By Michael Machuca

AUSTIN, TX.–Unconventional shaleproduction has many challenges. Rapiddevelopment and deployment of assets,accelerated production declines, and anevolving regulatory environment leavelittle margin for error and require effec-tively leveraging technology to achieveeconomically viable production.

An automation strategy based on sur-veillance, analysis, optimization and trans-formation provides a unique opportunityto reduce time to first production; loweroperating and maintenance costs; improvehealth, safety and environmental per-formance; and increase production andyield in order to maximize the economicviability of the field.

A number of best practices have beendeveloped for implementing an automationstrategy for well pad facilities that improveinsight into the key variables that impactthe health of the reservoir and optimizeoil and gas custody transfer. Field-provensolutions enable oil and gas companiesto fully utilize measurement and controltechnologies that go beyond a “goodenough” approach and manage facilitieseffectively. By utilizing innovative tech-nology in a more systematic and cost-ef-fective manner, operators can improveprocess unit operations and reliability.

With the rapid development of newfields, the variety and availability offacility management data are increasingdramatically in quantity and complexity.Yet, it remains a challenge to find the ex-pertise to filter and interpret data in atimely manner. The complexity of au-tomation integration, combined with man-aging different service providers, can putprojects at risk. Oil and gas operators

need standardized and integrated systemsand work practices that will improve cap-ital efficiency, lower project risk, andmeet challenging deadlines.

It is possible to use remote automationarchitecture and capability to transfer in-formation from the field to the office in away that provides the structure needed toreadily access critical information re-garding field equipment health, process-unit diagnostics, optimization opportu-nities, and resource utilization.

Many oil and gas operators are imple-menting a tiered automation strategy thatconsists of:

• Surveillance to obtain real-time

data to improve day-to-day asset man-agement;

• Analysis that adds automatic datavalidation and migrates data to actionableinformation in real time;

• Optimizing real time interventionwith automatic event detection and han-dling; and

• Transforming operations with in-novative business solutions.

This automation strategy is being uti-lized effectively to help operators achievetheir business goals in shale and otherunconventional resource plays, includingfaster and lower-cost first production; re-duced operating, maintenance and com-

Pad Automation Reduces Fiscal Risk

FIGURE 1Wireless Surveillance

Wellhead Casing/Tubing Pressure

Four-Tank Inventory Measurement

SeparatorProductionMeasurement

PressureRelease

Oil OutflowWater Outflow

InstrumentGas Supply

Gas Outflow

Well FluidInflow

Mist Emulsion Layer

Oil

NaturalGas

Water

The “Better Business” Publication Serving the Exploration / Drilling / Production Industry

DECEMBER 2014

Reproduced for Emerson Process Management with permission from The American Oil & Gas Reporter

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pliance costs; optimal production withmaximum yield; and better HSE per-formance.

Real-Time Surveillance

To build a foundation for analysis,optimization and transformation, accessto real-time data is necessary to improveday-to-day asset management. This in-volves installing instrumentation and ex-ploiting the breadth of technologies andtelemetry that monitor key process vari-ables in real or near-real time. As a bestpractice, technology selection should in-clude devices that are designed to worktogether, offer a simple means of inte-gration, and have diagnostic capabilitiesthat will help to enable data validationand analysis.

A flexible architecture that is scalableand considers wireless technologies willreduce costs and allow for adding instru-ments as the field changes and more ad-vanced control algorithms–such as artificiallift optimization–are required. Precon-figured software and hardware will in-crease standardization and facilitate gettingproduction on line faster.

Examples of typical well pad surveil-lance applications include:

• Monitoring wellhead integrity (cas-ing, tubing pressure, temperature), chem-ical injection, and sand/corrosion;

• Gathering separator/heater-treaterproduction data and tank volumes; and

• Lease automatic custody controlmeasurement.

Automation Best Practices

Figure 1 illustrates one well automationbest practice: wireless surveillance. Beingable to get on line quickly is a key chal-lenge in shale development because offast-paced drilling schedules. Increasingly,wireless technology is being adopted inthe oil and gas industry to reduce startuptime and installation costs, and to providea simple way to add monitoring pointsand access stranded data in remote fields.

