This article appeared in the December 2009 edition of the Fort Worth Basin Oil and Gas magazine
The well site of the future may feature valves, pipe sections, flow meters and other pieces of equipment that come from the manufacturer embedded with electronic sensors to facilitate remote monitoring. Or perhaps the site will be equipped with video monitoring, with the pictures transmitted back to the pumper or company engineer via digital radio signals, much like basic digital data is transmitted today from some well sites.
These are some of the technological advances that experts with companies who provide remote monitoring services think may be on the horizon. But even the remote monitoring technology available today is a huge leap forward from just a few years ago, with costs dropping so that some form of remote monitoring is probably economical even for smaller, independent producers.
Supervisory control and data acquisition, or SCADA, systems have been used by large companies for years, but typically required an in-house information technology (IT) staff and installation of a proprietary communications network to relay the information between the well site and company offices. SCADA computer systems normally work two ways – they can both monitor and control sites remotely. The original, large SCADA systems also were costly to install and maintain.
However, advancing technology is making SCADA and other types of remote monitoring systems more user-friendly, easier to implement and less expensive.
“A lot of the independent operators of today received their initial training right out of school working with a major oil company. Many of them are familiar with SCADA systems, but they often thought it cost multiple millions of dollars, required huge staff and a bank of computers,” said Greg Scoggins, vice president of sales and marketing for Wellkeeper Inc. (www.wellkeeper.com), which offers remote monitoring systems designed to meet the budgets and needs of small to medium-sized companies. “Only recently has remote monitoring become affordable for smaller, independent operators to do the same thing.”
One advancement that makes installation of remote monitoring systems less difficult is the ability to use wireless sensors on a well site. Sensors must be attached to each piece of equipment that needs to be monitored, such as a tank being monitored for the fluid level inside. Previously, the sensors were connected to the monitoring system by wires.
"You would have to hard-wire the sensors, which required digging a trench, laying conduit, it was very expensive. Now, you just mount the sensors and they wirelessly transmit the information back to the controller. That’s a much easier, cost-effective way of installing a system.”
New technology also allows the equipment on often remote well sites to use less power so it is frequently possible for it to operate on a solar-powered battery, which also reduces costs. Advances in communications equipment and technology are also reducing costs. The data must be transmitted back to a receiver at an office or other location via some type of communications technology. In the past, about the only choice was for companies to set up proprietary radio systems to relay the data from often far-flung well sites. These days, consumer digital cellular telephone and data networks have spread to even remote parts of the United States, and those cellular networks can be used to transmit data from the well site.
“Basically, you’re riding the back of the consumer network, which has expanded as more and more cell phones get out there,” Scoggins said. “There’s still a few dead spots out there, but we’ve found that, even where your cell phone doesn’t work, you can put a fixed 20-foot tower antenna and still get very good coverage
Also, for those who still use radio systems, that technology continues to improve so that larger and larger amounts of data can be transmitted, such as video signals.
Most remote monitoring systems offer at least one-way communications, bringing information from the well site back to a central office or computer. For example, the Wellkeeper production data gathering system offers one-way monitoring of such things as oil tanks, water tanks, electronic flow meters, turbine meters, compressor, pump off controllers (POCs), programmable logic controllers (PLCs), tubing and casing pressure, and plunger lift systems. With a compressor, for example, typically the system will monitor discharge or suction pressure and vibration, which helps tell whether the compressor is running or not. Wellkeeper is also starting to offer some two-way systems, where some of the devices in the field can be controlled through the system from the office or computer.
“For example, we could open and close a valve on a plunger lift system,” said Scoggins. “You could turn a pump on or off remotely – that’s something new that will be really useful to small operators, especially for wells that are somewhat remote and take a bit longer to travel to.”
Remote monitoring systems allow pumpers in the field to prioritize their work day, taking care of the more important needs first and saving on driving time, as well.
“The traditional way of monitoring a field is to send pumpers out every day to collect the data, bring all the information back to the office and manually enter it into some report. So they wouldn’t know if a well was down or not until they actually got out there and looked at it and personally visited the site. With the technology we have now, it allows you to automatically monitor the production battery. You’re able to access all this data and look at several hundred wells to determine which to visit first.”
Wellkeeper’s Scoggins added that having information about a problem before travelling to a site can help with planning ahead for such things as what personnel and equipment will be needed to repair the problem.
“They may need a specialist or company that does a special type of work, which they wouldn’t know until arrival at the location without something like Wellkeeper,” Scoggins said.
In addition, remote monitoring systems can allow pumpers to visit sites less often.
“We see a fair number of companies that have moved back to an every-other-day or a get-it-as-you-can philosophy and then solve the most important problems first,” Scoggins said. “They still want the well site visited several times a week, but they don’t have to go every day. They are fine with going to the problem areas first, instead of just driving a pre-determined route. They are dealing with the mission critical issues first. This can help save money by saving on fuel, truck maintenance and the amount of people it takes to adequately look after a field. You’re able to have existing pumpers handle more wells more effectively and productively.”
