Outside of quantum physics, technically nothing is unpredictable. Even so, two years ago when analysts claimed the shale industry couldn’t sustain itself in sub- $60/bbl oil, few could have seen what lay ahead. And even fewer could have guessed the extraordinary growth in shale production would happen so rapidly.

There are several indicators that can identify when, exactly, the oil market bottomed out. By most accounts, rock bottom occurred sometime between January 2016, when West Texas Intermediate dove to $29/bbl, and the end of May 2016, when the U.S. rig count fell to 404 active rigs. Two years later, thanks primarily to an unexpected (but technically not totally unpredictable) boom in the shale industry, the U.S. is now a net oil producer, and rig counts have climbed back to 2015 levels.

According to Baker Hughes, the number of operational rigs in North America increased 124% in one year between May 2016 (404 rigs) and May 2017 (908 rigs). The reason for the sharp increase is almost exclusively due to the rise of shale production. More than 40% of all operating North American rigs are located in the Permian Basin—the epicenter for the shale boom.

Those additional rigs in shale plays have led to substantial increases in oil production, with the U.S. now producing 9.3 MMbbl/d, a figure not consistently achieved since the late 1960s and early 1970s.

The reason behind the U.S. oil production resurgence in a sub-$60/bbl economy is rooted in the concept of survival. To survive, companies needed to find a way to produce oil in challenging shale reservoirs in a more economical way. The tools and systems featured in E&P’s shale technology showcase represent some of the latest efforts companies have made to push North American production even higher through more efficient processes, deeper wells and longer laterals.

Editor’s note: The copy herein is contributed from service companies and does not reflect the opinions of Hart Energy.


The Model 5400 Dynamic Scale Deposition Loop from AMETEK Chandler Engineering is a fully automated system that measures and evaluates the performance of scale inhibitors under the HP/HT conditions found in oil production. The system pumps precisely heated oil samples at known rates through a tubing test section while continuously measuring the differential. An increase in differential pressure serves as an indication of scale formation, and the test is completed once that differential pressure reaches an adjustable threshold value. The system features a highly precise forced air convection oven, removable sample and preheat tube assembly, external pH electrode with sample, and Hastealloy C276 sample tubing and fittings inside the oven. System hardware includes two manual set point backpressure regulators (high or low range) that are used to create the sample pressure inside the test section during pumping. Two high-performance liquid chromatography pumps are used to transport the fluids through the tubing, both with switching valves (6-port) for various anion, cation, scale inhibitor or cleaning fluids. chandlereng.com


Gas handling is among the most complex challenges for electric submersible pumping (ESP) systems. While ESPs can produce some gas, large volumes can create reliability concerns for conventional systems. The challenges are exacerbated by long horizontals in unconventional oil plays. Gas slugs that accumulate in the high side of undulations in the lateral section and then break free can cause gas-locking conditions. The gas slugs could then shut down the system and/or pump cycling, which can lead to motor overheating. Baker Hughes’ CENesis PHASE multiphase encapsulated production system fully encapsulates the ESP in a shroud to naturally separate gas from the fluid stream before it can enter the pump. The system is designed to help stabilize production rates, improve efficiency and eliminate reliability issues. The shroud provides a reservoir of fluid to keep the ESP operating during gas slug events, while a recirculation system keeps fluid flowing past the motor to mitigate overheating. The system has proved successful in more than 1,000 installations. Recently in a horizontal well in the Delaware Basin, installing the system enabled an operator to increase oil production by 48% and increase reservoir pressure drawdown by 40%. Motor temperature was reduced from 80 C (176 F) to 75.5 C (168 F). bakerhughes.com


There is no shortage of challenges that need to be overcome when oilfield operators produce unconventional shale wells, but identifying the best artificial lift technology to combat these challenges can be difficult. In the Bakken region, a Dover Artificial Lift customer was trying to produce an unconventional shale well with multiple deviations, high gas-liquid ratios (GLR) and solids production. The customer tried using two different methods of artificial lift, but the systems failed every two to four months, which cost thousands of dollars in downtime. Determined to find a better solution, the customer decided to try a gas-lift system. Because the moving parts of a gas-lift system are mounted on the outside of the tubing and are not exposed to wellbore fluids, the system is not affected by solids production or deviations. Moreover, gas lift closely mimics a naturally flowing well, so higher GLRs will actually improve the system’s operation. Dover Artificial Lift installed a gas-lift system and a compressor on the well, and the well has been running for 18 months without interruption, saving about $200,000 in downtime. This case illustrates that, because of its flexibility, gas lift can be a solution to address the operational complexities that are common in unconventional shale wells. doverals.com


