbore diameter of less than 10inches), long distance from surface (thousands or tens of thou-sands of feet), hazardous working environment with high press-ure and temperature, and direct contact with corrosive fluids.

Although electronic bottomhole sensors, especially pressureand temperature types, are fairly mature devices, real-time andfull-time monitoring are still rare, even for offshore wells. Real-time manipulation of bottomhole actuating devices, such assliding sleeves, downhole valves and motors, is even moretechnically demanding and expensive, and is pretty much limit-ed to specialized operations, such as the various types of direct-ional drilling, special formation tests, and in concurrently-produced multi-zoned wells. One recent study pointed out thatsince 1997, the so-called “intelligent well systems” had beendeployed in only about 200 wells worldwide, mostly offshore.

Artificial lift and fluid volume measurement are the twomost basic types of wellsite operation. They are definitely re-petitive, short-cycled, complex and hazardous at times. Thesame is also true for the operation of dehys, treaters, separators,tank farms, compressors, metering stations and similar fieldprocessing facilities. The most obvious benefit of an automatedcontrol system is the ability to fix problems in real-time, evenunattended, resulting in significant downtime reduction, tohours or even minutes, instead of days and weeks.

The cold Canadian winters bring forth additional operatingchallenges. A simple freeze-up at any point along the flow pathcan shut down operation of a single well, groups of wells, oreven the entire field. Problems occurring in the middle of nightmay take hours for anyone to attend to, and by then, smallproblems might have ballooned into much bigger ones.

Normal well spacing in Alberta is one-quarter section for oiland one section for gas. A field operator could easily spend upto 50% or more of his or her work-shift driving around well-sites. This is definitely nonproductive, repetitive and hazardous,whereas driving accidents are the number one cause of fatalityin the Canadian oilpatch. Most of the routine wellsite tasks suchas manual booking of data and manipulation of certain valvesand motors can be easily automated.

Even before venturing out to the field, the operators shouldplan for the day’s work by first reviewing wellsite data on thecomputer. By eliminating the unnecessary site visits, more timecan be devoted to solving real problems. Cost saving in fieldvehicles alone (likely in the range of $30,000 to $60,000 pervehicle per year) and in traffic accident prevention can be sur-prisingly significant, even without any staff reduction.

Operating mature sedimentary basins such as those in West-ern Canada is increasingly challenging due to the diminishingreservoir size and energy, coupled with the worsening water and

gas invasion problems (coning, fingering, channeling, flood-front breakthrough, etc.). Unassuming minor problems maynow have an unexpected and somewhat magnified impact. Anautomated control system would help to detect problems earlyand to fix some of them automatically. At the minimum, oper-ators and engineers would be notified on a timely fashion andpertinent data are made available to them online.

Petroleum engineers (production, exploitation, development,and reservoir) need timely data to analyze, trouble-shoot, deviseand dispense timely corrective actions, while operators need theextra time to implement the corresponding fieldwork. Withonline access to the same production data, paper work of theaccounting staffs could also be streamlined, while marketingstaffs could use the same data to deal more effectively with theever-changing market conditions.

A general misconception, especially amongst field operatorcircles, is that the only reason to automate is to reduce costs bycutting staffs. Operator acceptance is absolutely crucial in thesuccessful implementation of any automation project, whereasoperator resistance is always the prime suspect for project fail-ure or sub-par performance. It is true that increased profit is theprimary motive, but then there are two variables in the profitequation: income and cost. Objectives of any automation workshould nonetheless include:

• Increasing production volumes

• Reducing downtime

• Assuring product quality (e.g. meeting crude oil andsales gas specs)

• Reducing undesirable and redundant manual labour

• Reducing energy and consumables utilization

• Improving safety and lowering accident rate

• Extending the economic life of the wells and thereforeincreasing reserves

Cost cutting is at best only part of the picture, whereas themajority of these objectives should not necessarily result in stafflay-off. In many cases, job reassignment is more of a likelyoutcome, especially for larger companies. Production increase(or arresting deliverability decline) and improvement of safetyshould always demand a high priority.

For the impending major heavy oil development in NorthernAlberta, geology will likely limit surface mining to maybe atbest 20% of the established reserves. In-situ recovery schemesutilizing horizontal wells (SAGD, VAPEX, THAI, CAPRI andthe likes) will eventually dominate. For coal-bed methane, suc-cessful exploitation of this unconventional resource of emergingprominence will largely depend on the success in wellbore de-watering and the water handling capability of surface facilities.Most of these are extremely labour intensive processes withoftentimes razor-thin margins of errors and profits, makingthem ideal candidates for automation.

