World Oil
®
Originally appeared in
APRIL 2014 issue, pgs 47-51.
SPECIAL FOCUS: DRILLING TECHNOLOGY
Distributed automation streamlines
operations on multi-well pads
Reduced drilling costs,
combined with a smaller
environmental footprint, have
driven the burgeoning growth
of multi-well pads. Onshore
pads can now be found with
well counts ranging from
two to 24, and higher. Yet,
automation techniques often
become unmanageable,
when handling quantities
and densities involved in
multi-well pads. Distributed
logic and control provides a
scalable solution.
ŝŝJOHN ECKLEY, ROGER PETTON,
HOLLY WOOD, XTO Energy, Inc.; RICKY
STRONG, Vinson Process Controls; and ERIC
CYTRYNOWICZ and AL MAJEK, Emerson
Process Management
A 12-well pad in Texas’ Barnett shale.
In the Barnett shale of northern Texas,
XTO Energy, a subsidiary of Exxon Mobil, had been struggling to resolve problems arising from classical automation
approaches for years. Primarily producing
natural gas, using plunger lift for de-watering purposes, a pad included up to 12 wells,
with a two-phase separator and water tank
per well. When taking more recent drilling
programs into account, well counts of up to
24 per pad are projected.
Two groups had a need to access data
from the sites: production and measurement. The production organization had
one set of electronics, to monitor tank
levels and to execute plunger lift control algorithms. For monitoring gas production,
the measurement group had a separate
set. Both electronic implementations were
based upon Emerson’s FloBoss family of
Remote Terminal Units (RTUs), but configured to serve specific purposes.
On the production side, RTUs are configured using Production Manager, a software package provided by Vinson Process
Controls. To operate a plunger cycle, the
user interface permits selection of various
triggers, several of which are based upon
data acquired from a measurement RTU.
In one case, high pressure resulting from
the initial rush of gas production, when a
sales valve is opened, can exceed the range
of flow transmitters. When such flow is not
accurately accounted for, gas production is
effectively lost for a short period of time,
many times each day.
Triggers can be used to throttle back
the flow, via an electronically actuated
valve, to prevent such loss of measurement data. A second approach controls
the duration of the plunger lift after-flow
cycle, based upon current flowrates. Oftentimes, critical velocity calculation
is involved. Critical velocity, as determined by well-known Turner and Coleman equations, is the minimum flow
required, from the well, to lift liquids.
Flow below this value will cause liquid to
collect in the well, eventually curtailing
production. By receiving updates concerning each well’s flowrate, after-flow
can be terminated at the point that most
optimizes overall gas production. In all
trigger cases, it is imperative to receive
World Oil / APRIL 2014 47
DRILLING TECHNOLOGY
Fig. 1. The classical approach to automation.
Fig. 2. The wireless, distributed automation approach.
systems that exchanged limited data, using
a hardwired, multi-dropped MODBUS
communication protocol interface. This
approach suffered from several drawbacks
that proved difficult, if not outright impossible, to overcome on wellsite installations.
Electrical properties, associated with
lengthy cable runs, caused complications.
Inconsistent data update times—ranging from 1 to 15 sec—led to troublesome
control-loop execution. With so many
items in play—including separator pressures, gas level detectors, flow measurements, tank levels, acoustic detectors, as
well as chemical pumps—the process
of mapping MODBUS registers proved
time-consuming and difficult to manage.
The system was brusquely described as
a nightmare of MODBUS mapping and
convoluted wiring.
Furthermore, normal field planning often requires the drilling of a small number
of wells, with the intent of adding additional wellbores at a later date. This approach
led to dilemmas with the deployment of
the automation systems. Classical methods
needed advance notice to plan for the larger number of device point counts. Or each
new well installation became a brownfield
upgrade, incurring all the inherent expenses associated with increased on-site labor
and deferred production. Headaches only
increased with the expanded drilling programs underway.
WIRELESS DISTRIBUTED LOGIC
timely updates about each well’s flowrate from their respective measurement
RTUs. Additionally, individual tank levels are continually monitored to execute
related well shutdowns, using a causeand-effect program.
From the measurement view, adherence to American Petroleum Institue
(API) and American Gas Association
(AGA) standards—for flow computation and audit trail requirements—was
of paramount concern. RTUs configured
to act as traditional flow computers fulfill
these needs.
48 APRIL 2014 / WorldOil.com
Overall, each pad was tied back to a
main corporate office, via several longhaul radios. Production activities, including plunger-lift optimization, would then
be reviewed by personnel in the main office. Measurement data would be made
available, as required by accounting.