One such wireless surveillance projectconsisted of level measurements in afour-tank battery for inventory manage-ment, separator production measurements(pressure, and oil, water and gas flowme-ters), and wellhead integrity monitoring(casing and tubing pressures). An eco-nomic analysis of the project concludedthat taking advantage of a wireless–versuswired–infrastructure resulted in a 66 per-cent cost savings and an 80 percent re-duction in startup time.

Sand production in shale plays also isa challenge that can cause damage todownstream equipment, and in extremecases can cause erosion that compromisesthe pressure integrity of the wellhead andgathering pipelines. By taking advantageof nonintrusive, wireless acoustic sanddetection, proper choke settings were de-termined to minimize sand productionand the resulting equipment damage.Since the devices were nonintrusive andwireless, they were rotated to differentwellheads after the appropriate chokesetting was determined, thereby mini-mizing capital costs.

Real-Time Analysis

After a surveillance foundation hasbeen established, the next step is to ensurethe validity of data. As a best practice,operators should consider utilizing deviceswith diagnostics to confirm instrumenthealth. This provides a means to ensurethe integrity of measurement data.

Data management software tools alloweasy visualization, trending and analysisto turn raw data into actionable informationin order to improve production planning,schedule proactive maintenance operations,and provide a means for effective remotecollaboration and problem solving inorder to make informed decisions onfield management.

Many shale fields rely on productiondata measurements from the heater-treater.They may experience difficulty in ensuringaccurate allocation accounting withoutsending someone to the field to validatethe data. In many cases, the heater-treater

down-comer level is not controlled ade-quately. This results in gas exiting thedown-comer pipe with the oil.

Many flowmeters will over measureliquid volumes because of this gas, whichthen must be reconciled with the tankvolumes. This can lead to royalty disputes.In addition to the measurement error, thegas is often lost to the tank and flare sys-tem, if no vapor recovery unit has beeninstalled.

By using diagnostic capabilities builtinto Coriolis technology, flow measure-ment data can be analyzed easily. A spikein oil production, combined with a dropin density and an increase in drive gain,indicates that gas is escaping with the oilduring the dump cycle. One oil and gasoperator estimated he could recover anadditional $72,000 a day in gas revenueon 1,200 wells in one field by using flowdata dump cycle analysis to minimizegas lost to flare.

Fiscal Data Analysis

Accurate flow measurement is very im-portant, since it is used widely for accountingin fiscal and custody transfer applications.The meter must maintain a specified levelof accuracy in order to comply with industrystandards and regulations. Meter perform-ance is ensured through periodic provingand calibration cycles.

Modern flowmeters can be equippedwith diagnostic tools that show deviationsfrom base-line calibration values estab-lished at startup or at the calibrationfacility. In addition, alerts can be generatedthat show abnormal situations that will

FIGURE 2Real-Time Optimization

Surveillance

Workflows

Optimize

Control

Validate

Analyze

Store

IntelligentWells

EnhancedRecovery

ReservoirManagement

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affect meter accuracy.These analytical tools provide added

assurance of meter performance betweenproving cycles. The fiscal risk of an ad-ditional 0.1 percent uncertainty on a me-tering system going undetected betweenproving cycles can cost $1,000 a day,which can be identified easily using ana-lytical tools and meter diagnostics.

With a surveillance system, and dataanalysis and validation established, it ispossible to close the loop and controlreal time in order to optimize processesand move to rapid intervention (Figure2). Automating and integrating optimiza-tion software support closed-loop controlin order to optimize well production, re-duce production measurement uncertainty,and automatically optimize the field toensure production targets are met andreservoir recovery is maintained.