With the progressively more challenging operation environ-ments, it is inconceivable that oil companies can survive withthe status quo. The mode of operation must be changed and theinformation gap between the field and head office must be nar-rowed or eliminated altogether.

Having immediate and unrestricted access to the same fielddata would certainly force the engineering and operating staffsto work a lot more closer, and to be much more cooperative,attentive and proactive in solving production problems, thusimproving productivity and profits as a result. The costs ofautomating wellsites have experienced very dramatic decreasesin recent years. Even for small oil companies, wellsite automa-tion is definitely an affordable reality now.

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Artificial LiftOf all the production operations, artificial lift is probably the

most important because virtually all production comes from thewells (with the noted exception of tar sand mining), whereliquid lifting operation is a fact of life for both oil and gas wells.

Due to gravity, all fluid columns (oil, water, and even gas)inside a wellbore exert downward pressures. In order for a wellto flow (upward, of course) by itself, the reservoir pressure atsandface (i.e. perforations) must be greater than the sum of thefluid column pressures, frictions along the wellbore tubularsurfaces, and the wellhead pipeline pressure. For low GOR oilwells or high LGR gas wells, such sandface reservoir pressure isnormally not strong enough to sustain the natural up-flow ofany fluid. Therefore, an artificial lift system, which is a perman-ent system of wellbore and wellhead equipment, must be in-stalled to lift the liquids out of the wellbore on a continuousbasis. There are six major types of lift:

• Bottomhole Reciprocating Pump (BRP, i.e. Beam orRod Pump)

• Progressive Cavity Pump (PCP, or Screw Pump)

• Electrical Submersible Pump (ESP)

• Gas Lift

• Plunger Lift

• Hydraulic Lift

Regardless of types, all lifts have four basic components:

• Bottomhole Devices (bottomhole pumps, plungers, gaslift valves, etc.)

• Wellbore Connectors (rod strings or electric cables)

• Wellhead Drives (pump-jacks, hydraulic drive, directmotor drive, etc.)

• Prime Movers (electric motors, gas or propane engines,compressors, hydraulic pumps, etc.)

Obviously, different types of lift would incorporate very dif-ferent combinations of equipment, operation approaches, andoptimization expertise, whereby the wellsite controllers mustreflect such realities. In addition, most of the mathematicalmodels for optimization are empirical in nature. A highlypraised controller may fail miserably in seemingly identicalwells.

Initially, only a small number of lift control issues weretackled, which were typically handled by stand-alone electro-mechanical devices, such as the famous Presco switch for pres-sure and pump-off control in BRPs. In time, more and morecontrol issues were included, such as those associated withwellbore connector loading and prime mover power manage-ment, not only for BRP, but also for other emerging types of liftsuch as ESP and PCP. By the mid-1970s, fully integrated elec-tronic controller boxes were slowly but definitely finding theirways into North American wellsites.

During the past several decades and especially after the mid-1980s, wellsite controllers grew in both sophistication andspecialization. For most vendors these days, their product line-ups would include glorified timers at the low-end, stand-alonepush-button units at mid-range, and packaged solution control-lers (PSC) at the high end. A typical PSC would likely includemost of the following features:

• On-site user-friendly HMI features such as keypad andLCD display

• Programmability for all I/Os

• Expandable I/O modules for additional instruments

• Flow measurement and rate calculation module

• Proprietary operation and optimization programs

• Wireless connectivity with a CSC

• Ethernet- and Internet-ready

• Power supply module with battery and solar panel orthermoelectric cell

Notwithstanding the impressive efforts by some vendors,sales of the low-end and mid-range controllers are still verymuch the norm these days, reflecting perhaps the true comfortlevel of the field operating staffs, or even that of the productionengineers.

Fluid Volume MeasurementThe accurate measurement of fluid volumes in the field is

imperative to the financial health of an oil company, becausenot only the main and processing revenues, but also the mainoperating costs such as processing charges, disposal and trans-portation, are all based on such measurement.

Although the first LACT was implemented in the 1950s, itwasn’t until the past couple of decades that electronic flow andlevel measurement devices would catch on in wellsite operation.Most of the recent development is focusing on flow metersother than the orifice type, and levels other than the direct con-tact type. However, recent surveys show that orifice meters (i.e.differential pressure based devices) are still the market leader, atleast in North America, and especially in the oilpatch.

Working with the orifice meter and its companion circularchart recorder is one of the most basic operator skills. Mostcharts must be manually changed and physically read at the endof each month. Both the manual handling and mechanicalreading of paper charts contribute to costs, time delays, andmore seriously, inaccuracies especially in wells with cyclic andfickle production characteristics such as those with plunger lift.