Remote monitoring can also help improve the work field personnel can do on site.
“When a pumper goes out to the site, instead of taking measurements, the measurements are already taken and the pumper can spend his time trying to improve the site, doing maintenance, etc. For example, they see that a level has been dropping 10 percent in the past month and try to see what’s happening with that.”
For example, Deanna Poindexter, district engineer for Range Resources’ New Mexico assets, uses Wellkeeper’s one-way remote monitoring system. Via the Internet on her computer in her office in downtown Fort Worth, she can monitor approximately 125 well sites located a five-hour drive away. At the same time, Range’s field staff in the New Mexico area can use the system to monitor sites from their offices or via laptop computers in their vehicles. Poindexter said she and her pumpers out in the field access the Wellkeeper system every morning via the Internet on their computers, where they can review data together as they talk.
“A lot of times, as I’m sitting here in Fort Worth talking to them in Eunice, New Mexico, for example, they’re on their laptops looking at Wellkeeper and saying ‘it looks like I’ve got a problem on this well, that’s where I’m going first.’ So they’re able to prioritize what their daily needs are. Also, if they get an alarm on a tank level that’s getting too high, if it’s too close for comfort, they can go straight out there, address the problem and save us from any incidences or problems on location. The technology is great. We find it to be cost effective, it promotes efficiencies in the field. And anytime you can prevent a spill from taking place, you’ve saved thousands of dollars in cleanup costs.
“Previously, we had a lower level of monitoring,” Poindexter continued. “But it was simpler. Should a tank alarm go off, a phone call was made to a pumper’s cell phone, and all he could see was that an alarm was going off, he couldn’t see the cause behind it or exactly what was going on. He couldn’t see tank levels of anything else related to the battery location. So bringing in Wellkeeper upgraded those abilities, provided the pumpers with more insight into what’s taking place on location, what’s causing the alarm and gives them remote access to the alarm so they can address problems right from their laptops.”
Range also uses remote monitoring in its Hartville, Ohio-based operations. They have more than 800 electronic flow meters installed covering about 80 percent of production. They use barcode technology to read production rates. Six people in the Hartville Gas Measuring Department are responsible for tracking gas sales from more than 10,000 wells in the Appalachian basin, including new wells being drilled in the Marcellus and the Nora fields.
"Even with remote monitoring, we still have a big job,” according to Range’s Mike McLaughlin, who works in the Hartville operation. “We have an electronic alarm system that notifies us of well issues such as low flow or high pressure. It’s not unusual for me to receive 50 or more notifications in a given 24-hour period.
“I think of the Gas Measuring Department as a liaison between operations and accounting,” McLaughlin continued. “We gather the data and help interpret it so that revenue accounting can pay the royalty owners. In the Marcellus, production of liquids such as propane, butane and pentane are significant and add to the challenge. We need to be able to break down the production to the component level. New software is helping us with this task.”
Most remote monitoring systems today provide access to information via the Internet, offering an array of graphs, charts and statistics.
"People want to monitor everything. We live in such an information rich world that people expect all this data coming into them. They know the information is out there on the site and they can have the data coming in for them to monitor, to be able to improve their operation. You can’t improve what you can’t measure. This allows them to measure things, to tweak different sites, try new ways of improving their operation, to improve their margins. We see our clients getting this information and coming up with more sophisticated models of how they analyze the information to improve efficiency. You can have a constant reading of data and you can look at sites over a period of time and do comparative analysis between sites, maybe different operators at the site, to see who is doing a better job of operating the site.”
Of course, all of this new technology requires some training so that workers can learn to use it. Vendors usually include training with their particular remote monitoring application system and the systems continue to become more user-friendly.
“One nice thing about Wellkeeper is it’s very intuitive from the get go,” Range’s Poindexter said. “Our field staff had an introductory training session conducted by Wellkeeper, to the Web site, to the technology, to the capabilities of it, and how each pumper could customize his view of what he was seeing to suit his individual needs. From there, they were turned loose with it and allowed to use it to really optimize their daily routines.”
For those “old school” industry folks who are not yet comfortable using computers, most systems can set up alarms to be forwarded to a cell phone as a text message, for example. Or they can get an office assistant to fax the reports to them.
“Many pumpers have been faxing in reports for a long time, so they have a fax machine in their office or home,” explained Wellkeeper’s Scoggins. “They can have someone else in the office who is more tech savvy actually fax the reports or charts to them (taken off the Wellkeeper Web site). They come in first thing in the morning, pull up each well, print and fax them. That’s one way to work around it.”
And how much does all of this cost? Wellkeeper estimates, for example, that installing its remote monitoring system on an oil tank and a water tank would cost under $5,000, plus a monthly fee of about $75, depending upon how frequently a customer wants to access information.