An automatic tank gauging method from Emerson that uses guided wave radar and wireless technology is reducing operator risk while providing more accurate measurements of inventories. The new system is now acceptable for crude oil custody transfer from small lease tanks per the American Petroleum Institute’s MPMS Ch. 18.2 standard. The tank gauging technology complements Emerson’s tank manager application, which enables management of the entire custody transfer process—automating haul tickets, uploading to production accounting and allocating produced fluids back to each well—for a more accurate audit trail. Automatic tank gauging is an improvement over manual tank gauging, a labor-intensive process with considerable safety risks given that measurements often are taken during harsh weather and could potentially expose operators to toxic vapors from open hatches. These processes are also subject to measurement inaccuracies and production losses. For example, a 1% error in tank gauging on a typical shale production well represents an annual fiscal exposure of $164,000. Automatic tank gauging provides continuous insight into actual inventory levels and minimizes loss by offering oil and water interface detection. Information is wirelessly transmitted to control rooms where operators can remotely access measurements, full configurations, advanced diagnostics and troubleshooting tools. emerson.com


ENERGES Sand Management uses traditional and emerging technologies to provide a full range of de-sanding options. ENERGES uses dual cyclonic sand separators with engineered inserts for second-stage solids separation to create additional fine sand “fall out,” and the sand filter effectively eliminates the carryover to deliver solids-free production. Several tests were conducted on customer sites to measure the effectiveness of the sand management system. Two dual-cyclonic sand separators were used to combat the 100-mesh sand returns. Acoustic monitoring sensors downstream of the second sand separator were registering that 10% to 25% of entering sand was still carrying over. After installation of the sand filter, sand production downstream of the filter registered zero and was confirmed by checking the production separator. In addition to the successful removal of fine sands, choke sizes were increased while maintaining 100% sand removal. This ramp-up in production shows the filter’s ability to handle high flow rates while maintaining de-sanding efficiency. These technologies mitigate production equipment damage from sand and reduce frequent well shut-ins for maintenance, keeping production online. energes.com


Flogistix LP, a gas compressor manufacturer and well optimization service provider to the domestic onshore oil and gas industry, has released its newest software, Flux. Flux provides real-time insight into compressor unit performance and gives companies enhanced transparency. The system also offers the ability to identify longterm trends, ultimately reducing one of the industry’s main production challenges: downtime. With Flux, Flogistix guarantees a run time of 98%, proven through real-time telemetry, run-time statistics and maintenance history. This is accomplished by capturing changes in the state of a compressor and representing these events on a time line with other vital sensor data, providing context and insight to the user. The ability of Flux to capture real-time data and long-term trending makes it a tool for optimization. flogistix.com


Flowco Production Solutions has recently released its plunger lift-assisted gas lift with automation. This new application of existing artificial lift techniques along with advanced automation software algorithms and monitoring has helped reduce operating costs and improve the production of horizontal unconventional oil and gas wells throughout the world. Specifically, North American E&P operators are experiencing huge benefits of commingling gas lift and plunger lift without the high workover costs of any select pump apparatus—considering that gas-lift and plunger lift systems are the only two artificial lift systems that marry well together with long-term benefits in both oil and gas wells. The application of plunger lift-assisted gas lift coupled with automation has allowed the industry to reduce operating costs and extend the life of rapidly declining horizontal unconventional oil and gas wells. This new artificial lift has improved the way a gas-lift installation operates in the life cycle of a rapidly declining shale well. It also allows the operator to maintain the ability to handle high gas-liquid ratios and sand/solids from the well with no problems, unlike other forms of artificial lift. The system is designed to prolong the need for artificial lift conversion to positive displacement pump and reduce the operator’s monthly well costs by optimizing compression. Horizontal wells are not an issue for plunger lift or gas-lift systems as experienced with positive displacement pumps. The deep lift opportunity of Flowco’s applications helps increase profit margins on product sold by reducing operating costs, reducing workover costs for repair and maintenance and increasing production. flowcosolutions.com