The idea of electronic chart replacement was probably as oldas the orifice meter itself, but mature products did not appearuntil the 1980s. Retrofitting is relatively simple and inexpensivewith practically no change to the mechanical meter-run itself.Costs continue to drop due to competition and the incorporationof newer gadgets such as the multivariable (three-in-one)transmitters. The existing installed base of orifice meters ishuge, and it will likely take years for the majority of them to beconverted.

In recent years, newer types of flow meters such as mag-netic, Coriolis, vortex and ultrasonic are being heavily deve-loped and promoted by some of the best known names in thebusiness. Their major selling points are improved accuracy andthe ability to handle a variety of gases, liquids, slurries and evenmultiphase fluids (e.g. watercut). Outside North America, thedominance of the orifice meter is now being seriously chal-lenged by magnetic and Coriolis meters.

Tank level measurement is another major chore at the well-site. Because of the somewhat isolated nature of most wellsitelocations, unchecked liquid levels could easily lead to pro-longed production stoppage and/or expensive environmentalclean-ups. Recent development in level measurement is focus-ing on non-contact technology such as laser and sound wave.Besides improvement in accuracy and ease of operation, someof the newer devices are actually less expensive than the con-ventional float and sight-glass contraptions.

Wireless LinkageThe linkage between on-site instruments and controllers is

normally wired. But for the vast majority of onshore wells,

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normal well spacing would preclude hardwiring between thecontrollers and CSC, making wireless the only technically vi-able linkage option for them. Until quite recently, linking upwells wirelessly always meant big-time investment, and that hadbeen the biggest stumbling block for the growth of wellsiteautomation.

As recently as maybe only 5 years ago, wellsite automationalmost always meant private licensed airways. Each and everystep in setting up a private airway system is a big-ticket item:license applications, transmission towers, booster stations,truckloads of electronic equipment, license and system main-tenance, and training. The paper work in license applicationsalone could take months, if not years to complete.

Now, a substantial portion of such infrastructure has beeneliminated due to the availability of inexpensive wireless ser-vices such as CDPD, CDMA, satellite, and the unlicensed air-ways. From the user’s standpoint, both CDPD and CDMA aresimilar to regular cellular phone services. The only infrastruc-ture cost is to bundle the individual wellsite controllers withproper modems and antennas (equivalent to the handsets ofpersonal cell phones).

For unlicensed airways, most governments reserve certainchannels (e.g. 40, 900 and 2400 MHz) for open public use. Suchusage has already been heavily populated by familiar consumerproducts such as household cordless phones, garage door open-ers, walkie-talkies and wireless PC. Because the airways arepublic, transmission can be interfered with inadvertently. Formost industrial use, such interference could lead to unsafe oper-ation and was, of course, unacceptable.

To achieve secured communication in the unlicensed publicairways, one solution is SST (spread spectrum technology).Modems equipped with SST would subdivide the airway intosmaller sub-channels, and use special encryption schemes totransmit data through them. The receiving modems must there-fore have the proper decoding keys to be able to read the dataproperly. After years of development and deployment, SST isfast becoming the wireless standard for unlicensed industrialuse.

Costs of the modem/antenna pairs for any of the wireless set-ups are very affordable these days, ranging from less than$1,000 to maybe $5,000 per installation. Monthly usage fees areof course dependent on the type of service, typically less than$50 for cellular, and around $100 for satellite per site, forhourly data transmission. Obviously, there would be no usagefee for the unlicensed airways.

Control System ComputerNext to wireless linkage, an affordable CSC (control system

computer) was the second biggest stumbling block for the wide-spread deployment of wellsite automation. Prior to the year2000, and especially in the olden days of mainframe and minicomputers under the somewhat antiquated paradigm of DCSand SCADA, the costs of CSC were absolutely prohibitive.

Mainframe and mini computer hardware was very expensiveindeed, which would also require an expensive environmentallycontrolled workspace to house the equipment, and an army ofcomputer wizards for routine service and maintenance. Soft-ware was mostly proprietary and user-unfriendly, equally ex-pensive, and required yet another army of wizards for serviceand maintenance. Expansions and upgrades could easily cost asmuch, if not more, than the original installation. Hence, onlyvery big oil companies could afford them, and would in effectbe able to maintain a sizeable competitive advantage.

