Artificial lift providers are responding to

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1 New Technology Focuses on Efficiency, Reliability, Lower Costs Providers strive for improvements in sand control, gas separation, flow range expansion and automation. By Eldon Ball Executive Editor Artificial lift providers are responding to lower oil prices and the pressure to reduce costs by introducing new technology and processes that increase efficiency, improve reliability and lower initial and operating costs. New technology is focusing on expansion of flow and pressure ranges, designs that will better handle increasingly difficult fluids, automation, sand control and integration of artificial lift systems with other forms of production activities. Recognizing the growing demand for artificial lift from the unconventionals market, Schlumberger put together a full-cycle artificial lift offering and has added a number of new technological advances. Two and a half years ago, we put together a strategy to address the trends of the industry, with those trends being unconventional or shale wells and the production challenges that were associated with them, said Kyel Hodenfield, Schlumberger s president of artificial lift for North America. Shale wells typically have a steep production decline. They produce a mixed flow of gas, water and oil, which is difficult, and they produce sand, which is also very difficult. Often, there are corrosion issues and scale issues. And all of those are an unfriendly environment to artificial lift. What we wanted to do was to bring the right solutions to each well for each client. We didn t necessarily have the full offering, so we looked at an acquisition strategy for complete well flow management. As the industry becomes more competitive, it was really critical that we could help our clients achieve their production targets in the most economical way. This required more than just having ESPs [electric submersible pumps] and gas lift. Over a period of 18 months, Hodenfield said Schlumberger acquired 16 companies with locations all over North America and globally. This really helped us become more engaged with the customer after the well had been completed, Hodenfield said. But it is not really about these companies and the hardware but about offering a total solution to the client. It is part of an overall strategy for Schlumberger in the unconventional environment, where we utilize measurements of the reservoir to the drilling, well placement, completion and fracturing process, the well cleanup or flowback, and then on into production. Previously, the first completion would have been the extent of our solution, but now with these acquired companies, we will have engagement with our client for the production life cycle of that well. For unconventional wells, this is often targeted to be 30 to 40 years. Schlumberger is able to advise the client, based on a production forecast, whether they should initially use an ESP, for instance, or start off with a rod-

2 Artificial lift solutions include a wide variety of technologies. (Image courtesy of Dover Artificial Lift) lift system, Hodenfield said. It is very important to take a look at what the client priorities are, because you can have two clients right across a lease line from each other, and one may be much more interested in accelerated production due to cash flow requirements, while the other is looking at a longterm resource play and may be considering an enhanced oil recovery strategy from the initial completion. It s really about understanding what the customer s requirements are, how they want to produce the reservoir, and then selecting the right system to meet their requirements. Even though the oil price has resulted in a reduction in drilling for many operators, the market for rod-pump maintenance and repair and for rod pumps for new wells remains consistent, said Richard Webb, artificial lift manager at DistributionNOW. Our primary core business is to service sucker rod pump shops, Webb said. We have 40 shops in the U.S, which is more than any other company, and we have an additional 22 in Canada. We just got approval to open up our 41st shop in the U.S. for the Niobrara Shale in Fort Lupton, Colo. We have concentrated on expanding into the shale plays over the past five years. We have tripled our business in servicing rod pumps in the Eagle Ford each of the last three years, just because South Texas was not a traditional rod pump play. It had mostly gas wells. Development of fluids lifting in the Eagle Ford also has led to new business, Webb said. A lot of the players that moved into the Eagle Ford came in from offshore, and the operators didn t have experience with rod pumps, so it s been a training ground. We ve done a lot of schools on rod-pumping systems. We ll do probably 15 to 20 more this year. The training covers how to extend rod-pump life. What s most important for the customer now is not the initial cost of the pump, because it s so miniscule comparatively speaking, but keeping it downhole and keeping the whole system working. That s really the concentration in the industry now, with the horizontal wells keeping it in the hole and gas separation. Flow range expansion A trend I ve seen lately is that all the artificial lift types have expanded their operating ranges, said Charlie Fowler, vice president of product technology development at Dover Artificial Lift. When I got into it 20 years ago, you looked at the well conditions, flow, pressure, depths and fluid properties, and that pointed you toward a certain lift type. EPmag.com June 2015

