【系列专题】页岩油气复苏：高产量背后的新技术（1）

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.

AUTOMATED SYSTEM EVALUATES SCALE INHIBITORS

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.

ENCAPSULATED PRODUCTION SYSTEM OVERCOMES MULTIPHASE FLOW CHALLENGES

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).

GAS-LIFT SYSTEM INCREASES PRODUCTION AT BAKKEN WELL

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.

AUTOMATIC TANK GAUGING PROVIDES MORE ACCURATE INVENTORY MEASURES

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.