The arrival of the PC would eventually change everythingand have the effect of leveling off the playing field, but it didnot happen right away. Prior to the Pentium chips and MicrosoftWindows 2000 operating system, performance and reliabilityproblems had prevented the PC from being considered for seri-ous industrial use. After a decade and a half of heavy develop-ment, the maturing of Windows did eventually win out,eliminating the CSC hardware cost as an issue. Nowadays, evena mid-range, off-the-shelf Windows 2000+ PC is good enoughto run an entire oil or gas field with hundreds of wells and theconnected processing facilities, phasing out the dinosaur DCSsystems.

CSC software remains an issue though. While a typical CSCsoftware license may cost only $5,000 to $10,000, the configur-ation work could cost 5 to 50 times that amount and requireweeks if not months to complete, depending on the number ofsites and complexity of the control logic. Including the start-upcommissioning, training, future software maintenance and up-grades, the total CSC cost and the long project lead-time canstill be quite prohibitive, especially for small applications.

Web-based CSC or web-hosting CSC is a clever way of us-ing the Internet to provide a cost-effective alternative, parti-cularly for non-clustered and isolated wellsites. Instead ofinstalling one’s own CSC, the individual site controllers can belinked directly to the server computer of an ASP (applicationservice provider) via the Internet, as depicted in Figure 4.

The ASP server would then act as a common CSC for all theconnected controllers (likely of different client oil companies),with password-protected webpages set up for each site. Simplyusing a regular PC equipped with proper Internet access andweb-browser, the actual end-users (operators, engineers, ac-countants, marketers, etc.) could log on to the webpages any-time to view data and manipulate, if so permitted, the sitecontrollers directly and remotely.

Customers of the ASP would normally be charged a smallonetime set-up fee for the webpages (typically under $200 forregular wellsite and under $1,000 for the more complicatedworksite such as compressor station), and a small monthly us-age fee for each site. Even including the wireless and Internetconnection fees, the total monthly bill would likely be in therange of $100 to $300 per site. Five years ago, there were onlyone or two such ASPs in Canada, now the number is more thanten including those in the US, and the list will likely grow in thecoming years.

One drawback of such web-based CSC services is the factthat they are open for business. Traffic jam is a function of thetotal number of simultaneous log-on users with a particularserver, and the ability of the ASP to keep up. Higher trafficwould eventually slow the response time somewhat and in-crease the vulnerability of the servers. However, response timeis less critical at this level, especially for most wellsite appli-cations, because real-time critical control of the process instru-ments should always be done by the site controllers, and not bythe CSC.

The typical wellsite automation costs, either with web-basedor in-house CSC, are listed in Figure 5. For oil prices in the$30+ per barrel range and gas prices in the $4+ per Mcf range,cost is really a non-issue. Most major oil companies in Canadahave already had a portion of their wellsites automated, typi-cally with in-house CSC, but are starting to experiment withoutside web-based services, especially with non-clustered andisolated sites. For smaller oil companies, the web-based CSCservices have already made a lot of headway in recent years.

The current population of automated wellsites likely rangesfrom up to 10% for most oil companies, to as high as maybe

7

30%+ for a selected few. With the continual upward trends ofthe oil and gas prices, it is entirely possible to reach or surpassthe 50% mark within the next 5 to 10 years. And, should thefield operators and engineers embrace the concept wholeheart-edly while getting up to speed technically, then the sky wouldbe the limit.

RecommendationsFor new wells, regardless of onshore or offshore, the current

cost level represents only a tiny fraction of the total well cost,and is an absolute no-brainer. The time required to automate anonshore well in Canada is typically in a matter of weeks, esp-ecially if using web-based CSC. In general, the following proce-dures are recommended:

1. Define the objectives and scope of the work.

2. Identify the wellsite processes required and suitable tobe automated, and review their operation.

3. Identify and select the process variables (pressures,temperatures, flow rates, etc.) to be monitored. Thiswill define what sensing instruments and the type ofmodification for the existing equipment are required.

4. Identify and select the actuating instruments (valves,motors, etc.) to be controlled. This will define whatactuating instruments and the type of modification forthe existing equipment are required.

5. Define how the selected actuating instruments are to becontrolled. This will define the control logic relation-ship between the actuating and sensing instruments, theset-point values of the pertinent process variables, andtheir error tolerances. This will also define the processschematic (computer graphics) to be displayed on theCSC screens or webpages.

6. Specify the technical requirements of the various con-trol equipment (instruments, controllers, CSC and link-age devices) capable of performing all the necessarycontrol functions within the scope of the work. Selectthe equipment based on speed, accuracy, reliability,prices, and the ease of configuration, field installation,and the day-to-day operation.