3 That s still true to a certain extent, but the various lift types now overlap a lot more. I think that s partially driven off the fact that the flow conditions in unconventionals change so dramatically over the life of the well. Because of the production changes in unconventional wells, ESP providers are trying to take their product down to a lower flow rate and handle gas and sand better, while rod-pump suppliers are going in the other direction, Fowler said. The rod-pump people are setting them deeper and are increasing the flow rate. Currently, the average ESP is still pumping about 2 Mbbl/d, and the average rod pump is still in the 300-bbl/d range, he continued. Operators are focusing more on initial cost as a result of the decline in oil prices, Fowler said. Before this recent drop in oil prices, the thinking around unconventionals was more about reliability and expanding the operating ranges of the artificial lift, so that you re not changing them out so much, Fowler said. If you re starting off at 3,000 to 5,000 barrels a day and then in only 12 to 18 months you re down to 500 barrels a day, it s a pain in the neck for the operators to install three or four different types of artificial lift in the well in that short a period of time. In the last 90 days they still want the reliability, but we re seeing a lot of pressure to reduce that initial system cost and the need to change over to another form of lift. The ability to run longer under changing conditions will still be a technology driver. They re going to want to put in an ESP and run it at a couple thousand barrels a day and also run it as low as 300 barrels a day. Once a particular artificial lift system has been selected, a lot of design work goes into it. Just putting a generic ESP in an unconventional well is not going to be optimal, because of slugging production, solids and proppant, corrosive fluids, very high gas rates [and] a steep production decline extreme conditions that many ESP designs can t cope with. Optimizing for each particular well is all part of the packaged service, Schlumberger s Hodenfield said. The transition phase includes monitoring, surveillance and the ability to predict the point in time to transition from an ESP to a hydraulic stroking unit, surface beam pump or some other form of artificial lift, Hodenfield said. In today s environment, workover rigs are not always readily available, and clients do not want to wait two weeks for an available rig in order to repair or put a new artificial lift system on a well, Hodenfield said. This is lost production, and if the well is a high-volume producer, this can equate to a large cash flow deficit. The ability to predict ESP runlife will allow our client to schedule a workover at a certain point in the future, reducing lost production to one or two days. We have performed this service in the Eagle Ford, and now we also are providing that service to Bakken customers. Sand control Another trend is that regardless of the type of equipment, rod lift or ESP, the system has to handle sand better. There are two approaches to handle sand, Fowler said. One approach is more passive and utilizes some kind of nonmoving device to separate the sand before it enters the ESP or rod-pump intake. There s a lot of work being done by Dover and others on stopping the sand before it enters the pump. These devices certainly help the situation; however, sand is still going to get into the pumps. People are working with the geometry and materials of construction of their equipment, Fowler said. With an ESP, it s a centrifugal pump spinning at 3,500 rpm, and it can generate a lot of wear. Generally, centrifugal pumps don t like sand, and they don t like gas; the same with rod pumps. Our Harbison Fischer pump team is constantly developing new materials of construction to handle the abrasives better and different configurations to handle sand better. Those issues are receiving a lot of focus now. In addition, one of the new technologies that Schlumberger is most pleased about is its REDA Continuum unconventional extendedlife ESP, which provides continuous operation over a wide production range and increased sand-handling capabilities. That s important because the unconventional wells can decline 60% to 80% in the first year, Hodenfield said. Most of the time ESPs are designed to operate at a somewhat narrow production range. It is not uncommon to have an older-generation ESP designed for a range of 1,400 bfpd [barrels of fluid per day] to 900 bfpd. The Continuum extends that range