Never before has oil and gas equipment been subject to such abrasive conditions as found in modern horizontal drilling and multistage fracturing jobs. During these challenging completion operations, surface wellhead equipment needs to be efficiently protected from high-pressure, high-volume conditions. Greene’s Energy Group recommends the application of isolation tools to protect the wellhead equipment from high pressures and abrasive materials as well as protecting personnel operating at surface from unplanned pressure events. Greene’s Guardian Wellhead Protection tools allow operators to fracture directly through the existing wellheads, eliminating the need to kill the well and reducing the possibility of sand and erosion, which causes valves to fail during the operation. There are three different versions of the tool system that seal off in tubing, casing or the wellhead. The Tree Savers use hydraulic cylinders to insert the main mandrel of the tool through the tree and wellhead bore and sealoff in the tubing inside diameter (ID). The Casing Savers use hydraulic cylinders to insert the main mandrel through the tree, wellhead bore and seal-off in the casing ID. The Stage Tools use a hydraulic single screw to insert the main mandrel through the tree and seal-off in the wellhead bore. The average installation or removal time is 30 minutes, and the use of wellhead protection technology can eliminate costly repairs to conventional rental fracturing trees. greenesenergy.com


Halliburton provides time-saving analysis through new technologies. Accurate diagnostics are critical to help keep projects on budget and on time. The Acoustic Conformance Xaminer (ACX) and Electromagnetic Pipe XaminerV (EPX V) services help operators quickly find a leak’s location and describe the extent of the damaged pipe that needs fixing. Halliburton created the flow imaging tool ACX, which locates and images flows behind pipe(s) and is primarily used for flow assurance, well integrity and well leaks. The tool can map fluid flow around the wellbore, including in between annuli and throughout the completion. Well leaks are very costly to production returns, including the cost of locating and repairing them. There are several operational techniques for narrowing down a leak’s location. However, these can be time-consuming and might not fully explain what is occurring. When corrosion is a problem, the EPX V pipe inspection tool quantifies metal loss in one to five concentric strings of pipe in a wellbore using accurate high-definition (HD) frequency technology. The tool helps customers examine the whole well in one trip and assess pipe condition. The EPX V operates by inducing HD frequency electromagnetic energy into the surrounding pipe, which propagates through the concentric well strings with no wellbore fluid influences. The interaction with the metal of the pipe returns signals to the tool, yielding information about the state of metal loss in each pipe. halliburton.com


Deep, high gas-rate horizontal wells are known to experience excessive gas interference. The large pumping capacity of the electric submersible pump (ESP) makes it the artificial lift system of choice for deep high-rate wells. In ESPs, however, gas interference frequently overheats the motor, resulting in excessive shutdowns and premature failures. HEAL Systems Horizontal Enhanced Artificial Lift, or HEAL ESP System, is a downhole flow conditioning artificial lift technology designed to smoothen and suppress slug flows and resulting in improved ESP performance. The HEAL ESP System incorporates an encapsulated shroud. A vortex separator discharges gas to the annulus and intakes liquids into the bottom of the encapsulated ESP shroud. Liquids flow past the motor section to provide cooling and then enter the intake section. ESPs can be equally challenged with maintaining critical velocity and corresponding pump efficiency. To address critical velocity, the annular area between the encapsulated ESP shroud and the casing is designed to achieve the expected gas rates without entering the critical velocity region. The HEAL ESP System manages challenges exacerbated by small hole size, allowing the benefits of slug flow suppression to be achieved in small casing sizes while achieving low pump intake pressures. This results in increased production with reduced capex and opex. healsystems.com

The HEAL ESP System is a downhole flow-conditioning artificial lift technology. (Source: HEAL Systems)


Hexion’s OilPlus advanced proppants are field-proven in more than 1,000 wells, with 1 billion pounds pumped in major basins throughout North America. By increasing the relative permeability of oil in the proppant pack, OilPlus proppant users can produce better wells. This includes improved IP, higher cumulative production, reduced cost per boe and higher return on investment. Recent production data studies have proven that OilPlus proppants outperform traditional resin-coated proppants. A 24% increase in production was shown in the Permian Basin. A 24% production increase was shown in the Bakken Formation. And a 28% increase in production was shown in the Eagle Ford Formation. Each case study focused on a single operator using similar fracture designs, and a comparable number of wells were used over long periods of time under similar downhole conditions. Upfront investment of about $30,000 for an 11% tail-in of OilPlus proppants was proven to be returned in less than 30 days in the Permian Basin. Based on $53/bbl oil, wells that used an 11% tail-in of OilPlus proppants generated on average $1.1 million more revenue than offset wells during a 12-month period. hexion.com