“The longer you operate a well, the more you spread out the initial installation cost,” Scoggins pointed out. “We’re also able to group multiple locations in the same proximity together. If you monitor a group of five to 10, we’re able to lower the monthly cost even more because we can use low power wireless radios to transmit data from one well location to another that has a digital cellular communication box. We construct a hub and spoke system, where we mesh locations together into a central point.”
All of this data can be analyzed to help facilitate better and faster decision making, according to the IBM Corporation. The “intelligent oilfield” can use advanced technologies to analyze raw data and turn it into meaningful information that experts can use to improve production, reduce costs and streamline operations. For example, staff can identify which wells might benefit from pump upsizing, and which show signs of wear. Incremental production increases quickly add up and can significantly improve the output of mature fields. The applications are seemingly endless for using information to optimize oil and gas operations.
By Pamela Percival, Editor, Fort Worth Basin Oil and Gas Magazine
Monday, January 4, 2010
Thursday, December 3, 2009
Wellkeeper Remote Monitoring Benefits
Clients are utilizing Wellkeeper to reap the following benefits:
1. Reduce costs
1. Reduce costs
- By decreasing the amount of miles a pumper drives, because he has visibility into each well and tank battery before he leaves his home or office
- Allowing field personnel to “pump by exception”, and go first to the sites that require their attention and expertise
- By reducing the number of mechanical failures, because preventative data is always being monitored by the Wellkeeper system, and alarms are sent
2. Increase production
- By knowing when wells go down and getting them back online sooner
- Remotely configuring Pump-off Controllers, EFMs, plungerlifts and PLCs
- Having real-time visibility into the behavior of a well
- Providing engineers the data needed to maximize production
- Identifying up & downstream effects on production, and eliminating problems
- Using Wellkeeper’s Alarm Notification System
- Dispatch personnel to the site before the spill occurs, allowing time to take corrective and preventative action
- Turning pumps on or off when an alarm condition is present
- Using the latest technology to provide sophisticated measurement and real-time data gathering
- Knowing what wells are doing minute by minute
Wellkeeper offers a cost-effective way to have access to well data by being able to sign into the website at your convenience, to view both the current and historical well production information. Wellkeeper has recently unveiled some significant improvements in remote monitoring services, such as remote configuration of equipment, real-time data every few minutes and extended coverage of wireless communications, which lowers the monthly telemetry cost dramatically.
As a reminder, Wellkeeper has helped companies lower their cost of operations, increase their production, and reduce environmental costs associated with spills. During these times of uncertain commodity prices, tighter capital, and increased environmental liability, Wellkeeper’s services can generate an immediate ROI.
Tuesday, November 3, 2009
What to do with all that data?
Once again, technology has created a looming monster about to overwhelm many independent producers. Before remote monitoring of oil and gas production facilities became commonplace, it used to be that producers/engineers were lucky to get one accurate daily reading from their field personnel of what was happening at a given well site/tank battery. Even as remote monitoring was implemented, early systems were usually only polling sites two to four times a day. But as telemetry costs continued to decline, many systems now offer sample rates as frequent as every five minutes!
So what to do with all that data? The opportunity is to:
1. Do optimal scheduling and dispatching of field personnel
2. Do predictive maintenance allowing minimal maintenance expenses with maximum production
3. Plan for and manage required resources to eliminate waste and ensure timely availability of resources
4. Have more granular data for reservoir modeling
The ability to balance the first three above competing objectives stems from the development of three techniques previously available only for the major oil companies for decision support.
The first is PROBABILISTIC SIMULATIONS that periodically process the incoming data from the remote monitoring system to understand the range of potential future outcomes that may occur for that well/field. The second is INTELLIGENT AGENTS that are embedded in the simulations who react to events according to rules used by the operational process. The third is an OPTIMIZATION ENGINE that can “shape”, under uncertainty and risk, the range of outcomes of a plan so that decisions can be made to move toward the desired results, while minimizing effort.
These concepts have been successfully applied to several major oil and gas field operations. To do it successfully requires not only the remote monitoring data but a commitment to an iterative process where the above tools “learn” over time to fit with the actual field being operated. It also requires integration with the cultural and procedural context of the organization (in other words, what the organization believes is the best way to operate). The result of the interaction between the decision support system and the organization is a continuous learning process for the life of the production field.
So to enable the investment in remote monitoring to be fully realized, a producer has the opportunity to acquire additional tools to avoid being buried in data. Using these techniques, instead of drowning in too much data, the operating company will be able to react more quickly to problems and opportunities and plan better for the future. Data is good, once you pass it to new tools that react to events as they occur in the field.
Co-authors:
Dr. Lester K. Sisemore
President and CEO
VGO Oil and Gas
Dr. Sisemore has over thirty years experience in the Exploration and Production sector of the oil and gas industry as a senior technology executive with Chevron, an executive consultant with IBM Global Services, and an independent consultant. Focus areas have included geophysical research, exploration operations, upstream data management, and technology management. Expertise includes strategy and planning, operational modeling, business process management, project valuation, portfolio decision-making, and technology implementation. Dr. Sisemore has specialized in the implementation of Upstream Petroleum Technology – including the strategy, planning, and change management that are a necessary part of this process. Focused on the improvement and sustainability of oil and gas portfolio and asset performance, is able to help clients create competitive advantage by solving important operational problems.
