Scratch out a shale-play living
Part 3: Producers are struggling with depressed oil prices, but at least they’re producing. Drilling, conversely, has slowed to a minimal pace.
So far, this article series has examined refining and the oil industry as a whole. This installment concentrates on land-based operations and includes the actual oil plays and production sites where oil, natural gas, and water are separated and prepared for refining. The nature of this section of the industry has changed enormously over the past few years with the advent of large-scale hydraulic fracturing for oil and gas production. For a while, producers couldn’t drill fast enough in areas such as Marcellus, Bakken, and Eagle Ford plays, but those advances stalled as the price of West Texas Intermediate roughly halved during 2014. Much has been written on the causes for this change, but for now, the effects will be considered, concentrating on unconventional drilling. From 2010 through 2014, investment in exploration and drilling increased by 80%, but that trend has reversed. Areas where jobs couldn’t be filled fast enough are now seeing major declines. But how does this macroeconomic picture affect life for companies trying to make a living by producing crude oil? Traditionally, the upstream portion of the industry had generally been regarded as the high-profit part of the business with refining plodding along, trying to keep its head above water. That picture reversed and companies that only operate refineries are glad to be doing just that.
Oil still flows
The industry consensus is most of the conventional oil and gas in North America and much of the world has been found and extracted. The next barrels of oil will either come from unconventional plays or involve expensive extraction methods, in some cases both. Fracking is more expensive than traditional methods, and oil prices below $60 per barrel make those unsustainable. However, once the wells are drilled and producing, it’s important to keep the product flowing. “One thing that’s keeping the oil prices low is that everything that has already been developed is producing at maximum or close to maximum,” said Randy Miller, vertical marketing director for gas at Honeywell Process Solutions. “If the initial drilling investment has already been made, it’s almost always the best decision to produce at the highest level. If you strip away the cost of capital, the operating costs of shale wells are not all expensive. The sunk cost and the cost of capital is the biggest component, so there is not much incentive to shut the well down because you still have to service the debt, maintain leases, and other associated costs. There are fixed costs you can’t avoid whether the asset is producing or not.” Miller added that in some situations producers ended up halting work in new fields, completing wells but stopping short of doing the final connections. The wells remain untapped, waiting for prices to recover.
James Crafton, consultant with Performance Sciences, considers the rate of return on investment the key element as companies look at their situation. “Only the leveraged small production operators are in a bad way,” he said. “The rest just aren’t making as much money as they would like. However, based on my analysis and that of a few others, those companies where the primary cash flow stems from drilling are in trouble. This is because production alone does not cover their operating costs. It has been reported that in several shale plays, few, if any of the wells will actually pay out.” According to Crafton, the resulting management strategies to mitigate this challenge are diverse to say the least, and include:
- Reducing nontechnical staffing and terminating consulting staff
- Minimizing capital expenditures: no compression and no surface facilities
- Reducing drilling or drilling to hold acreage, set pipe to satisfy the contract, and move to the next lease
- Not bringing wells online, which saves on lease operating expenses and automation costs.
Not a great situation, but production companies are pushing ahead in areas where production is already underway. Other companies look at this situation with a sense of history and know the industry has survived boom and bust cycles many times before. This is just one more. “I’ve seen some projects that are tied to the bigger picture,” said Virgis Vaiciulis, senior consulting technical professional at Wood Group Mustang’s automation and controls team. “Those companies say, ‘We know times are tough, but we still have to execute this project because it affects other areas of our fields.’ Everything is tied together, and if you change one piece, it affects other pieces, and if you upgrade one site, you need to upgrade other sites too, because you can’t just do it halfway.”
Automation to the rescue?
Conventional wisdom states, “When the going gets tough, the tough automate.” Well, perhaps, but it isn’t always so simple. Automation requires investment and when times are tough, there might not be a lot of extra money available. As the first article in this series pointed out, just because there might be a clear business case for making some sort of improvement, companies are not necessarily ready to leap at such an opportunity. There are other considerations at work. “Whenever an industry retracts, we have a surplus of many things, so the aspects that focus on efficiency are not usually the ones that are employed first,” Miller said. Many projects are proceeding, particularly those related to compliance issues, but overall Honeywell has been surprised at the extent to which producers have delayed or cancelled other automation projects, still the expectation is that discretionary automation projects related to efficiency increases they will come back as soon as the price of oil shows more sustained upward movement, according to Miller. Companies with a little foresight might want to get ahead of the curve and work on projects now, during the lull, so they can be ahead when prices recover. “When resources become tight and expensive, automation can make those resources more efficient,” said Miller. “Under those conditions, automation has more value. But now we have people and resources available to develop assets, even if they’re less efficient. If we get back to where we were a year ago and resources get tight, then automation makes more sense. Automation projects related to safety and regulatory compliance are always going on, but the ones related to improving efficiency will not lead the resurgence of this industry. It will lag somewhat depending on the company and specific situation.”