7. Finalize the design and budgeting, and proceed to pro-cure the equipment and services.

8. Configure and bench-test the control equipment, andproceed to field installation, start-up, maintenance, andtraining.

For retrofitting older wells, cost could be the deciding factor.A detailed economic analysis considering the cost and benefitfactors listed in Figure 6 is highly recommended, which maynot only be able to uncover unexpected costs, but also hiddenbenefits as well. Missed opportunities can be as equally undesir-able as cost over-runs.

Because web-based CSC charges on a per site basis, for alarge number of clustered wells, comparative cost study shouldbe conducted for setting up one’s in-house system. However,the service and maintenance cost of the in-house system mustalso be counted, and the feasibility of keeping an army of non-core business specialists must be addressed. Even for multi-nationals, in-house systems may not always be the best solution.For one thing, project lead-time is always longer. The Canadianoilpatch is full of lessons that outside vendors can indeed pro-vide substantially more superior services, less costly, and with aquicker project start-up.

Training will be the key to remain competitive, either on apersonal or corporate level. Like the PC or Internet, or even theelectronic calculator of not so long ago, engineers and fieldoperators must learn to adapt to avoid obsolescence.

Closing RemarksWireless communication and CSC became affordable only

very recently. The notion that wellsite automation is unrealisticshould be reexamined. PCAT has been an effective tool for thedownstream petroleum industry for years, and its usefulness inthe offshore and oil sand has been proven quite conclusively.Now, it’s the turn for the rest of the upstream industry.

Production automation should be regarded as both an en-gineering and management tool. Not only can it be used to fost-er efficient field operation, but more importantly, it also allowsthe engineers and management to gain full control of the fieldproduction data - unrestricted, unassisted, accurate, and in real-time. Without good and timely data, engineers can’t do their jobproperly, and the quality of management decisions will suffer asa result.

By eliminating the information gap between field and headoffices, automation will provide the necessary tool for the en-gineering staffs to be more attentive and work more closelywith the field staffs to optimize production, reduce waste andloss, and improve overall productivity and profits. Operatingmaturing oil and gas fields such as those in Western Canada,such additional attention could mean life or the premature deathof the wells. It is envisaged that, in a matter of 5 to 10 years, themajority of wellsites in Canada should likely be automated.

Wellsite automation presents probably one of the biggestopportunities for oil companies to improve bottom-line in asignificant manner, with virtually no risk. Companies withstaffs well conversant with such technology will likely gain adecisive edge. In a highly competitive industry such as petro-leum, that could well be the difference between survival andelimination.

AcknowledgementThe authors of this paper would like to thank the manage-

ment of Land Petroleum International Inc. and Prologic Con-trols Ltd. for allowing the publication of this paper.

NOMENCLATURE & TERMINOLOGYActuating Instrument = A process instrument that executes in-

structions sent from the controller to initiate changes tothe process. Examples are the opening mechanism of avalve and the driving mechanism of a motor. In tradit-ional instrumentation terminology, it can be referred toas the final control element or end device.

ASP = Application Service Provider

BRP = Bottomhole Reciprocating Pump

CAPRI = Catalytic THAI

CDMA = Code-Division Multiple Access, a cellular techno-logy based on SST and analog-to-digital conversion. Asthe third generation cellular technology to the old analogand the earlier digital ones, CDMA has variant namessuch as 3G, 1X, 3X, etc.

8

CDPD = Cellular Digital Packet Data, an earlier data transmis-sion technology which utilizes the unused cellular chan-nels to transmit data in packets. CDPD offers quickercall set-up and better error correction than using mo-dems on an analog cellular channel.

Controller = A control device that receives sensing signalsfrom one or more sensing instruments, performs signalmanipulation, and sends out the corresponding actuatingsignals to one or more actuating instruments. It can bemechanical, electromechanical, electronic and/or pro-grammable. Programmable electronic controller is bydefinition a computer, typically with a real-time operat-ing system, as opposed to a non-industrial PC withbatch-like operating system. PLC, RTU, ROC, PC-basedPLC and micro-PLC are all programmable electroniccontrollers.

CPU = Central Processing Unit, a microprocessor acting as thebrain of a computer.

CSC = Control System Computer, a computer connects to thesite controllers of a control system and acts as theirmanager to perform mostly non-time-critical, but occa-sionally time-critical, control functions. CSC is alsoknown as the host or master terminal unit, system con-troller, system or central computer.