Kimark’s dual-flare system, featuring a 98% destruction rate efficiency, is designed for dual-stream volatile organic compound control, particularly in rich, oily shale plays where vapors must be considered. Destruction occurs at both high-pressure and low-pressure systems in one modular stack. With a 0 to 30 high-pressure inlet range, gas stream flow rates can be achieved between 70.7 Mcm/d (2.5 MMcf/d) and 141.5 Mcm/d (5 MMcf/d). The low-pressure gas stream is air-assisted with a variable speed blower and inlet ranges from 0 oz to 16 oz. The advanced datalogging capabilities of the dual flare with the onboard computer collects vital data necessary for compliance with Quad O and Oa reporting and recordkeeping. The dual flare meets the criteria set forth in NSPS 60.18 to include continuous pilot, flare tip velocity, minimum heating value, smokeless burn with built-in Modbus communications and SCADA-ready operation. It has an intuitive touchscreen interface for local control and operates in a leak-free capacity with its ability to cut off stream flow in emergency situations. The Kimark dual flare is an efficient combustion system with advanced safety features such as high liquid-level kill, constant flame detection, inlet flame arrestors and inlet gas shut-off valves. otacompression.com


Operators of conventional wells across the globe battle excess paraffin wax deposition in oil and gas productions. Conventional control treatments might temporarily remove paraffin wax but must be repeated often. Traditional hot oil processes and hot water treatments might damage formations over time by pushing paraffin farther into the formation, and benzene, toluene, ethylbenzene and xylene solvents are extremely toxic. Locus Bio-Energy Solutions LLC has developed a patent-pending microbial technology that delivers fresh and dense microorganism populations to problem areas. This treatment has been successfully applied in the field and is proven to remove paraffin wax deposits in oil well tubulars as well as adjacent formation rock. In addition, microbial treatments can be used in well stimulation to remove formation damage from various unwanted precipitates near the wellbore such as paraffin, asphaltenes and resins, and any scale attached to them. Similar microbial treatments also rapidly soften tank bottoms that have lost capacity from sludge buildup. locusbioenergy.com

Locus Bio-Energy Solutions’ microbial technology delivers fresh and dense microorganism populations to problem areas. (Source: Locus Bio-Energy Solutions LLC)


Leading operators increasingly turn to technology to address the challenges associated with high well counts, geographically dispersed and remote operations, and hefty equipment maintenance and costs. As automation and other digital oilfield initiatives expand, they must be augmented by the reality that operational decisions and execution still require human intervention. The blending of massive amounts of data through technologies provides operators insight and context and drives faster, more informed decision-making. This improves production and drives revenue and profitability. P2 Energy Solutions is surrounding its production data management platform, P2 Merrick, with enhanced mobility and operational intelligence capabilities to make management by exception a reality for customers. P2 Merrick offers • Connection of the field and back office through tablet/phone-based mobile applications; • Real-time surveillance and monitoring of asset performance; • The ability to alert and notify the right people at the right time with the right data; and • Visualization and diagnostic tools to support issue identification and resolution. The platform also is designed to improve pumper-towell ratios, reduce man hours and associated costs, and reduce downtime and deferments. p2energysolutions.com

P2 Merrick enhances mobility and operational intelligence capabilities. (Source: P2 Energy Solutions)


A successful production chemical program that leads to reduced costs, greater efficiencies and increased well productivity is essential to remaining competitive in the market. The Ayre-Flo System, a chemical injection technology, is optimizing well performance by challenging traditional application methods. Pro-Ject Chemicals’ Ayre-Flo System uses a pressure-balancing technique to apply chemicals into oil wells throughout the day using virtually no moving parts. The steel chemical tank is fully contained and requires no outside gas supply or power source for operations. A patented process of integrated flush sequences ensures consistent chemical residual levels. With Sync Mode, the pump-off controller initiates the chemical treatment, moving fluid for the flush. Operations are SCADA-enabled with two-way command and control, providing real-time data. An operator recently conducted a field review comparison in the Wolfberry Formation with more than 400 wells and three chemical vendors. Each vendor had been treating wells for more than a year, and the severity of downhole conditions was relatively consistent across the field. The wells with the Ayre- Flo chemical injection method had an average run time of 260 days compared to 140 days for the standard treating methods, resulting in significantly reduced well failures and overall total cost of ownership. pro-jectchemicals.com