From cap-ex to op-ex
When capital for investment projects dries up, companies move their activity to smaller-scale operational projects, where they hope to realize higher production and lower costs. Such has been the case during this downturn. “In the general business environment, we have seen a move from cap-ex to op-ex focus,” said Darren Doige, director of onshore oil and gas marketing and business development for Emerson Process Management. “A year or 18 months ago, the primary driver was to bring new wells online as fast as possible and get them connected to the market. That urgency has completely gone away, at least in North America. The Middle East is still going strong, but in the U.S. there is a move to op-ex focus. Operating engineers are now focused on existing wells and maximizing the production from them. They’re also looking for ways to keep production costs and lifting costs as low as possible to maintain the profitability of the limited revenue stream. Operators are willing to listen or complete automation projects when they have immediate impact toward increasing production or decreasing operating costs.” Overall, the oil and gas industry is famous, or perhaps notorious, for being slow to adopt new technologies. Fracking was an exception because it was adopted almost overnight, but more mundane technologies can take a long time. Production companies and their investors are looking at projects very carefully trying to see beyond the current situation–aware low prices could persist. That makes for a tricky analysis.
Boots on the ground
Humans serve as the nodes of these SCADA systems. They tour sites, read gauges and flowmeters, and jot down numbers—as slow and error-prone as that might be. Production facilities are generally farther along in their sophistication, but even they are generally far from state-of-the-art. Vaiciulis said the situation can vary considerably when moving from site to site for different kinds of companies. “For large operators, automation has evolved over the last three years,” he said. “They have done much to standardize and streamline everything, and today, those large operators are where they need to be. But for smaller operators, for lack of a better word, there is no automation and everything is mechanically based. Some may have deployed a small SCADA system, but are not automated to the full extent they could be. I think the reason is because they punched a hole in the ground and got their first oil going, and realized they needed to punch another hole and then another, and soon they were in over their heads. If you go to one of well sites where small, independent operators are leasing the field from somebody else, you’ll see how simple it is. Maybe they have 20 wells scattered over two or three square miles and that’s it. I was at one where they had a flowmeter that runs on a battery. The operator goes to the flowmeter, writes down the number, and comes back the next day and does it again. That’s the data collection. Later they may realize, ‘We need to do something better.’”
What does “better” look like?
The reason such simplicity can continue in this context is because the processes involved are not complex. What comes out of the ground is typically a mixture of oil, gas, and water. Those components must be separated into three streams in a process powered largely by gravity. Wells must be tested regularly to verify what is coming out, and there may be some sort of gas injection system, but the overall requirements do not extend much beyond basic instrumentation and flow control. In this context, one of the more sophisticated extraction technologies is a technique of compressing some of the natural gas and injecting it back into the well to assist with moving oil out of the ground. Increasing the gas side of the two-phase flow effectively makes the liquid lighter and easier to pump. Metering the amount of gas is critical because overdoing the action is counterproductive. Emerson’s Doige said that using these gas-lift systems to their greatest effect requires some optimization. “We can calculate the optimum amount of gas to inject into any given well,” he said. “The constraint is often compressor capacity and we don’t have enough gas to send the optimum amount to every well. We can perform an analysis to optimize the injection rate at the most critical wells to get the greatest benefit for the amount of gas we have. Otherwise, if operators do it manually, the result is far from optimal. In other situations where there are different types of chemical or steam injection processes, it’s a similar application.”