Contact information: les@vgo-oilandgas.com or 281-344-0351
Greg W. Scoggins
Vice President
Wellkeeper, Inc.
Mr. Scoggins has over 20 years experience in the oil and gas technology solutions business. His focus areas have been remote data monitoring solutions, operations and production process efficiency improvement, reserves and economics software systems and integration of engineering software tools using decision tree analysis. Mr. Scoggins came to Wellkeeper from OGRE Systems, where he also served as Vice President. Previously, Mr. Scoggins was a Vice President at Implicit Monitoring Solutions and Landmark Graphics Corporation. Mr. Scoggins has a Bachelor of Science degree in Engineering Management from Dallas Baptist University, and is a 28 year member of the Society of Petroleum Engineers (SPE), as well as IPAA.
Contact information: 888-WELLKEEPER (888-935-5533) or Greg@Wellkeeper.com
So what to do with all that data? The opportunity is to:
1. Do optimal scheduling and dispatching of field personnel
2. Do predictive maintenance allowing minimal maintenance expenses with maximum production
3. Plan for and manage required resources to eliminate waste and ensure timely availability of resources
4. Have more granular data for reservoir modeling
The ability to balance the first three above competing objectives stems from the development of three techniques previously available only for the major oil companies for decision support.
The first is PROBABILISTIC SIMULATIONS that periodically process the incoming data from the remote monitoring system to understand the range of potential future outcomes that may occur for that well/field. The second is INTELLIGENT AGENTS that are embedded in the simulations who react to events according to rules used by the operational process. The third is an OPTIMIZATION ENGINE that can “shape”, under uncertainty and risk, the range of outcomes of a plan so that decisions can be made to move toward the desired results, while minimizing effort.
These concepts have been successfully applied to several major oil and gas field operations. To do it successfully requires not only the remote monitoring data but a commitment to an iterative process where the above tools “learn” over time to fit with the actual field being operated. It also requires integration with the cultural and procedural context of the organization (in other words, what the organization believes is the best way to operate). The result of the interaction between the decision support system and the organization is a continuous learning process for the life of the production field.
So to enable the investment in remote monitoring to be fully realized, a producer has the opportunity to acquire additional tools to avoid being buried in data. Using these techniques, instead of drowning in too much data, the operating company will be able to react more quickly to problems and opportunities and plan better for the future. Data is good, once you pass it to new tools that react to events as they occur in the field.
Co-authors:
Dr. Lester K. Sisemore
President and CEO
VGO Oil and Gas
Dr. Sisemore has over thirty years experience in the Exploration and Production sector of the oil and gas industry as a senior technology executive with Chevron, an executive consultant with IBM Global Services, and an independent consultant. Focus areas have included geophysical research, exploration operations, upstream data management, and technology management. Expertise includes strategy and planning, operational modeling, business process management, project valuation, portfolio decision-making, and technology implementation. Dr. Sisemore has specialized in the implementation of Upstream Petroleum Technology – including the strategy, planning, and change management that are a necessary part of this process. Focused on the improvement and sustainability of oil and gas portfolio and asset performance, is able to help clients create competitive advantage by solving important operational problems.
Contact information: les@vgo-oilandgas.com or 281-344-0351
Greg W. Scoggins
Vice President
Wellkeeper, Inc.
Mr. Scoggins has over 20 years experience in the oil and gas technology solutions business. His focus areas have been remote data monitoring solutions, operations and production process efficiency improvement, reserves and economics software systems and integration of engineering software tools using decision tree analysis. Mr. Scoggins came to Wellkeeper from OGRE Systems, where he also served as Vice President. Previously, Mr. Scoggins was a Vice President at Implicit Monitoring Solutions and Landmark Graphics Corporation. Mr. Scoggins has a Bachelor of Science degree in Engineering Management from Dallas Baptist University, and is a 28 year member of the Society of Petroleum Engineers (SPE), as well as IPAA.
Contact information: 888-WELLKEEPER (888-935-5533) or Greg@Wellkeeper.com
Friday, October 2, 2009
Implementing Remote Data Monitoring Technology in Times of Economic Crisis
Understanding the value that remote data monitoring technology can bring to an oil and gas company is fundamental to justifying a financial investment, and critical to the successful adoption of the technology. A basic dynamic that is inherent with selling any technology is the “value-point”. The value point essentially assumes that the technology delivering value to an organization is unimportant in the eyes of the buyer, and the benefits the technology delivers is the true selling point.
If the value point delivered by remote data monitoring outweighs the return on investment timeline set by the corporate and operations staff (typically 12-18 months) and the value point benefit is considered important by that organization, then the investment should be seriously considered.
A rather short-sighted argument is to not invest in remote data monitoring during an economic downturn in the oil and gas industry. An economic downturn is typically associated with the requirement of the prospective buyer to limit future spending, cut current field operating costs, and diversify offerings to mitigate losses.