DCS = Distributive (or Distributed) Control System. Distribut-ive control is a general design strategy by which thefunctions of a control system are distributed horizontallyamongst devices of the same level (such as the variouscontrollers on the same plant-floor) and/or verticallyamongst devices of different levels (such as between theinstruments and controllers, or between the controllersand CSC). DCS was originally used to distinguish itselffrom the then popular Direct Digital Control (DDC, ahighly centralized system) in the early 1970s, and spec-ially as a product name used by Foxboro, Honeywelland Yokogawa for application in very large systems,typically using mainframe or mini computers back then.Nowadays, the acronym DCS may invoke such conno-tation as being a very large and somewhat outdated sys-tem. Virtually, all modern control systems are designedas some forms of distributive control. The acronym DCSmay also be used to denote Digital Control System orDigital Cellular Service.

ESP = Electrical Submersible Pump

Fieldbus System = A special type of distributive control sys-tem that utilizes a single communication standard for allcontrol devices in a particular system, from instrumentsto controllers to CSC. Typically, expensive intelligent(smart) instruments are required. FOUNDATION Field-bus, Profibus and HART are competing examples ofsuch communication standards.

GOR = Gas-Oil Ratio

HMI = Human-Machine Interface

I/O = Input/Output

IT = Information Technology

LACT = Lease Automatic Custody Transfer

LCD = Liquid Crystal Display

LGR = Liquid-Gas Ratio

PC = Personal Computer

PCAT = Process Control and Automation Technology

PCP = Progressive Cavity Pump

PLC = Programmable Logic Controller. PLC is an electroniccontroller with programming capability, which wasoriginally used by Modicon and Allen-Bradley as aproduct trade name since 1969. However, the popularityof PLC had turned it into an industry jargon, somewhatover-used and sometimes misused, for all programmableelectronic controllers.

PSC = Packaged Solution Controller

ROC = Remote Operation Controller

RTU = Remote Terminal Unit

SAGD = Steam Assisted Gravity Drainage

SCADA = Supervisory Control and Data Acquisition. SCADAis an industry jargon for a special form of supervisorycontrol. Supervisory control is a general design strategyby which one level of control devices (e.g. controllers)would act as supervisors for the devices of a lower level(e.g. instruments). Typically, the lower level devices areautonomous in their routine operation and interferedwith by their supervisors only if and when specificemergency criteria are met. SCADA became an industryjargon in the 1980s specially for systems covering largegeographical areas utilizing long-distant communication,such as wireless, between the site controllers and CSC.Prime examples of users are the oilfields, railways andelectrical power distribution. The site controller used inSCADA is normally called RTU (Remote TerminalUnit), which may also appear as product name of somevendors. Supervisory control, by definition, is also aform of distributive control because the control funct-ions are definitely shared between two or more levels ofdevices. Originally, supervisory control also impliedsome forms of human intervention, whereby set-pointadjustment and start/stop could be initiated by humanoperators.

Sensing Instrument = A process instrument that detects andmeasures the value of a process variable, and send themeasured signals to the controller for further actions.Examples are thermometers, pressure recorders, flowmeters, level sensors, barcode readers, motion and vi-sion devices. In traditional instrumentation terminology,it can be referred to as the primary element, or simply,sensor.

SST = Spread Spectrum Technology

THAI = Toe-to-Heel Air Injection

VAPEX = Vapour Extraction

REFERENCES1. CLELAND, N.A.; Centralized Automatic Production

Control and Data Gathering in the Virginia Hills Field;SPE Paper 112, JPT January 1962.

2. SCHWARTZ, H.J.; Control and Telemetering of GasProducing Wells; JCPT May 1962.

3. NIVEN, R.D.; A New Era in Supervisory Control; JCPTOct-Dec 1971.

4. BURRELL, G.R.; Key Design Parameters of a ComputerProduction Control System; JCPT Jan-Mar 1972.

5. DUNHAM, C.L.; Bridging the Information Gap BetweenOperations and Engineering; SPE Paper 3967, JPT April1973.

6. SKINNER, S.C.; A Quarter Century of Production Pract-ices; SPE Paper 4701, JPT December 1973.

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7. BROPHY, C.E., SCOLES, L.R.; Analysis of an Operat-ional Oilfield Supervisory Control System; JCPT Apr-Jun1975.

8. ANDERSON, G.L., REED, G.A.; Automation in theSouth Swan Hills Unit; JCPT Oct-Dec 1981.

9. BOHANNON, J.M.; Automation in Oilfield ProductionOperations; SPE Paper 13395, JPT August 1984.

10. BOYADJIEFF, G.I.; The Application of Robotics to theDrilling Process; SPE Paper 17232, February 1988.

11. MCGINNIS, B., FLANDERS, W.A; Developing a Pro-duction Data Management (PDM) System Using Off-The-Shelf Software; SPE Paper 16507, JPT October1988.