4 from 1,400 bfpd down to 200 bfpd. Extending that range becomes increasingly important as our clients are improving their initial flow rates by 30% to 50% each year. There are a number of efficiencies that go along with that. The most difficult environment for unconventionals is probably in the Bakken play in North Dakota. This is where we are having a lot of success with the Continuum. The first one was just installed in third-quarter It s been operating for over 200 days, and it s still working in a well where the production has declined 77%. For certain difficult areas of the Bakken, it is significantly improving the ESP run times. Another difficulty for unconventionals is multiphase flow, Hodenfield continued. We are pumping a slurry of four phases; in addition to gas, water and oil, we are producing sand. Sand is what most often causes other ESPs to fail. It either erodes the stages or destroys the bearings. We have a technology with an enhanced protection front seal on the bearing. This, along with the enhanced capability to pump sand, is what extends the life of the pump. The fact that this pump lasts longer relates back to the need for a wider flow range. There are two Continuum ranges that have been commercialized with a third on field test across the flow rate of 7,000 bfpd to 200 bfpd. Schlumberger also has a new product called a hydraulic stroking unit, which offers the longest stroke in the industry 336 in. This is another form of transitional artificial lift, where we can go from an ESP into a hydraulic stroking unit, and the hydraulic long stroke unit offers many advantages over other units. One is cost. It is significantly less expensive. The second is that it is very transportable. You can take it down in three or four hours and move it to another well, Hodenfield said. Gas separation Gas separation is a major issue for the industry in producing unconventionals, DistributionNOW s Webb said. There are probably 10 different kinds of gas separators out there now, with every manufacturer making one. They work, but none of them gets all the gas separated before it gets into the pump. You just can t do it. You re going to have to make your pump produce gas. You used to have wells where you could stick the pump down beneath the perfs, but there aren t any new wells like that. With all the new wells, the perf is around the corner, so gas and all the solids have to come by the pump intake. That s an area where we re still looking for better technology, but it s just a fact that whatever room you have with your volume, casing and tubing size, you don t have much room in a certain distance to get the gas to separate. We re still looking for the next best thing, Webb said. As a board member of the Artificial Lift R&D Council, Webb said they have a meeting every year, inviting oil and gas companies and vendors to describe their latest development. It s called the Seminar for New Artificial Lift Technology, and this year s meeting took place on May 12 in Houston. The idea is that maybe one of the oil and gas companies or service companies will invest in them and give them a chance to advance the technology. If somebody comes up with the premier performing gas separator, they ll be very successful, Webb said. Neither ESPs nor rod pumps are known for handling high concentrations of sand and gas particularly well, but they re getting better, Fowler said. ESPs are doing things with the gas separator designs, geometry of the pump stages and the control systems to handle gas better, he said. If you experience some gas or some cavitation, the control system picks up on it and can speed it up or slow it down. It s the same thing with rod pumps. Some pumps have unique geometry and configurations that are tailored for handling gas slugging. Through-tubing deployment Although its name might imply it s only a provider of ESPs, AccessESP provides a much different service, said Todd Wray, vice president of marketing and sales. We have integrated two practical technologies into a unique solution that radically simplifies the conveyance of ESPs without the use of a rig, Wray said. Our clients maximize the value of ESP wells with significantly lower intervention costs, minimal lost production and fullbore access to the reservoir. Traditionally, ESPs are deployed with the tubing, with the electrical cable mounted on the out- EPmag.com June 2015

5 side. If there are any challenges, if you need to resize the pump, if there s an issue downhole with the motor or anything else, or if you just need to get below the pump, it s very difficult, because it s attached to the tubing. So you have to pull the entire tubing string, and that can be cost prohibitive in certain areas. AccessESP provides a through-tubing ESP deployment and intervention solution, Wray said. We are not an ESP company. We don t market pumps, intakes, variable-speed drives etc., and we don t provide cable installation and penetrator services. We provide our clients with the ability to install and retrieve their ESP through slickline, wireline or coiled tubing. Ultimately, our objective was to be able to deploy with the smallest operational footprint possible, which is slickline, because the vast amount of rigs and locations around the world have slickline readily available. We wanted