Although the critical value-points are now typically shifted to cost savings, all of the value-points for remote data monitoring still exist. As such, a company evaluating remote data monitoring to address these value-points should, under the same pretext of return-on-investment and corporate prioritization, invest in the underlying system that best supports their needs.
Suffice to say, some companies looking to address economic downturns with an investment in remote data monitoring have accelerated the ROI cycle times and limited their capital budgets. These same companies have an adoption acceptance curve that has shifted to represent their new needs; however, they still have value points that demand remote data monitoring solutions.
In times of economic crisis, vendors must be conscious of the changing corporate and operational priorities of their clients, while buyers must be conscious of not losing sight of the value that remote data monitoring can bring, regardless of their current economic situation.
If the buyer has any hope the industry will eventually rebound, the best time to implement remote data monitoring is when other projects are postponed and more attention can be focused on cost-saving tools. While the breakeven point of an investment in remote data monitoring is usually months, the largest benefits will be realized when the industry returns to a robust state. By increasing production, remote data monitoring is even more valuable when commodity prices are higher. By reducing operating costs, such as spills, pumper fuel costs, pumper truck maintenance and oilfield equipment maintenance, remote data monitoring delivers an even larger impact on profitability when the costs for these things are higher.
In short, the time to invest in remote data monitoring is now. By utilizing remote data monitoring to streamline and better manage field operations today, oil and gas companies set themselves up to cash in on the benefits for years to come.
Critical Value Points for Remote Data Monitoring
There are several critical value points inherent to oil and gas field operations that are addressable through adoption of remote data monitoring technology.
Greater Quality Control to Reduce Wellsite Spills
Faster Quality Control to Reduce Wellsite Spills
Optimized Production Scheduling
Increased Production Throughput
Increase Production Yields
Reduced Production Overhead
Optimized Information Flow to and from Field Worker
Quicker Response to Field Workers
Reduced Need for Routine Wellsite Inspections
Reduced Human Errors during Daily Production Reporting
Enhanced Corporate Decision Making
Scalability to Expand Operations
Scalability to Reduce Operations
Reduced Overhead for Product Storage
Accelerated Auditing
Minimize Shrinkage
Access Real Time Inventory
Sunday, September 6, 2009
Remote Monitoring: Online in the Oil Patch
This article appeared in the June 2009 edition of the Permian Basin Oil and Gas magazine
http://www.pbog.com/index.php?page=article&article=88
When Randy Krall tells an operator that he is in the “remote monitoring” business, the operator no longer responds with a “What’s that?”
“At least they have heard of it,” said Krall, president of Wellkeeper, Inc., an Albuquerque, N.M,.-based technology company that has been involved in remote monitoring in the Permian Basin for six years. “The industry is still in its infancy, but it is no longer obscure.”
Krall acknowledged that every well and every situation is different, but he claimed there are four advantages to having a remote monitoring system. The first advantage, he said, is reducing cost by making people more efficient.
“We like to say it lets the pumper be the pumper,” he said. “When he takes off in the morning, he knows where the problem is. It means less routine driving and less gas.”
“We call it ‘pump by exception,’ ” added David Hight, North American sales manager for the smart, self-powered wireless “iNodes” sensors that Tyler-based Ferguson Beauregard, Inc., has developed. “Let’s say a pumper is babysitting 10 wells, and he goes to each of them clockwise every day. That is time-consuming and not an efficient way to use your resources. With remote monitoring, he can see the pressure has dropped at the No. 4 well, and he can go to it first. He visits the trouble spots first and addresses that well’s issue.”
Reducing environmental exposure is the second advantage, according to Krall, because sensors can be equipped with an alarm.
“Depending on the volume, a problem at a well can be either an inconvenience or a catastrophe,” he noted.
“All of our sensors are fully alarmable,” emphasized Ferguson Beauregard’s Hight. “If there is a high level or a low level, or high pressure or low pressure, an alarm goes off, and the pumper or operator can be notified by cell phone or e-mail.”
The third advantage to remote monitoring, according to Krall, is the pumper knows when there is a problem and can get the well back on line quicker, thus increasing production.
“The fourth dimension may be a little harder to wrap your arms around,” Krall stated, “but it gives you better access to data and what is really going on with the well. The well’s production may look normal if you are looking at it just once a day, but if you are looking at the data in real time, you may discover a problem.”
Krall explained that there are three components to remote monitoring – sensors at the well site, a way to communicate the data out of the field, and then a way to present it.
Sensors
Sensors can monitor any number of things from tank levels to pressures, gas volumes, electronic flow meters, liquid volumes or water volumes at a disposal site.
Ferguson Beauregard has been making sensors for the oil and gas industry for 35 years, but got involved in the remote monitoring end of the business about nine years ago with the development of its wireless “iNodes.”