12. Independent Cuts Costs With Wellhead Automation;Petroleum Engineers International, May 1989.

13. DUNHAM, C.L., ANDERSON, S.R.; The GeneralizedComputer-Assisted (CAO) System: A ComprehensiveComputer System for Day-to-Day Oilfield Operations;SPE Paper 20366, 1990.

14. HALGRIMSON, B.; Wexpro Expands Wellhead Auto-mation; Petroleum Engineers International, July 1990.

15. GILL, G.R.; Amoco's Field Data Entry System; JCPTSep-Oct 1990.

16. BATTEN, G.L., Jr.; Programmable Controllers – Hard-ware, Software, and Applications, 2nd edition; McGraw-Hill, Inc., 1994.

17. NGAI, C.C.; Integrating Production Process ThroughAutomation, Rockyford Pilot Experience; PS-CIM &AOSTRA Paper No. 94-72, June 1994.

18. PARR, E.A.; Industrial Control Handbook; Reed Educat-ional and Publishing Ltd., 1995

19. OUTOMURO, M.V.; Using Automation for OptimizingProduction Fields; SPE Paper 29534, April 1995.

20. GORANSON, H., KNUDSEN, R., MCLEAN, D.; UsingSCADA to Provide Corporate Wide Data Accessibility;PS-CIM Paper No. 97-SCADA, 1997.

21. REYNOLDS, M., SUTTON, J., HEDBERG, G.; Well-head Managers Improve Operating Efficiencies in thePembina Field - A Case Study; JCPT Special Edition1999, PS-CIM Paper 97-24, June 1997.

22. KNUDSEN, R., FOORD, T., BARTLE, A.; ImprovedProduction Operating Efficiencies Through Automation;JCPT December 1997.

23. MCLEAN, D., ALVIS, V.; Case History of the Imple-mentation of a Fast Track Gas Production SCADA Pro-ject; SPE Paper 49065, September 1998.

24. EDWARDS, J.J.; Gas Well Production Optimization withRemote Performance Monitoring; JCPT November 2002.

25. YODER, J.; Go New-Tech or Stick with DP?; ControlMagazine, June 2002.

26. WEBB, J.W., REIS, R.A.; Programmable Logic Con-trollers – Principles and Applications, 5th edition; Pear-son Education, Inc. (Prentice Hall), 2003.

27. DUNHAM, C.L.; Production Automation in the 21stCentury: Opportunities for Production Optimization andRemote Unattended Operations; SPE Paper 79390, JPTJuly 2003.

28. CORREA, J.F., LEPKISON, H., BITTENCOURT, A.C.;Intelligent Distributed Management System for Auto-mated Wells (SGPA): Experience and Results; SPE Paper84225, Oct 2003.

29. YODER, J.; Trends Among The Top 10 Flowmeter Tech-nologies; Control Magazine, July 2003.

30. GIALLORENZO, M., LOSETO, M., VANELL, L.; Newtechnique allows real-time watercut monitoring in oilproduction; World Oil, September 2003.

31. TURTA, A.T., SINGHAL, A.K.; Overview of Short-Distance Oil Displacement Processes; JCPT, February2004.

32. KONOPCZNSKI, M., AJAYI, A.; Optimizing reservoirperformance with intelligent well technology; World Oil,March 2004.

33. COLLISON, M.; Safe or Sorry; Oilweek, May 2004.34. COGGAN, D.A. (editor); Fundamentals of Industrial

Controls, 2nd edition; ISA, 2005.

Figure 2: Basic Structure of a Control System

InstrumentsInstruments

ControllersControllers

Control System ComputersControl System Computers

Corporate ComputerCorporate Computer

At the process leveln Sensing Instrumentsn Actuating Instruments

At the worksite leveln Mechanical Controllersn Electromechanicaln Electronicn Programmable

At the production management leveln Factory/Plant Computersn Field/Regional Office Computers

At the corporate management leveln Enterprise/Corporate Computer

LinkageLinkagen Wired or Wirelessn Private or Common Carrier

Process

22

11

33

4455

Figure 4: Web-Based CSC System

Internet

ISP

ASP Server

User PC

ASP = Application Service ProviderCSC = Control System ComputerI/O = Input/OutputISP = Internet Service Provider