Real-Time Separator

In order to meet production plans andmaximize production and yield, reliableand efficient separator operations thatprovide accurate and timely productiondata are needed. This requires reliablelevel measurement, dependable level-control valve performance, accurate pres-sure control loops, and accurate flow-measurement solutions that have diagnosticinsight to detect separator efficiency prob-lems. All of these devices can be integratedin a remote terminal unit with softwareto perform and automate test sequencing,scheduling, and test validation that can

be operated remotely.An optimized separator solution allows

easy diagnosis of any separator problems.By using these diagnostic tools, one oiland gas operator estimated he could re-cover 3.4 percent more gas productionby minimizing gas carry-under, whichwould go to tanks and flare. This has thepotential to increase gas sales by $3.3million a year. In addition, productionallocation errors are reduced and moreaccurate data are available to feed thereservoir model, which results in more

certain reservoir characterization.Implementing surveillance, analysis

and optimization completes the foundationfor transitioning to transformation, orusing innovative business solutions tochange the way a field is managed andoperated. It requires utilizing people,processes and technology in a collaborativeand innovative way to solve complexbusiness challenges. Oil and gas companiesare looking increasingly to integrated op-erations centers to facilitate collaborationand sharing of information, as shown inFigure 3.

Gas Lift Management

Optimizing gas lift to ensure optimalhydrocarbon recovery can pose significantchallenges. It is difficult to maintain anoptimal gas injection rate based on theratio of the volume of gas injected to thevolume of oil produced. Overinjectingreduces profitability because of the addedcost of the gas and compression, alongwith diminished incremental oil produc-tion. In the event of limited gas supply,overinjecting in one well potentiallystarves another well of needed gas, whichresults in diminished production.

Underinjection simply increases thehydrostatic pressure, which can reducethe ability of bottom-hole pressure topush fluids to the top. With multiplewells and a limited gas supply, it is chal-lenging to distribute gas to the most prof-itable wells so as to maximize recovery.

Managing gas lift requires integrating

FIGURE 3Scope of Integrated Operations Center

Asset Management• Risk Analysis• Asset Strategy

Definition• Safety Strategy

Definition• Asset/Safety System

Health Monitoring

Production Optimization• Field Management• Integrated MPC• Event-Based Electronic

Workflow Sequences

Certification &Self Services• Training Requirements/

Status• Self Certification

Mobile Worker• Operator Rounds• Manual Data Collection• Maintenance/Safety

Task Execution• Man Down Tracking

Process Control• Integrated UI• Local System/ Remote

System Controls• Alarm Management• Operations Logbook

Business &Production KPIs• Production Reports• Integrated Business

Intelligence• Business Activity

Monitoring

Integrated Information• Local/Network Search• Event Monitoring/Data

Collection• Inventory/Material

Movement Management• Document Access/Mgmt

Gas Lift OptimizationFIGURE 4

Compressor EAM Package

Gas Lift Optimizer

Gas Lift Manifold

Gas Lift ControlValve(s)

Gas Lift ControlMode (1 node foreach 4 wells)

“Intermitter” Valve(s)

Compressor Node(1 total)

CompressorPressure and Flow

Rate

Smart SeparatorData

High Vibration

Fluctuations in Gas Flow

Surge

Restrictions

Hydrocarbon Vapor Releases

Lube Oil Leak/Failure

Temperature Risk

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multiple variables across the field, and isa key example of where people, processand technology can come together to pro-vide an innovative solution. In order tomaximize efficiency, operators must:

• Automatically optimize gas lift in-jection flow rates to each well;

• Prioritize gas lift supply to the wellswith the highest profitability; and

• Protect the compressor from com-mon failures and trips that threaten gaslift supply.

Figure 4 shows an ideal gas lift archi-tecture for accomplishing these goals.Using this architecture, specialized gaslift optimization software gathers real-time data from the field and tests the var-

ious combinations of lift-gas rates againstoperating constraints.

The software then converges on an op-timum set point and automatically sendsnew lift gas rates to the automation systemeither as an advisory or as a new set point.This makes the most of available gas andallocates it to wells where it makes themost money. One oil and gas operator ex-perienced a 16 percent increase in oil pro-duction by using this solution. r

Editor’s Note: The preceding articleis adapted from a technical presentationat the 2014 Unconventional ResourcesTechnology Conference, held Aug. 25-27 in Denver.

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MICHAEL MACHUCA is upstreamoil and gas industry marketing managerat Emerson Process Management inAustin, Tx. He previously served thecompany as senior marketing engineer.Machuca began his career in 1998 asa design engineer at Cameron, andthen served as a proposals engineerat Dril-Quip before joining Emersonin 2007. He holds a B.S. in mechanicalengineering from the University ofHouston.