“These sensors talk to an RTU (remote terminal unit) or CCU (central collection unit or central communication unit),” Hight said. “We can be as little or as much help as the customer wants. We can do it all, or we can take the data and push it to an existing radio. Think of the sensors as spokes on a wheel, and the CCU as a hub. The hub can talk to each of the sensors.”
A typical well site, according to Hight, might include four “iNodes,” two oil tank level sensors, a flow tubing pressure sensor and an electronic flow meter.
“Each device talks to the CCU,” he explains. “A pumper can touch a button, and it will show instantaneous reading. He can see a digital LED reading at one location.”
That has a safety advantage as well, Krall added, pointing out that the pumper no longer has to crawl up a ladder to the top of the tank to check the fluid level.
Getting Out of the Field
The second part of the remote monitoring function is the ability of getting the data out of the field. Hight said Ferguson Beauregard uses either satellite or digital cell technology, “depending on the client’s needs.”
Krall said Wellkeeper, Inc., is now using digital cellular service to get the data out of the field, but that has been an evolution over the last seven years.
“We started out using satellite, then analog cell service and now digital cell,” he noted. “The price keeps going down with every technological change.”
“That is a huge advantage,” Greg Scoggins, vice president of sales and marketing for Wellkeeper, Inc., said of digital cellular service. “When we started, we used analog cellular service. That was spotty at best. Satellite allowed universal coverage, but the expense was high and there was only limited data available a few times a day. Digital cellular service came in on the back of the consumer network, and the oil and gas industry benefited.”
Surprisingly, Krall said cell service is usually available in even the most remote locations in the Permian Basin.
“You think about having service on your cell phone to make a call,” he explained, “but we have stronger radios and a fixed antenna. There are only a handful of sites that still use the satellite options.”
“Satellite is still a fall-back,” added Scoggins, “but with a 20-foot antenna, we have coverage almost everywhere, and you can get information every five minutes. It is far cheaper than satellite with 12 times more data frequency. We call it ‘near real time.’ ”
The one thing that Wellkeeper’s system doesn’t do is turn something on or off, but Scoggins said that is the next step in the evolution of its system.
He said SCADA (Supervisory Control and Data Acquisition) systems can do that now, but they are really expensive and are only being used by the major companies that have their own information technology (IT) department.
“Our system is not meant to replace the pumper,” Scoggins reiterated. “The idea is to make the pumper more efficient.”
Krall said Wellkeeper’s system offers “80 percent of the functionality at 20 percent of the cost” compared to the much more expensive SCADA systems.
Balloon Launch
Space Data Corporation offers perhaps the most unique method of getting the data out of the field. For the last five years, the Chandler, Ariz.-based company has launched a constellation of industrial weather balloons every day or several times a day to provide 24/7 coverage to the oil and gas industry in the Permian Basin.
Andy Germer, managing director of Space Data’s commercial network, said the balloons comprise a free-floating network that operates between 60,000 and 100,000 feet altitude, well above airline traffic.
“The network is owned by Space Data,” he explained. “We own the nationwide frequency at 900 mhz, so there are no restrictions of interference. We fly coverage in a 200-mile radius of Midland. Wind speeds are constant at about 15-25 mph at that altitude. We know that at certain times of the year, we launch from the west and certain times of the year from the east.”
Germer said the weather balloons eventually disintegrate in the atmosphere, but their payloads, the transceivers that provide the communications, float back to the earth attached to a parachute. The balloons are equipped with global positioning satellite (GPS) technology, so they can be tracked and recovered. Space Data technicians also have the ability to steer the balloons, moving them up or down into various thermal systems.
“Cell coverage is not good in a lot of West Texas,” Germer stated. “We are trying to automate wells so it lessens the need to check a well or pipeline every day.”
Services that Space Data offers the oil and gas industry, according to Germer, include alarm monitoring of storage tanks, compressors and pipelines, production monitoring, tracking compressors, drilling rigs, service trucks and frac tanks via GPS, and cathodic protection monitoring and notification. Field communications is also available.
Displaying the Data
Scoggins said Wellkeeper can provide a Web-based presentation of its data or it can integrate the information into a company’s existing software program.
“We supply a nice Web presentation with graphs and charts,” he pointed out, “or we can provide an Excel spread sheet and integrate into a company’s accounting system.”
Hight said Ferguson Beauregard’s wireless “iNode” sensors can “push that data to whatever is receiving it or we can provide an ‘iNode’ viewer, which is Web-based for the user that has Internet access.”
Automating the Routine
Remote monitoring is designed to make the oil and gas industry more efficient.
“We want to automate the routine, mundane, and sometimes dangerous things that pumpers do,” related Hight. “Remote monitoring is good management of personnel. If the device monitors the routine, it frees the pumper to do what he does best, which is to fix problems and increase production instead of routinely climbing on tanks. That makes sense.”
“This isn’t a toy,” Krall said of remote monitoring. “It is a real business benefit to solve very painful problems. It takes communication software and builds a complex solution.”