a deployment solution that allowed our clients to use the existing equipment that s available everywhere. Standard slickline, standard lubricators and a crane are all you need. What we ve done is reduce both the time that it takes to acquire and mobilize a rig to pull the tubing as well as the costs associated with it, Wray continued. Now we re able to install and retrieve an ESP very quickly with a light operational footprint. We re minimizing or eliminating the amount of time that your well is down because of a nonproducing ESP. In offshore or remote locations, that could be 60, 90 to 120 days of no production, because if the ESP s not working, you re not producing, and it could take that long to get a rig. Other costs are associated with mobilizing, setting up and performing the operation itself. By focusing on minimizing downtime and decreasing the intervention costs, our through-tubing system is going to make wells that are on ESPs more economically practical. In the future, it makes an ESP more practical for clients who believe that interventions and the use of ESPs could be cost prohibitive, Wray said. A cut-away view of AccessESP s rigless ESP conveyance system is shown. (Image courtesy of AccessESP) It s now possible to deploy an ESP through 4½in. tubing and produce up to 6 Mbbl/d, he said. We use conventional pumps, protectors [and] intakes that most ESP industry providers have, so we don t require anything special, Wray continued. We incorporated industry accepted, tried-andtrue technologies into our solution. The system is a combination of two elements. The first is our permanent completion, which incorporates the side-pocket wet connect. The wet connect is very similar in the basis of design to a gas-lift mandrel, except that it s an electrical connector. The permanent completion is integrated into the tubing string, and the power cable is installed in a similar fashion to traditional ESP installations. The second is the retrievable assembly, which consists of our female connector that mates to the side-pocket connector downhole, completing the electrical circuit, providing power to the permanent magnet motor. Permanent magnet motors have a much higher power density than induction motors today, Wray said. Today, if you needed 130 horsepower to drive the pump on an ESP and you wanted to do it with a 3.75 OD [outer diameter], which means it can be deployed through tubing, that 130 horsepower pump s going to be about 50 ft long, he said. For us, that pump is 9 ft long. Additionally, you ve gone from 1,900 lb down to 250 lb. Our permanent magnet motor makes it practical to deploy through a lubricator, which allows us to perform live well ESP deployments with a slickline unit. The permanent magnet motor and the sidepocket wet connect are the two practical technologies that make the system work, Wray said. Unique to our design is that when the retrievable assembly is not in the hole, the ESP is not in the hole, Wray continued. You have fullbore access to the reservoir. You can run squeeze tools, coiled tubing, PLTs [production logging tools], do wireline perforations or whatever you want below the assembly. The convenience and cost savings [come from] being able to

6 do a multitude of intervention operations with fullbore access. It s exciting, and we have had proven success with this technology and expect to see this solution gain widespread application in the future. Supplier decision role Dover Artificial Lift s Fowler also sees a trend toward more access to data and more decision making by the supplier. Fifteen to 20 years ago in the initial stages of automation, customers were more protective of their data, Fowler said. They didn t want the artificial lift provider getting too much information. There was a reluctance to let the artificial lift provider monitor the well. We might put the sensors in, but the data went to them. The trend now is to let the artificial lift providers monitor the wells for them. We re starting to hear customers say, Look, help us manage it, or you manage it for us. If your data are telling you to speed it up, slow it down, or shut it off, go ahead and do it. Just send us a note that you ve done it. There s increasing trust in letting the service companies watch the well closely. As monitoring and data collection increase, the supplier can provide well data in addition to artificial lift equipment data, an added benefit to the operator, Fowler said. When we first got into monitoring, we did it to protect the AL [artificial lift] equipment, he continued. The more we got into it, we started to monitor the well also. It s kind of a hybrid now. You re looking at what the equipment s doing, but you re also looking at what the well is doing. Our people now can get text messages [from the control systems], and they ve got the ability to go on their iphone and speed it up or shut it down. Remote surveillance centers allow Schlumberger to monitor and control artificial lift systems globally from centralized locations. We have a real-time surveillance center in Scotland that manages about a thousand wells across the North Sea and Africa, said Chad Bremner, president