Site Controller

Process In

strum

ent I/O

Process

HMI

ISP

ISP

CSC

Wirelessor wiredlink

I

I

I

I

I

O

O

O

O

Figure 5: Typical Wellsite Automation Costs

Pressure Sensor c/w transmitter ….….….…....Temperature Sensor c/w transmitter ………....Orifice Gas Rate Module c/w transmitters …..Turbine Flow Meter Package …………..….....Ultrasonic Liquid Level ……………….……..Pneumatic Control Valve ………..……...……On/Off Solenoid Valve ………………….……Valve Positioner …………………….…..……Wellsite Controller (Low End) ……….………Wellsite Controller (Mid-Range) ……...…….Wellsite Controller (High End) …………...…Solar Power Module ………………...……….SST Modem c/w Antenna …………….……..CDMA Modem c/w Antenna …………….….CDMA Per Site Monthly Fee ………….……...High Power Antenna …………………...…....Satellite Modem c/w Antenna …………....…Satellite Monthly Fee Per Site ….……..….….CSC Hardware (Typical Windows PC) ….....CSC Software (Unlimited I/O) ………….......Web-CSC Per Site Set-Up ……………..….….Web-CSC Per Site Monthly Fee ………...…...Internet Per Site Monthly Fee …………….....Engineering Hourly Rate ……………..….…..CSC Configuration Hourly Rate ………….…..Site Installation Hourly Rate ……………..….

Example Project20 Oil & Gas WellsMonitoring Only (No Control)CDPD Linkage to Web-CSCCapital Cost = $200,000Monthly Fee = $2,000

Example Project20 Oil & Gas WellsMonitoring Only (No Control)CDPD Linkage to Web-CSCCapital Cost = $200,000Monthly Fee = $2,000

Example Project20 Oil & Gas WellsMonitoring & Control (2 On/Off Control Valves)SST Linkage from Wellsite to Central SiteCDMA Linkage from Central Site to Web-CSCCapital Cost = $340,000Monthly Fee = $1,100

Example Project20 Oil & Gas WellsMonitoring & Control (2 On/Off Control Valves)SST Linkage from Wellsite to Central SiteCDMA Linkage from Central Site to Web-CSCCapital Cost = $340,000Monthly Fee = $1,100

Example Project1 Gas WellMonitoring Only (No Control)CDPD Linkage to Web-CSCCapital Cost = $8,000Monthly Fee = $80

Example Project1 Gas WellMonitoring Only (No Control)CDPD Linkage to Web-CSCCapital Cost = $8,000Monthly Fee = $80 Example Project

1 Gas WellMonitoring & 1 Control ValveCDMA Linkage to Web-CSCCapital Cost = $12,000Monthly Fee = $80

Example Project1 Gas WellMonitoring & 1 Control ValveCDMA Linkage to Web-CSCCapital Cost = $12,000Monthly Fee = $80

$250$250

$3,000$3,500$1,000$3,500

$150$2,500$1,500$3,000$7,500$1,500$3,000$3,000

$50$1,500$5,000

$100$2,000$7,000

$100$50$40$80$60$50

Unit Cost

Figure 6: Automation Cost-Benefit Analysis

CostsSensing InstrumentsActuating InstrumentsController Hardware PackageController SoftwareController ConfigurationTerminal BlocksWire & CableSite InstallationCSC Hardware PackageCSC Software, Maintenance & UpgradesCSC ConfigurationWireless Modem & AntennaCommunication Monthly FeeWeb-CSC Set-Up FeeWeb-CSC Monthly FeeInternet FeeProcess Equipment ModificationTraining

CostsSensing InstrumentsActuating InstrumentsController Hardware PackageController SoftwareController ConfigurationTerminal BlocksWire & CableSite InstallationCSC Hardware PackageCSC Software, Maintenance & UpgradesCSC ConfigurationWireless Modem & AntennaCommunication Monthly FeeWeb-CSC Set-Up FeeWeb-CSC Monthly FeeInternet FeeProcess Equipment ModificationTraining

BenefitsProduction IncreaseDowntime ReductionQuality AssuranceInproving SafetyEnergy & Consumables SavingImproving Operator EfficiencyStaff ReductionReducing Accident CostsReducing Field Vehicle CostsBetter Data Access for All StaffsImproving Engineer EfficiencyReducing Engineers’ Field Visit CostReducing Accounting Paper WorkImproving Volume Data AccuracyImproving Marketing EfficiencyExtending Life of Wells & ReservesImproving Overall Management

BenefitsProduction IncreaseDowntime ReductionQuality AssuranceInproving SafetyEnergy & Consumables SavingImproving Operator EfficiencyStaff ReductionReducing Accident CostsReducing Field Vehicle CostsBetter Data Access for All StaffsImproving Engineer EfficiencyReducing Engineers’ Field Visit CostReducing Accounting Paper WorkImproving Volume Data AccuracyImproving Marketing EfficiencyExtending Life of Wells & ReservesImproving Overall Management