U.S. oil and gas fields are evolving with more wells and multi-well pads. PLC-based instrumentation, RTUs and HMIs are evolving, too, to meet new data management and wireless communication demands.
Across oil and gas fields in the United States, growth in unconventional extraction efforts—especially hydraulic fracturing or “fracking”—have led to more wells being drilled in smaller geographic areas, increasingly on multi-well pads. According to research from PacWest Consulting Partners, 71 percent of all wells in the U.S. at the end of 2013 were drilled on multi-well pads. That’s more than double the proportion just three years earlier.
The growth, expected to continue, is understandable: more closely spaced wells found on multi-well pads not only increase drilling efficiencies, but also provide greater economies of scale and asset utilization. An obvious example is transportation: trucking in people, equipment, and supplies to just one multi-well drilling operation (and trucking out expended material such as used fracking fluid) costs much less money and time than if the wells are located miles apart.
In turn, these factors drive greater efficiencies and lower costs to help ensure the profitability of upstream operators. That’s important because increasing horizontal lateral lengths and frac stage counts—both of which have much greater service intensity at multi-well sites—are offsetting cost reductions.
(PacWest forecasts that the number of horizontal frac stages in U.S. oil and gas fields will rise by a compounded annual growth rate (CAGR) of 7 percent through 2016.)
The Rise of Oil and Gas “Factories”
As service intensity rises on multi-well pads, so does the need for applications of industrial process automation technologies to improve the cost and time efficiencies of those services. Consequently, it requires a shift in mindset from extractive to manufacturing, with perhaps a blend of the two being ideal. Many upstream operators are starting to think this way and their increasingly sophisticated production facilities reflect it by looking more like manufacturing sites that happen to be outdoors and, most often, in extremely remote places.
The technologies enabling this transformation involve the automation and control of frac equipment and complex services during drilling stages as well as the post-completion well-heads, pipelines, and storage tanks that make up a multi-well facility. An example that spans one key part of the fracking process is automating the injection of hydraulic fracturing fluids, monitoring their storage tank levels (both pre- and post-fracking inventories), and scheduling the transportation of new supplies in and expended ones out.
This kind of automation requires pulling data from sensors to generate data for monitoring and analysis, perfect tasks for the modern programmable logic controller (PLC). Given its capabilities and the advancements in wireless connectivity, oil and gas producers can now consider extending the model of integrated operations to their upstream production facilities, especially those hosting multiple wells, no matter how remote.
The Challenge: Cost-Effective Monitoring of Remote Well-Head Performance
A typical work setting in upstream oil and gas production, especially drilling, resembles the factory of yesterday: loud, dirty, and dangerous. This is not at all like today’s modern manufacturing facilities.
With messy and volatile hydrocarbons as their “product,” upstream oil and gas producers face a set of challenges that would seem to limit a modern evolution of their day-to-day operations. Their work sites are usually remote, which brings a host of issues, such as a lack of water supplies and sewage, off-grid power requirements, and limited or no wireline connectivity. Sites also come with harsh operating conditions, including extreme temperatures; ever-changing weather patterns; and penetrating dust, dirt, and moisture. These conditions put these sites on the frontier, literally, for integrated operations.
Two forces are driving the reach of integrated operations into upstream oilfields: economics and technological development. First, the need to drive costs down and asset utilization up while avoiding downtime is paramount. To have a completed well go down can be extremely expensive (whether in a multi-well configuration or not): the cost can be up to $100,000 a day in lost output revenue, amortized drilling costs, fixed operating costs, and depreciation. But once well-heads are set in place and operating, having costly field technicians onsite daily, babysitting them against potential failure, isn’t the best use of human resources. Even having field technicians make periodic visits isn’t optimal as data gathering and visual inspections can respectively be error-prone and subjective. Second, technology is advancing on multiple fronts, not just the capabilities provided by sophisticated PLCs and wireless connectivity, but also in sensors, instrumentation, human-machine interfaces (HMIs), and energy efficiency.
The Solution: A Ruggedized, Solar-Powered Well-Head instrumentation Skid Package with Remote
To see an example of how these advancements can be combined to integrate the monitoring and control of upstream production facilities into a broader oil and gas enterprise, consider a fully ruggedized, solar-powered skid package that provides PLC-based instrumentation for well-head measurement, control, and data collection: the NYATI M1000 Remote Terminal Unit (RTU)/PLC.
Typically the more wells on a pad, the tighter the well spacing. This makes an ideal deployment scenario for the NYATI M1000. That’s because it can support up to 10 wells with expanded I/O, controlled by the recently introduced Siemens SIMATIC S7-1500 PLC. This is the latest in a long line of SIMATIC S7 PLCs, highly secure and proven in oil and gas applications worldwide. As a skid package, the NYATI M1000’s portability offers operators a wide range of flexibility in placing it among any common well-head configurations.