of KUDU Industries, a Schlumberger company. It s real-time surveillance, so that engineers and operators can sit in a central room and monitor wells 24 hours a day. Our clients are paying us to monitor these wells and to be reactive to them. If there s any issue with high temperature or high vibration, for example, we can be reactive to that. With that capability, you can reduce workover costs, especially offshore, where it can be very expensive. We can actually speed up or shut down a well at a remote location. And we can communicate with a platform in the North Sea, for example, contact their control room, and they will make the adjustments. The LiftWatcher real-time surveillance service provides around-the-clock surveillance of all artificial lift systems, monitoring of well conditions, and preventing or resolving downtime or system failure, Hodenfield said. Our flagship real-time surveillance center in Houston monitors PCPs [progressive cavity pumps], beam pumps and ESPs. Remote surveillance centers allow Schlumberger to monitor and control artificial lift systems globally. (Image courtesy of Schlumberger) EPmag.com June 2015

7 The remote control capability is very critical, especially in unconventionals. In severe or extreme conditions, there have been up to 15 manual adjustments per week. That is an indication of how fast the well conditions can change. The centers provide a staff with a wide range of backgrounds: completion engineers, production engineers, reservoir engineers and petrotechnical engineers with reservoir knowledge. We look at other parameters and indicators in addition to the ESP functions, such as casing pressure, tubing pressure and the flow rate that the gas is being produced up the annulus, such that we can be optimizing the production all the time. Schlumberger also can produce a pseudo well log and calculate a flow rate from our ESP. That is a new service that we have just launched in the last couple of months. Gas lift Adapting gas lift as a way of dewatering fracked wells eventually led to using it to produce fluids, said Kelly Raper, vice president of sales and corporate development at Priority Energy Services. That, in turn, led to reduced production costs. We started out doing gas lift in the Barnett Shale, he said, and we had some customers calling us and saying, We re fracking these wells with a couple of hundred thousand barrels of water. We re swabbing them, and we can t get these wells to flow. Can you come help us? That led to the idea to use gas lift to dewater the wells. We re actually the ones that first started running gas lifts in shale plays, Raper said. After gas prices tanked, everybody started using that same technology to develop oil plays, so we ran tons of this equipment in the shale plays when they were primarily gas plays. We started out just basically dewatering the frack so the wells could flow. That was the concept behind using gas lift to produce liquids, he said. Now that they ve gone to liquids, we re in the Eagle Ford, the Permian, the Niobrara, still in the Barnett, and we re up in Oklahoma. A lot of these places previously didn t run gas lifts. Now it s become the preferred form of dewatering the wells and then producing them with gas lift, whereas a lot originally went to pumping units immediately. The problem operators faced was that many of the wells were seeing gas locking, and they really couldn t rod pump efficiently, Raper said. So they circled back, and now we re starting to run a lot of gas-lift systems. That s in West Texas, the Niobrara and the other [areas] I mentioned. Raper said that Priority is focusing on reducing lifting costs. We started doing this before oil went to 40 dollars a barrel, he said. We looked for the most efficient system for a customer s well over a period of time to reduce lifting costs per barrel. Everybody drills five or six wells on a pad. We would put a compressor on each of these wells and gas lift. Then as the wells start to decline, we can start taking compressors off, and eventually we get down to maybe one compressor. Since compressors rent for about $5,000 a month, taking them off created a cost-saving scenario for the operator, Raper said. We ve been able to go to what I call a hybrid system, with one compressor where we re gas lifting with a plunger in it. We re using the gas-lift systems in place to lift the plunger. That s the second phase of how we lift these wells, he said. The company has tweaked the system to create greater efficiencies since originating it, Raper said. It s basically intermittent lift, where we re running a plunger to catch fallback, because in most of these wells if you re intermitting it, you lose about 8% of the head per 1,000 ft, he said. [If] you have an 8,000-ft well, the plunger s catching a lot of that fallback because it s slugging, so we re able to produce the wells with the plunger. They still make some gas, so there s still gas locking the pumping unit, and they weren t really ready to put on a pumping unit. Another problem is scale and paraffin. Depending on the area, we ve set a plunger just below the paraffin line, and we trip that plunger with the gas-lift system two or three times a day just to wipe the tube and keep the paraffin out. The process can reduce capex significantly, Raper continued. We re saving a lot of capex being spent in the initial phase by doing this, because a gas-lift system and a plunger-lift system are a lot cheaper than putting in a rod pump. And if you re gas locking it or if you have paraffin problems, then you have rods parting and other complica-