By Al Pickett, Special Correspondent
http://www.pbog.com/index.php?page=article&article=88
When Randy Krall tells an operator that he is in the “remote monitoring” business, the operator no longer responds with a “What’s that?”
“At least they have heard of it,” said Krall, president of Wellkeeper, Inc., an Albuquerque, N.M,.-based technology company that has been involved in remote monitoring in the Permian Basin for six years. “The industry is still in its infancy, but it is no longer obscure.”
Krall acknowledged that every well and every situation is different, but he claimed there are four advantages to having a remote monitoring system. The first advantage, he said, is reducing cost by making people more efficient.
“We like to say it lets the pumper be the pumper,” he said. “When he takes off in the morning, he knows where the problem is. It means less routine driving and less gas.”
“We call it ‘pump by exception,’ ” added David Hight, North American sales manager for the smart, self-powered wireless “iNodes” sensors that Tyler-based Ferguson Beauregard, Inc., has developed. “Let’s say a pumper is babysitting 10 wells, and he goes to each of them clockwise every day. That is time-consuming and not an efficient way to use your resources. With remote monitoring, he can see the pressure has dropped at the No. 4 well, and he can go to it first. He visits the trouble spots first and addresses that well’s issue.”
Reducing environmental exposure is the second advantage, according to Krall, because sensors can be equipped with an alarm.
“Depending on the volume, a problem at a well can be either an inconvenience or a catastrophe,” he noted.
“All of our sensors are fully alarmable,” emphasized Ferguson Beauregard’s Hight. “If there is a high level or a low level, or high pressure or low pressure, an alarm goes off, and the pumper or operator can be notified by cell phone or e-mail.”
The third advantage to remote monitoring, according to Krall, is the pumper knows when there is a problem and can get the well back on line quicker, thus increasing production.
“The fourth dimension may be a little harder to wrap your arms around,” Krall stated, “but it gives you better access to data and what is really going on with the well. The well’s production may look normal if you are looking at it just once a day, but if you are looking at the data in real time, you may discover a problem.”
Krall explained that there are three components to remote monitoring – sensors at the well site, a way to communicate the data out of the field, and then a way to present it.
Sensors
Sensors can monitor any number of things from tank levels to pressures, gas volumes, electronic flow meters, liquid volumes or water volumes at a disposal site.
Ferguson Beauregard has been making sensors for the oil and gas industry for 35 years, but got involved in the remote monitoring end of the business about nine years ago with the development of its wireless “iNodes.”
“These sensors talk to an RTU (remote terminal unit) or CCU (central collection unit or central communication unit),” Hight said. “We can be as little or as much help as the customer wants. We can do it all, or we can take the data and push it to an existing radio. Think of the sensors as spokes on a wheel, and the CCU as a hub. The hub can talk to each of the sensors.”
A typical well site, according to Hight, might include four “iNodes,” two oil tank level sensors, a flow tubing pressure sensor and an electronic flow meter.
“Each device talks to the CCU,” he explains. “A pumper can touch a button, and it will show instantaneous reading. He can see a digital LED reading at one location.”
That has a safety advantage as well, Krall added, pointing out that the pumper no longer has to crawl up a ladder to the top of the tank to check the fluid level.
Getting Out of the Field
The second part of the remote monitoring function is the ability of getting the data out of the field. Hight said Ferguson Beauregard uses either satellite or digital cell technology, “depending on the client’s needs.”
Krall said Wellkeeper, Inc., is now using digital cellular service to get the data out of the field, but that has been an evolution over the last seven years.
“We started out using satellite, then analog cell service and now digital cell,” he noted. “The price keeps going down with every technological change.”
“That is a huge advantage,” Greg Scoggins, vice president of sales and marketing for Wellkeeper, Inc., said of digital cellular service. “When we started, we used analog cellular service. That was spotty at best. Satellite allowed universal coverage, but the expense was high and there was only limited data available a few times a day. Digital cellular service came in on the back of the consumer network, and the oil and gas industry benefited.”
Surprisingly, Krall said cell service is usually available in even the most remote locations in the Permian Basin.
“You think about having service on your cell phone to make a call,” he explained, “but we have stronger radios and a fixed antenna. There are only a handful of sites that still use the satellite options.”
“Satellite is still a fall-back,” added Scoggins, “but with a 20-foot antenna, we have coverage almost everywhere, and you can get information every five minutes. It is far cheaper than satellite with 12 times more data frequency. We call it ‘near real time.’ ”
The one thing that Wellkeeper’s system doesn’t do is turn something on or off, but Scoggins said that is the next step in the evolution of its system.
He said SCADA (Supervisory Control and Data Acquisition) systems can do that now, but they are really expensive and are only being used by the major companies that have their own information technology (IT) department.
“Our system is not meant to replace the pumper,” Scoggins reiterated. “The idea is to make the pumper more efficient.”
Krall said Wellkeeper’s system offers “80 percent of the functionality at 20 percent of the cost” compared to the much more expensive SCADA systems.