PAD DATA MANAGEMENT
PROBLEMS
The classical approach, based upon
common automation practices, is depicted
in Fig. 1. Essentially, the two groups—production and measurement—had separate
To address these weaknesses, XTO performed a pilot test, based upon Emerson’s
concept of a Distributed RTU Network
(DRN). A DRN is a time division, multiple-access (TDMA) based, time-synced,
“master-less” wireless RTU network. It is
peer-to-peer addressable and requires no
MODBUS protocol register mapping. The
pilot wellsite was modified from the classical approach, as depicted in Fig. 1, to the
DRN version shown in Fig. 2.
The RTUs are the same type of equipment as used in the classic approach. Additional hardware is added to each unit
in the form of a short-haul radio module. Operating in the 2.4-GHz frequency
band, the technique is basically the same
as is commonly found in Wi-Fi applications. Distances of up to 10 mi (line of
sight) can be crossed, which readily covers the area of a well pad and allows for
access to remote sites. While the RTUs
are of the same family, the units can be
composed to fit a particular functionality.
DRILLING TECHNOLOGY
Fig. 3. The distributed system makes use of a drag-and-drop technique in its design
mode.
Fig. 4. A three-well plunger lift node.
itation, a second network can be created.
To avoid conflict between multiple networks, utilizing the same radio frequency
spectrum, communications are based
upon selectable pre-determined “hop patterns.” Up to 15 networks can co-exist.
One of the nodes serves as an access
point for the network. This node can discover other nodes automatically, as they
are added. A user has the ability to select
which nodes become part of a particular
network. The access point also serves as
the central location for a SCADA application. That is, only one long-haul radio
is needed to connect to a distant SCADA
host server. The rest of the nodes can
all be accessed directly, via the host, by
making use of a “pass-through” feature
of the network protocol. For the pilot
test, two long-haul radios were kept in
service, to avoid modifications to the
SCADA server.
In the current configuration, an RTU
dedicated to handling tanks and emergency shutdown logic was designated
as the access point. The unit would process selected information from other
network nodes, and issue appropriate
shutdown commands. The update time,
for all of the devices on the network, is 1
sec, which is suitable for critical control
requirements. The ability of the RTU to
monitor the wireless link between remote nodes provides a mechanism to ensure that the system is fail-safe. Programming can be customized to take specific
actions on one or more units, in the wireless network, should communications
be interrupted.
FIELD RESULTS
In the case of the pilot, units were outfitted to operate three plunger-lift wells,
each. Other units handled the measurement requirements, at multiple meter
runs, and yet another style performed
tank-level monitoring and executed surface shutdown control logic. Each of these
RTUs became a node on a network.
Instead of using MODBUS registers to map data between RTUs, the
distributed system makes use of a dragand-drop technique in its design mode,
50 APRIL 2014 / WorldOil.com
Fig. 3. A user adds an RTU to the network, and then proceeds to select points
to either send to, or receive from, other
network RTUs. This means that an
RTU’s database is “browsable” by other
RTUs in the network.
ROBUST COMMUNICATIONS
A network can support up to 25 RTUs
or nodes. The pilot program required 12
such devices. Should the network configuration grow to exceed the maximum lim-
From the beginning, the pilot’s purpose
was not to modify current operations; the
pilot equipment performed the same function as the preceding classical implementation. Rather, the intent was to demonstrate
enhancements for future well installations.
The results exceeded expectations.
Benefits projected in the next installations include several items detailed below.
Elimination of cabling, heavy-equipment trenching. Wireless technology
eliminates the need to trench and bury
conduit between the wellhead equipment,
and the separators and storage tanks. Previously, end-device, emergency-shutdown
signals and MODBUS communications
wiring had to be routed through these underground pathways. Expenses that can
DRILLING TECHNOLOGY
be eliminated include hydro-truck costs;
heavy-excavation equipment costs; repairs
to underground equipment damaged by
strikes; labor associated with excavation
work; and the cost of wiring materials.
Subsequent pad modifications can be accomplished quickly—without the need
for excavations. A side benefit relates to
the susceptibility of equipment to damage from induced transients. High-voltage
transients arise from nearby lightning
strikes, creating potential differences between points connected together with
cables. Getting rid of long cable runs negates the affect of all but the most direct
lightning strikes.
Seamless integration of production,
measurement goals. Since a DRN does
not use MODBUS protocol, the associated
issues found in the previous installation
evaporate. The ease of the drag-and-drop
style, of point mapping between units, significantly reduces set-up time and related
errors. Production functions can be added
easily to control costs, such as chemical
control, liquids measurement, and a manually activated, central emergency, site-shutdown switch. The flexibility to map any
point to and from any unit, in the wireless
network, markedly eases interface issues
between production and measurement applications. Password protection is afforded
to prevent inadvertent modifications of the
respective objectives.