PLC Monitoring and Control
With the PLC controller as the system’s data monitoring and command center, the NYATI M1000 can separately control and monitor each well-head’s gas lift, measure gas flows and remotely control flow valves, provide LACT unit control and measurement systems, and provide truck load-out controls and measurement with ticketing. It can issue alerts, if the performance of lifts or valves exceeds operating parameters, and provide any diagnostics available to be programmed into the PLC. Maintenance schedules can also be programmed to provide advance notifications with pre-set time periods for the sake of dispatching field technicians with the specific work detail and any parts and tools needed.
The NYATI M1000 can also be custom-configured to meet a producer’s specific “cause and effects” operational and safety logic requirements. The unit’s expanded I/O connects well-head sensors with the PLC, which reads real-time sensor data associated with a well-head’s gas and liquid flows. These flows are calculated using algorithms that respectively comply with the American Gas Association (AGA) standards, Chapters 1 and 2, and the American Petroleum Institute (API) standards, Chapters 11,12, 13, and 21 (including the API’s August 2011 Addendum).
The PLC’s memory card contains pre-allocated data files in easily accessible CSV for each month of the year and stores the data for a full year. Data logs also can be retrieved in other widely used formats. In the event of a PLC hardware failure, the memory card will retain its data. Data also can be sent via the unit’s remote connectivity to feed distant SCADA-based distributed control systems (DCSs) and be stored.
HMI, SCADA, and Remote Connectivity
The NYATI M1000 features a graphical HMI touchscreen that is easy to learn and use. It facilitates local, onsite operation of the unit and interrogation of the PLC. It can also connect with other vendors’ HMI systems using their software drivers. USB ports on the PLC provide access to stored data that can be loaded onto a flash drive or printed by a technician. Even better, the PLC also can include an onboard Web server that can provide secure, password-protected, remote HMI viewing and control capabilities via a smartphone, tablet, or PC.
The unit’s PLC also provides a SCADA system for full local and remote data accessibility and control. It offers multiple concurrent user access to the PLC, so local and remote users as well as remote SCADA systems can retrieve data without interrupting each other or an active process.
Through its PLC’s support for open Ethernet protocols, such as native TCP/IP and ISO Transport Service on top of TCP (ITOT), the NYATI M1000 offers multi-well pad operators a variety of proven communications protocols, including Modbus 485, PROFINET, RS-232 and cellular. If necessary, it can be also configured for satellite communications. Instrumentation protocols include HART, RS-485, PROFIBUS PA, and other field protocols.
Although the NYATI M1000 can be wired to a utility grid, it is otherwise self-powered via a highly efficient solar panel that feeds an on-board battery storage system. The solar panel can rotate 360° to ensure an optimum solar angle wherever the skid is placed on a multi-well pad and can be adjusted throughout the year with the sun’s seasonal elevation. Its highly efficient power engineering—the NYATI M1000’s electronics draw just one ampere—enables it to operate for up to 10 days on a minimum charge.
The NYATI M1000 illustrates how advanced sensor, instrumentation, PLC, communications, and energy-efficient technologies can come together in one skid-based package to help operators optimize their upstream production facilities—increasingly multi-well pads—and integrate them into their wider enterprise operations. Among the many benefits:
- Greater visibility into well-head performance to ensure production optimization, with operator personnel able to remotely view real-time and historical data from well-head sensors.
- Avoiding downtime that costs as much as $100,000 a day per well, via advanced warnings of needed maintenance or repairs.
- Reducing the frequency of field technician visits, along with associated labor costs.
- Improving compliance with state and federal environmental, health and safety regulations, with more detailed, real-time monitoring of well-head performance, helping to avoid any regulatory shutdowns due to non-compliance.
- Better overall business intelligence and enterprise performance for operators, given the improved operating visibility, control, and analytics across all their operations.
While these benefits are substantial for well-head operations, process automation and control can span many other areas of multi-well facilities, including equipment automation and control, flow measurement and control, and automation of complex services.
While the migration of upstream production to multi-well facilities will only increase going forward, so will the number of wells per pad. That’s because the efficiencies are too great to ignore. For example, publicly traded Cabot Oil & Gas Corporation announced its first 10-well pad to investors in late 2013 and reported that, as a result, its drilling cost per foot had dropped nearly 30 percent, from $325 to $228. As the industry evolves, these gains and other compelling benefits of process automation and control technologies will continue to drive their adoption, transforming upstream production into an increasingly modern venture.Have an Inquiry for Siemens about this article? Click Here >>