While the oil and gas economy continues to recover, the industry emphasis is on finding new solutions to old production challenges such as increased efficiencies and reduced operating expenses. Production lubricant ProFlow is offered by ProOne for artificial lift well systems. Results are field-proven in live pilot tests with some of the world’s largest oil producers. The lubricant is a polarized bonded thin film nanotechnology designed for production wells. Positively charged at the molecular level, the treatment bonds to all metal surfaces of rod, tubing and pump components to reduce friction, torque and drag by up to 80%. Among the direct behavior changes resulting from these reductions are increased pump efficiency, production volume and pump-off times, with a reduction in rod load and flowline pressure. After almost two years of testing in all pump types and well situations for major producers, this fluid treatment is serving a rapidly expanded market with new pilot testing planned or already commenced at other well-known majors and independents. pro1energy.com


MyQuorum Field Insights is the first cloud-based software for end-to-end field data capture, operations management and production reporting. Using a mobile app that runs on any iOS or Android tablet, field workers can capture information such as oil and water run tickets, maintenance, common services and treatments. Information collected in the field automatically syncs with web-based dashboards that offer production reporting, forecasting, key performance indicators, downtime analytics and lease operating statement analytics. In addition, energy companies can integrate myQuorum Field Insights with reservoir systems to track production targets and variances. The latest release of the program offers an advanced allocation engine to distribute oil, gas, water and components. A new interactive user experience lets users visually create and manage allocation flow networks with easy-to-use templates and dragand- drop tools. Through integration with accounting systems, myQuorum Field Insights lets users create customizable allocation reports including regulatory, joint venture and royalty reports. The program makes it possible for energy companies to eliminate manual paper-based processes, optimize well performance, ensure run ticket accuracy and reduce downtime. The net result is cost savings and higher profits. For example, one Oklahoma City-based E&P company saved more than $600,000 per month across 25 well sites using myQuorum Field Insights. qbsol.com


Data are the lifeblood of the digital oil field. Data can help producers improve nearly all aspects of their oil and gas production, from maximizing equipment performance and meeting production targets to lowering operating costs. In many operations, however, data are still collected manually and confined in silos, with limited integration between systems. In other cases, it’s a blowout: Too much data overwhelms operators and lacks the context needed to help them make informed decisions. The ConnectedProduction offering from Rockwell Automation creates an intelligent automation ecosystem, providing producers with actionable information at their fingertips. The ConnectedProduction environment brings the digital oil field to life by

  • Connecting production equipment, devices and systems;
  • Seamlessly integrating data; and
  • Transforming data into actionable operational information.

Once in place, the offering allows producers to visualize and control all aspects of production. By collecting the right data and contextualizing it into real-time diagnostics, production trends and key performance indicators, operators can better understand equipment performance and make more informed decisions. This can help producers maximize operations performance, optimize production facilities, enhance production agility and reduce downtime. rockwellautomation.com


A stable foundation is essential for rod-pumped wells to protect surface equipment and to keep production flowing. Even a slight shift in alignment of the pumping unit base can cause premature wear or damage to the polished rod, wellhead equipment and pumping unit components. In regions that experience seasonal freeze-thaw cycles or in fields with soggy, unstable ground, soil movement often results in detrimental shifting of the pumping unit base. For operators this translates to increased operational costs and environmental problems. Weatherford offers a friction-driven piling system that eliminates shifting of the pumping unit base in unstable soil conditions. This patent-pending total engineered system distributes the load of the surface equipment among several hollow piles that are driven to achieve precise load-bearing capacities. Movement or load changes in the surrounding soil will not cause a friction-driven piling base to settle or shift—even in permafrost or difficult geological conditions. Friction-driven piling systems save operators significant time and money compared with gravel pads or helical piling systems. For operators looking to enhance operational safety, reduce costs and downtime, prolong equipment life, prevent pumping unit settling and eliminate foundation resets, friction-driven piling foundations provide an economical solution. weatherford.com