Scalability. Classical architectures are
most efficient when large point counts
are concentrated into a single box. As a
result, there are always concerns in highdensity locations of processor loading.
For example, there are limitations on the
number of meter runs that can be placed
on a unit. Consideration has to be given
as to whether calculations are gas-oriented, or computationally intensive liquid
measurement versions. Since the DRN
consists of intelligent nodes, each with
the capacity to serve their respective purposes (Fig. 4), the system capability automatically grows in proportion to need. In
short, once determined to fit a particular
use, computing and memory issues are no
longer matters of concern.
From an installation standpoint, the
ability to quickly add RTUs, to an existing wireless network, is a distinct advantage. After initial drilling is concluded,
the addition of future automation, for
later wells, is fast and simple. This ability extends to multiple pad sites, within
range of the access point, providing the
ability to automate production between
multiple pad sites.
Reduced deferred production. The
combination of all the above benefits
provides significant savings in terms of
man-hours. Usually, automation is one
of the last functions placed in service before commencing production. With the
DRN system, time to first production,
on a greenfield installation, is projected
to be reduced by a nominal three days—
representing three less days of initial deferred production.
Lower, total installed cost. From an
equipment perspective, the ability to use
the access point as a pass through, for other
units on the wireless network, eliminates
additional radios. On the test site, the radio
count dropped from 18 to two. By coupling
measurement and production functions in
a single RTU, this count can be decreased
even more. When combined with diminished cabling and trenching work, savings
in excess of $1 million can be realized in a
300-well drilling program.
TOTAL PAD OPTIMIZATION
CONCEPT
The prospect of achieving the aforementioned benefits has already been demonstrated by the pilot efforts. Taken as a
whole, these elements serve to make new
installations manageable and avoid placing
burdensome demands on existing personnel. However, the gains for operations are
anticipated to broaden.
The presence of what is essentially
an on-site wireless Local Area Network
provides capabilities for optimization
that previously were either very costly to
achieve, or simply unattainable. All of the
wells in a wireless group can be set to work
in unison with each other. Well functions
can be set up to work on one or more conditions existing in any other RTUs in the
network. Furthermore, liquid monitoring and chemical use can be orchestrated
to work, based on real-time production
needs, for one or all wells in the network.
The possibilities for site-specific optimization are limited only by the imagination
of the operations team.
Article copyright © 2014 by Gulf Publishing Company. All rights reserved.
JOHN ECKLEY is an automation
supervisor with XTO Energy. He
is a former avionics technician in
the U.S. Navy and has had
extensive exposure to amine gas
plants, gas measurement, and
gas well automation systems. He
currently manages the automation of oil and gas
control systems for the Barnett shale area.
Additionally, Mr. Eckley has been instrumental in
teaching production optimization methods in
various XTO Energy producing areas.
HOLLY WOOD joined XTO
Energy’s Production group in
2008. In her current role, as a
facilities clerk, she coordinates
equipment ordering,
equipment inventory, systems
test verification, and scheduling
of activities for the Production Facilities and
Production Automation groups.
RICKY STRONG is the RAS
services and applications
manager for Vinson Process
Controls in Lewisville, Texas.
Vinson Process Controls is the
local business partner for
Emerson Process Management
for East, North and West Texas, Oklahoma and
New Mexico. Mr. Strong has over 30 years of
experience in the oil and gas industry, starting
his career with Northern Natural Gas.
ROGER PETTON is a former
member of the U.S. Marine
Corps, with experience in naval
avionics and various RADAR
school training. He has an
extensive background in
high-purity process piping
systems, bulk chemical delivery systems, and
bulk gas delivery systems. Mr. Petton is an
automation specialist at XTO Energy, involved
with the deployment of automated oil and gas
control systems in the Barnett.
ERIC CYTRYNOWICZ is the
RTU product manager with
Emerson’s Remote
Automation Solutions business
unit. He has over 20 years of
marketing and product
development experience in
the manufacturing, power generation, and oil
and gas industries. Mr. Cytrynowicz has a BS
degree in chemical engineering and an MBA
degree in industrial marketing.
AL MAJEK is the oil and gas
production area technical
manager with Emerson’s
Remote Automation Solutions
business unit. He has more than
30 years of experience in the
design, manufacture and
deployment of automation in the oil and gas
industry. Mr. Majek holds a BS degree in
electrical engineering from Rice University. He is
a certified Project Management Professional,
and a registered Professional Engineer.
Printed in U.S.A.
World Oil / APRIL 2014 51
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