FEBRUARY 2016

The “Better Business” Publication Serving the Exploration / Drilling / Production Industry Technology Solves Sanding Problems By John H. “Jay” Thompson, to remediate, resulting not only in in- since late 2013, according to data from Jeff Dwiggins creased operational costs, but also po- Primary Vision Inc. and Scott Muster tentially leading to equipment failures Increased proppant concentrations per that necessitate unscheduled repairs and stage mean that wells completed with OKLAHOMA CITY–The industry’s interrupting hydrocarbon flow to the 500-750 pounds of proppant for each lat- concept of sand control has been redefined sales line (increasing costs while de- eral foot a few years ago now are being by unconventional reservoir development. creasing revenues). completed with 1,000-1,500 pounds/foot A decade ago, sand management was as- Given the prevailing low commodity (routinely exceeding 7 million pounds sociated with conventional, high-perme- price environment and the need to optimize total for each lateral completed in the ability reservoirs, where “getting the the economics of each asset, a single Bakken, Eagle Ford and other plays). beach out” was required to sustain hy- equipment failure can impact a well’s While helping operators maximize pro- drocarbon production in sand-producing bottom-line performance materially. Costs duction and recovery rates, it also obvi- intervals, particularly sandstones and vary based on the type and size of equip- ously places twice as much frac sand in other unconsolidated formations. ment installed and the well’s location, the formation. With the advent of multistage com- but the capital expenses associated with pletions of horizontal wells in unconven- a well intervention to repair or replace a Sand-Related ESP Failures tional resource plays, the production of damaged ESP system can exceed $150,000 Sucker rod pumping is the most frac sand and other proppants has become for horizontal wells. The value of lost widely used artificial lift method in U.S. a more widespread challenge. For the and/or deferred production from downtime onshore operations, but oil and gas com- majority of oil and gas fields, sand from also must be factored into the equation, panies invest more capital in electric the reservoir is an inevitable byproduct along with the possibility of decreased submersible pump equipment than any of hydrocarbon production. In unconven- reservoir performance that may never be other lift method. In fact, ESPs account tional wells, however, it is a consistent restored. for more than 45 percent of the total an- challenge. In some wells, downhole pumps have nual spending on artificial lift installa- Virtually all wells completed in un- to be replaced as often as three or four tions. They are deployed routinely in conventional formations experience some times a year because of wellbore sanding, shale plays to accommodate high pro- level of proppant flowback, since all creating an operating cost structure that ductivities, and frequently are used in wells in these plays require hydraulic challenges profitability, especially at lower combination with other forms of artificial fracturing to produce economic rates of wellhead prices. In pad developments lift at different stages of a well’s pro- liquids and gas. Proppant flowback begins with multiple wells, recurring sand prob- ductive life. immediately with fluid flowback at the lems that require frequent interventions For example, a horizontal well may time of pressure release, but can occur to can negatively impact the economics of be equipped with an ESP to accommodate different degrees throughout a well’s pro- individual pads as well as entire field de- the high-rate initial production phase, but ductive life cycle. Depending on the par- velopment areas. then converted to rod pump or some other ticular operator’s completion method, Looking at well construction trends form of lift once IPs have dropped. But sand flowback issues can range from in shale and tight reservoirs, proppant even in these situations, proppant flowback moderate to severe, and may present myr- flowback and sand control issues certainly typically occurs most frequently in the iad problems. do not appear to be diminishing anytime earliest stage of production, when an The immediate concern is damage to soon. In fact, given the correlation between ESP is required to accommodate the peak artificial lift systems and other downhole higher volumes of sand pumped during initial flow volumes. equipment, in particular electrical sub- hydraulic fracture treatments and better Consequently, ESPs in horizontal shale mersible pumps, as well as plungers, production performance in horizontal wells commonly suffer from severe erosion valves and tubular components. Sand- wells in many plays, proppant volumes and radial wear caused by frac sand and related problems can be very expensive pumped per well have effectively doubled other residual solids. The biggest chal-

Reproduced for Multilift Welltec LLC with permission from The American Oil & Gas Reporter www.aogr.com Special Report: Unconventional Resource Science

FIGURE 1 Sand Control Tool ESP Run Days Before and After Installing Sand Control Tool An alternative approach available to (Mississippian Lime Wells) operators is a low-cost mechanical tool that is located in the tubing string just 600 above the ESP pump discharge to guard against sand-related problems. The rela - 500 tively simple device captures fallback sand and segregates it away from the 400 pump. It diverts falling-back, solids-laden fluid to an inner chamber, which in turn,