Balloon Launch
Space Data Corporation offers perhaps the most unique method of getting the data out of the field. For the last five years, the Chandler, Ariz.-based company has launched a constellation of industrial weather balloons every day or several times a day to provide 24/7 coverage to the oil and gas industry in the Permian Basin.
Andy Germer, managing director of Space Data’s commercial network, said the balloons comprise a free-floating network that operates between 60,000 and 100,000 feet altitude, well above airline traffic.
“The network is owned by Space Data,” he explained. “We own the nationwide frequency at 900 mhz, so there are no restrictions of interference. We fly coverage in a 200-mile radius of Midland. Wind speeds are constant at about 15-25 mph at that altitude. We know that at certain times of the year, we launch from the west and certain times of the year from the east.”
Germer said the weather balloons eventually disintegrate in the atmosphere, but their payloads, the transceivers that provide the communications, float back to the earth attached to a parachute. The balloons are equipped with global positioning satellite (GPS) technology, so they can be tracked and recovered. Space Data technicians also have the ability to steer the balloons, moving them up or down into various thermal systems.
“Cell coverage is not good in a lot of West Texas,” Germer stated. “We are trying to automate wells so it lessens the need to check a well or pipeline every day.”
Services that Space Data offers the oil and gas industry, according to Germer, include alarm monitoring of storage tanks, compressors and pipelines, production monitoring, tracking compressors, drilling rigs, service trucks and frac tanks via GPS, and cathodic protection monitoring and notification. Field communications is also available.
Displaying the Data
Scoggins said Wellkeeper can provide a Web-based presentation of its data or it can integrate the information into a company’s existing software program.
“We supply a nice Web presentation with graphs and charts,” he pointed out, “or we can provide an Excel spread sheet and integrate into a company’s accounting system.”
Hight said Ferguson Beauregard’s wireless “iNode” sensors can “push that data to whatever is receiving it or we can provide an ‘iNode’ viewer, which is Web-based for the user that has Internet access.”
Automating the Routine
Remote monitoring is designed to make the oil and gas industry more efficient.
“We want to automate the routine, mundane, and sometimes dangerous things that pumpers do,” related Hight. “Remote monitoring is good management of personnel. If the device monitors the routine, it frees the pumper to do what he does best, which is to fix problems and increase production instead of routinely climbing on tanks. That makes sense.”
“This isn’t a toy,” Krall said of remote monitoring. “It is a real business benefit to solve very painful problems. It takes communication software and builds a complex solution.”
By Al Pickett, Special Correspondent
Friday, August 7, 2009
Award Winner!
On Friday, August 7th, Wellkeeper's Carlsbad-based technican, Patrick Mitchell, received an award at the IPANM conferenece in Albuquerque, New Mexico. A photo he took of a hawk landing on a wellhead has earned 2nd prize in the association's photography contest.
Wednesday, July 1, 2009
Private versus Public Networks for Remote Oilfield Monitoring
The major drivers of the traditional variations of remote production data gathering are cost and presentation. On the cost side are the two extremes of a SCADA system versus a simple call out system. The SCADA system typically employs a dedicated or private network, providing high volumes of information on a near continuous basis at a cost of up to several hundreds of thousands of dollars for spread spectrum radios, radio tower infrastructure, satellite uplinks and complex software to control it all. The ensuing private network allows the owner full use of the available bandwidth but at a significant initial cost and generally a high exposure to single point of failure due to the lack of redundancy in the infrastructure. The radios used will typically generate one or more watts of power for a range of several dozen miles at a cost of several hundred dollars each.
A more efficient alternative is to use a public network for all or a portion of the data collection. Digital cellular modems are available from a variety of vendors at a price point half or less the dedicated spread spectrum radios mentioned above. They are designed to communicate on the major cell carriers existing networks set up to carry voice and increasingly, data traffic to the oil fields. This approach uses less expensive devices and removes the need to construct and maintain a dedicated tower, freeing that capital for other uses and allowing the network to be deployed anywhere within range of a cell tower.
When the field to be monitored has a high concentration of wells in a limited geography a hybrid approach is even better than either extreme of all private or all public infrastructures. This approach uses a set of digital cellular modems dispersed through the field collecting data from several nearby locations via low power, inexpensive radios. The monthly costs are thus reduced without requiring the private tower's costs and exposure to a single point of failure.
In summary,
1. Spread spectrum radio systems require a very large upfront cost
2. Building radio towers in the oilfield increases the risk of failure of the entire system, as there is one single point-of-failure. If high winds damage the tower, or a power outage hits the area, all well sites will be unable to report data to the server
3. Digital cellular network technology is exploding, primarily due to consumer demand. This means the major communications companies are rapidly offering the best, cutting-edge technology to even remote areas of the oilfield, and continued innovation will be funded by consumers. This means reliable, consistent and inexpensive data networks for the oilfield.
4. Using a hybrid approach, companies are using digital cellular and low power, inexpensive radios to provide the real-time data they need to improve their operations and manage their assets effectively.
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