Other relatively simple automation capabilities can make a big difference. Even the most basic SCADA platforms working with a handful of flowmeters and pressure sensors can gather information far more quickly, more accurately, and less costly than operators making rounds. Monitoring the condition of equipment can also streamline operators’ duties. “If you look at the gas compressor at a small site, it’s no bigger than one you’d buy at an industrial supply store,” Vaiciulis said. “If that thing goes down and you don’t know about it, your production may have just stopped, or you’re flaring gas that you could be selling. Who knows how long it may take an operator to get to the site on his rounds? All you need is a system that can tell you it has stopped. It doesn’t have to intervene, it just has to send an e-mail to your smart phone that states, ‘You’ve got a flare event at site such-and-such.’ So you jump in the truck, drive over there, and fix the problem. You keep production up and running, that’s the primary thing.”
Doige said, “We’ve seen more wireless devices being used, not to bring information up faster, but to instrument things that weren’t instrumented. It means field operators don’t have to visit wells that are running correctly just to verify the fact, they can tell from the instruments. Operators have to visit only the wells that have problems, which is the concept of condition-based maintenance. Information comes through a SCADA system and sends an alert via a text message. An operator goes out and deals with the exceptions rather than having to check everything.”
When prices recover
While nobody can predict the price of oil over the next couple years, the consensus is we have seen the bottom of the curve. It may not shoot back up right away, but it shouldn’t go down any further. Maybe that’s wishful thinking, but many seem to be subscribing to the idea. If oil does begin to creep back to $70 or $80 per barrel, what is likely to happen?
Automation projects should begin to move again, and they may look different than they did in 2013 or earlier. Operating companies have learned lessons about standardization that they will use going forward. “The automation industry, across the board, is trying to make everything simpler,” said Vaiciulis. “In oil production, they try to reduce the engineering cost by standardizing Ethernet-based technology and by putting the remote I/O on the equipment skid. It must be plug-and-play. If a customer asks, ‘We’re putting in a 16-well test manifold, and we’re buying two test separators and one production separator, what PLC equipment do I need?’ I can say, ‘You need a well-test enclosure, two test separator enclosures, and one production enclosure.’ That’s it. I just place the order and buy it. The vendor already has the design. It really becomes cookie cutter.”
Operating companies have also realized that unconventional wells act differently and need different systems than in years past. Doige said that systems on older wells might be reconfigured over their life, but the schedule moves much faster now. “One thing that has caught the industry is the rapid decline curve with unconventional wells,” he said. “A traditional well starts off free-flowing, then you put it on gas lift, and later on an electrical submersible pump (ESP). When it’s really low, you put it on a sucker-rod pump. Traditionally, that might take 10 or 15 years. But in some unconventional fields like Eagle Ford, that’s happening within 12 to 18 months. That’s a lot of change to a well site in a short amount of time. A single remote terminal unit can now handle all of those conditions so you may need only one over the life of the well. The instrumentation can remain constant rather than having to change everything when you move from gas lift to ESP.”
As producers consider a world after the oil slump when prices stabilize above $75 per barrel, resources will get tighter and cash will start flowing again. When that happens, investments in automation will return. As Honeywell’s Miller pointed out, “Automation plays a role in keeping operating costs low. Automating a well head means fewer trips by an operator. Companies that have such a philosophy will continue, but they will be selective. The resurgence of automation will likely lag in overall development, but it will play a stronger role as resources get tight and the move to make them more efficient, safer, and more flexible as those aspects are more highly valued, as they were just a year ago.”
Wireless wellhead pressure monitoring
Wellheads scattered across one of western Europe’s largest on-shore oil fields now use wireless pressure sensors to monitor annular pressure. Emerson Process Management has deployed its Smart Wireless self-organizing field network to enable continuous monitoring of wellhead pressure, which indicates well tube condition. Previously pressure was measured by using gages read by operators, once or twice each day. Continuous monitoring eliminates the need for daily visits to the wellhead and enables unusual readings to be identified earlier before faults develop into problems.
Two wireless sensor and transmitters packages are mounted on each wellhead and a single gateway, mounted outside the process area, sends data to the control system where it is collected in a PI historian database for regular maintenance and safety reports. Despite short access periods to the site, it took less than eight hours in total (spread over two days) to complete the installation, including removal of the old gages, replacing them with wireless transmitters, and calibrating. The network was operational within 30 minutes.
– Peter Welander is a contributing content specialist for Oil & Gas Engineering. Edited by Eric R. Eissler, editor-in-chief, Oil & Gas Engineering, email@example.com
Original content can be found at Control Engineering.