8 tions. We re able to bridge that gap before someone has to spend a lot of money on a higher priced system, he said. As the production starts to decline, the compressor also needs to decline, he said. If you have a three-well pad and we re gas lifting all the wells, then each well has to have a compressor for the amount of gas and volume it s going to produce. As the wells start to decline, some will go to plunger lift assist, and we don t need a compressor for each well. We can take a couple of compressors off, and that reduces their cost by $10,000 per pad, Raper said. When you multiply the savings of one pad by the number of pads being produced, the savings can be very substantial, Raper continued. We have a customer that we ve done this with, he said. Theirs are primarily three-well pads, and they ve done this to 50 pads. That s $500,000 a month, and they re maintaining their production. As everybody becomes educated on what we do, generally they know they re going to complete the well with gas flow initially, so they call us out about the time they re going to do the frack. Some of the customers give us their frack schedule and plan accordingly. Well profiles show the rate of corrosion (left bars) and wall loss (right bars) by joint at precise depths. (Image courtesy of NOV) Optimizing performance National Oilwell Varco s (NOV) Artificial Lift Technologies (ALT) group has the goal of optimizing performance, protecting assets and managing production costs, all to serve operators during a period of price erosion, said Matt Davison, product and engineering manager at NOV. Because of the oil price, this is a time when mostly everyone wants to optimize their wells, Davison said. Operators want their equipment to last as long as possible. Some want to optimize and make the well last longer, and some are cutting costs and only want to put the necessities downhole. Mostly, they want to mitigate wear so that they don t have to replace tubing and rods. Asset protection is critical as highly corrosive environments and wear caused by contact between sucker rods and production tubing can damage the production string, Davison said. With rod-lift pumps, you often can have metal-on-metal contact of the sucker rods and the inside of the tubing, and you get a lot of wear over time. You also can get corrosion, which results in pitting. Either way, you get tubing wall loss. Wellchek, an NOV service, scans the tubing as it s being pulled from the hole, identifies corrosion and wear, what percent and the exact location in the well, Davison continued. We also have other services, such as rod guide calipering, he said. Rod guides are commonly used to keep the metalto-metal contact down. A rod guide consists of plastic that is positioned around the sucker rod to keep the rod from direct contact with the tubing. EPmag.com June 2015

9 The idea is that the plastic wears out before you get the metal-to-metal contact, which protects the metal and makes the tubing and sucker rods last longer. The rod guides come out of the hole with some amount of wear. We measure them and use that information to make recommendations about replacing them. NOV provides that service along with predictive software and the Rod Guide Advisory Program, an internal advisory program. We combine the data we get from WellTrack, a database that stores all the data from WellChek, the calipering services, along with the predictive software that we use and any failure history. Our internal software was built from empirical data over the past years to help predict and recommend the number of guides you Created by the latest version of the Rod Guide Advisory Program, a 3-D representation of a sample well is shown. (Image courtesy of NOV) downhole, Davison said. We want to protect not only the tubing but also the sucker rods, he said. Pitting can easily lead to a break, which leads to downtime, lost production and requirement for equipment replacement. Once we get to know our customers and know their wells, we can start to see trends or characteristics that are common to wells in a specific area. We can standardize on a procedure after we have analyzed enough wells. We use the data that we collect and we also get well data from the customer. We have to know what s in the well. Sometimes with a new well, we help design it from scratch. And most companies are very open with sharing the data on a well-to-well basis. Rod rotators and tubing rotators are also a way of distributing wear, Davison said. We combine all those as needed to work toward our customer s goal. Our overall goal is to become a partner with the operator and help oversee, track and bring continuous improvement. That s why we have the software in