300 allows the fluid to drain off back through the pump, while capturing sand and solids within the chamber. 200 When the pump is restarted, the cap - tured sands and solids are expelled from 100 the chamber by the flow action of the pumped fluid, and are carried to the sur - 0 face. The system can be cycled endlessly, #1 #2 #3 #4 #5 #6 #7 #8 #9 #10 #11 #12 #13 #14 #15 #16 #17 #18 #19 #20 #21 #22 #23 eliminating potential damage to the pump Run days with tool installed Run days prior to installing tool Shutdowns at every shutdown while lowering lease operating expenses by protecting downhole equipment and increasing ESP run times. lenges for ESPs are sand and gas slugging, sissippian Lime trend in Oklahoma and Because it has no moving parts, it is which lead to excessive temperatures in the Permian Basin, power fluctuations fail-safe and invisible to the ESP. An im - the motor, cable and pump section. Promi - remain the root cause of many production portant technical feature of the technology nent failure modes are related to erosion, issues, including pump failures caused is an automatic self-flushing capability sand accumulation, plugging or contam - by sand. that empties the pump after every restart. ination, and loss of radial stability. Not surprisingly, sand fallback has Since there are no ports to the annulus In unconventional reservoir applica - been identified as the number one cause (the tool does not communicate with the tions, ESP shutdowns happen throughout of ESP failures in unconventional wells. annulus), pumped recirculation is impos - the life of a well, and sanding is always In propped horizontal shale wells, the sible. a concern when restarting the pump. fluid column in the tubing string will al - SandRidge Energy is deploying the When an ESP cycles off or shuts down, most always have significant volumes technology in more than 30 ESP well in - the sand trapped in solution in the pro - of suspended sand. Therefore, some sus - stallations in the Mississippian Lime play, duction stream begins to fall out and tained level of solids production must and the company is realizing substantial collect on the top of the pump. By the be accepted in order for a well to be pro - increases in ESP run times in hydraulically time the ESP cycles back on, sand can duced, but establishing a proactive sand fractured wells that historically have suf - accumulate to the point that it clogs the management strategy is vital to protecting fered from problems caused by significant pump chamber. the ESP, achieving an acceptable run sand production. Restarting a sand-plugged pump can life, and keeping production flowing Figure 1 shows performance data on cause catastrophic harm, including the smoothly. ESP systems installed in 23 SandRidge- inability to restart because of severe plug - One solution to controlling an ESP’s operated wells equipped with the tool to ging (thereby mandating a workover), exposure to proppant flowback is using safeguard the downhole pumps. All of significant damage to the upper stages curable resin-coated sand designed to the wells produce sand, and two of them (commonly top 20-30 percent), forcing form a “pack” under temperature and yield such heavy sand concentrations that lower stages into down-thrust, torque closure pressure conditions to mitigate two devices have been installed in each twisting and broken pump shafts, and sand production while maintaining fracture well to ensure the ESPs are protected. burned motors from starting under high conductivity. The downside to this ap - With well production rates varying be - load conditions. proach, especially given today’s tighter tween 400 and 6,200 barrels a day across For this reason, fluctuations or dis - economic margins on well completion the field, two sizes of ESPs are installed: ruptions in electric supply are a key issue and production operations, is the additional a 4.0-inch outside diameter system for in ESP applications. Every time the power cost of premium proppant materials com - wells producing at lower daily rates, and goes out, sand starts falling back on the pared with uncoated frac sand. a 5.38-inch outside diameter pump for pump. Many ESP manufacturers have tech - wells with rates greater than 3,500 bbl/d. Electricity reliability tends to be a lo - nologies engineered to cope with sand ESP run life in the field is on an calized problem, and some areas are passing through the pump. But when the upward trend, thanks to high efficiencies, worse than others. In North Dakota, for ESP shuts down from a power failure, good operational procedures, and a focus instance, ongoing improvements to sta - pump-off conditions, production shut - on ESP reliability solutions. The sand bilize the power grid in the Bakken play downs, etc., previously pumped sand falls control tool has performed flawlessly, al - area have eliminated many lingering prob - back onto the top stages where it wreaks lowing the pumps to record as many as lems. However, in areas such as the Mis - havoc on attempted restart. 477 run days (and counting) after the Special Report: Unconventional Resource Science

tool was installed, representing an average 1,200 percent improvement in ESP run JOHN H. “JAY” THOMPSON is the Dwiggins started his own consulting times. artificial lift specialist with SandRidge firm in 2002, opening his international No pumps have been lost because of Energy in Oklahoma City. He has been office in 2005. He holds a B.S. in me - sand in the field since the tools were in - with SandRidge for three years, but chanical engineering from the University stalled, and there have been no workover has more than 27 years of experience of Oklahoma. call-outs to mitigate sand-related well or in the surface and downhole pumping pump failures. In an extreme case, as industry. Thompson’s interests include SCOTT MUSTER is managing prin - many as 104 shutdowns were observed the effects of wellbore design and how cipal of MCe Performance, and works within six months in one of SandRidge’s that affects ESPs, root cause failure as a marketing consultant to Houston- wells. With the tool in place, the ESP was analyses, and how the longevity of based Multilift Welltec LLC, which ™ protected at every shutdown and production downhole equipment can be improved. manufactures the SandGuard tool used was able to resume immediately flowing to protect the ESPs in SandRidge En - each time the pump was restarted. JEFF DWIGGINS is managing di - ergy’s Mississippian Lime wells. Muster By preventing damaged pumps and rector of Artificial Lift Solutions. He is an award-winning branding/market - costly well workovers, the tool provides has more than 25 years of experience ing executive with more than 25 years an affordable safeguard against sand fall - providing support for all types of arti - of experience coaching teams of cor - back in wells equipped with ESPs. The ficial lift projects in many of the world’s porate thought leaders and graphic net result for SandRidge in the Missis - major oil-producing areas, including arts professionals to produce marketing sippian Lime is significantly lower lease Russia, China, the Middle East, Asia, materials and messaging. He is a grad - operating expenses, extended ESP run South America and the United States. uate of the University of Houston. life, increased overall production, and dramatically reduced downtime and de - ferred production. Ì