place to help track failures and track problems. need in the well, where you need them, what style of guides and what type of material, depending on each application, he said. The ALT group of engineers analyzes the data and makes recommendations based on its analysis. Once we re through with the consulting phase, then we can start recommending products, Davison said. We also have our Tuboscope internal plastic coatings that we use to line the inside of the production tubing. This can be for corrosion, paraffin, wear or for better flow properties. Some liners are mechanically applied, some are liquids that are sprayed in and cured, and some are epoxies. NOV also supplies coatings to sucker rods, since corrosion will attack anything that s metal Lift design A recent ESP change-out by Baker Hughes demonstrated the new approaches to pump design, expansion of flow ranges and an innovative solution for producing from deviated wellbores. An operator had experienced multiple problems installing and operating ESPs in a horizontal well in the Permian Basin. Part of the problem was that the kickoff point for the curve section of the well exceeded a buildup rate of 12 degrees per 100 ft, which led to mechanical issues with getting an ESP successfully through that high buildup rate. Baker Hughes was able to provide an ESP for deviated wells that uses boltless connections between the ESP components. Unlike bolted flanges, the boltless design allowed

10 the equipment to pass through buildup rates up to 25 degrees per 100 ft. The system was set deeper in the well and closer to the producing zone. The ESP system included a new pump design that can operate at flow rates from 3,000 bbl/d to 50 bbl/d, a flow rate the company describes as the industry s widest flow range for a single pump. Moreover, DistributionNOW s Webb said that after f lowing, most wells will go on a combination of rod pump, gas lift or ESP applications. However, about 90% of the liquid-rich shale plays in the U.S. will be on rod pump at some point. DistributionNOW serves that demand. We don t manufacture the pump parts, Webb said. We buy the components and work with the engineers to design the pumps. In all the shale plays, they ve gotten pretty much standard with certain things that we know work. We also rebuild them. The thing is, it s not [as much about] that first pump that you put in the ground as it is learning about the pump when you pull it. When we get the pump out of the well, we immediately get back to the shop, tear it down [and] take pictures. If there s paraffin in it, or scale, or they ve been beating the pump up because they ve been tagging bottom, we get the pictures back to key personnel as quickly as we can. If the operator has to change chemicals because they didn t know they were getting the scale, for example, that s a key to our service. As a company that rebuilds, you ve got to be able to communicate to your customer what you see after that pump comes out of the hole. There s more opportunity in this down market to gain market share if you re the best at doing that. Our target is that they don t have to pull a pump more than maybe once every five years. In new wells in the Eagle Ford, that s not realistic. But from day one, you have to start setting a target of how you extend the run times. Some people never kept track of that before. Now pretty much everybody has to look at that. Design of the pump depends on where the company wants to put it, Webb continued. Most of these pumps we re putting above the kickoff point, he said. At some point, they re going to have to go into the horizontal section if they want to get all of the production possible out of the well. But in the early stages of the shale plays, most pumps go in above the kickoff point. Some people put it partially into the curve. We believe that is a big mistake, because if you re in the curve and you have the plunger barrel where it s going to shorten the life of the pump [then] you d only get about 30% out of the life of the pump. These are long-stroke pumps, so if you re there in the deviation, there s a good chance that the barrel is in a bind at some point. In that case, you ll be wearing the plunger to the barrel, and it will wear out much faster. The design also comes from how much fluid the operator thinks it s going to have to move and how much gas it may have to deal with, Webb said. Like with some, we start out with an inch and threequarter pump, he said. By the time they pull the well the first time, we usually go back with an inch and a half, because their fluid has already dropped off. That s typical with most companies. However, in the Niobrara, they start out with an inch and a half, and after the first pull, they go to an inch and a quarter, because they have less fluid. That s not true of every well, but it s generally true. As to general business conditions, we ve had customers slow down; however, there is still new business. I don t expect it to drop unless it stays like this for six months. If the price comes back, like it did in 2009, I ll just consider it a healthy cleansing. I don t think it s coming back like it did in I think we re in for a little rougher haul, but for us there are a lot of new wells that will be going to rod pump, so there s new business for those. Heavy oil challenges Heavy oil production brings its own set of challenges, and Bremner said Schlumberger is advancing technology to deal with those issues. About 15 years ago, the SAGD [steam-assisted gravity drainage] market was really beginning to grow in Canada, Bremner said. To summarize the overall problem, it s that you have to heat cold water to create steam to pump into the well and then heat the reservoir enough to produce the fluids. To be cost effective, you want to pump heat into the ground and not hot water. The ideal situation is low reservoir pressure, EPmag.com June 2015

11 which is the opposite of a conventional well, so that the steam stays in a vapor phase and the heat moves around the reservoir and doesn t go down the producing well, Bremner said. To do that, you have to introduce artificial lift downhole, and the flow rates of some of these SAGD wells are quite large. Some of the highest ones are around 10,000 barrels a day. Clients wanted to see if they could operate an ESP at a temperature of over 150 C [302 F]. That may have seemed a little crazy at the time, but there were a few clients who were willing to take the risk. So, we started developing it, and we re on our fourth version now, called the REDA Hotline SA3 high-temperature ESP system, he said. Over time this has become the main technology in SAGD, Bremner said. Other technologies have been added over time, Bremner said, but the ESP is the biggest one. The product that KUDU has is an all-metal PC [progressive cavity] pump. It doesn t have any elastomer in it. The ESP is rated to 250 C about 480 F and for a PCP you re looking at 350 C, or about 660 F. SAGD wells are fairly shallow, so it s not a matter of how much differential pressure is put downhole; it s whether the pump can handle the temperature and the amount of gas, Bremner said. If you look at the end view of the reservoir, you have two wells, one above the other, with the steam chamber. Then if you look at a pad, you have these steam chambers side by side. Then there s a triangle, a wedge, between the two producers that the steam chamber is not hitting. In between the two wells, you can t produce that oil, because the steam isn t getting access to it. So clients now are drilling what s called a wedge well. That goes in as a horizontal producer. They re not putting an injector in, but they want to reduce their drilling costs, so they re going in with a much smaller wellbore and casing than they were with the primary producers. We didn t have technology to go into those smaller wells, such as 7-in. casing and liner, so we had to change to a smaller OD. That was another project that had its own challenges, but we developed a slimhole hotline ESP as well. It s really become a stable product for us in Canada and around the world for thermal projects. Demand still strong Although operators have reduced spending on new wells, Fowler said that Dover still sees a steady flow of artificial lift requirements for existing wells. The artificial lift industry is riding a bit of the wave on wells that have been drilled and completed, Fowler said. Some operators are going to complete them and bring them on, while others are not. Our focus will continue to be on superior service for these new wells and existing wells. We ll also focus on leveraging the flexibility that our jet-pump systems provide. The production business never drops quite as much as drilling, Fowler said. As long as they re producing, they re going to need to replace artificial lift equipment. So we never quite feel the effects as much as the drilling side. For example, if drilling drops 40%, we generally drop 20%, he said. Fowler said he sees an opportunity to better integrate the artificial lift system with production chemicals treatment. There s a lot of chemical treatment that goes on to deal with paraffin and scale, both of which can result in early failure of an artificial lift system, he said. I don t think at this point any company has successfully integrated those things. In some ways, we ve not convinced the production companies that integrating these provides value. Our ichem service is demonstrating that value and gaining traction by reducing the cost to the end customers. In a nutshell, artificial lift technology will continue to focus on more automation, more expansion of flow and pressure ranges, designs that will better handle increasingly difficult fluids, and integration of artificial lift systems with other forms of production activities such as chemical treatments, Fowler said. An often overlooked area is application engineering. For the future, good application engineers may be as critical as, or more critical than, the hardware itself, Fowler said. Oil and gas wells have a unique personality. Someone who understands a particular well and can say, This is the right lift for this well based on these conditions those people will be in high demand in the future, Fowler concluded. n HART ENERGY 1616 S. VOSS, STE. 1000, HOUSTON, TX USA FAX