Over the last decade, techniques for horizontal drilling, fracking, and production have evolved, lending way to significant improvements in the way that artificial lift systems are used in unconventional applications. Characterized by steep decline curves, turbulent fluid production, and irregular wellbore geometries, horizontal well conditions presented a formidable challenge for the conventional artificial lift technologies of the time. Before the upstream sector was able to establish predictable, profitable recovery in horizontal wells, the industry first had to adapt to a new way of operating and develop production technologies that would be fit for purpose.
Since 2011, hydraulically fractured horizontal wells in the U.S. have dominated the landscape, with good reason. Among the various advantages to lateral drilling, by far the primary driver behind the unconventional boom is the ability for operators to access a much greater area of the producing formation than what’s possible with a vertical well. Rather than hitting the pay zone once at a perpendicular angle, a horizontal wellbore can maintain contact with the producing formation for the extent of its lateral section, which in some cases can reach up to several miles long. Additionally, because a single horizontal well has the potential to hit several pay zones, operators are able to produce more economically while minimizing surface impact.
Proportional to the impressive gains, however, are the significant obstacles encountered in unconventional applications. For instance, a typical horizontal well in the U.S. experiences a 60 to 80 percent decline in production in the first year, producing about half of its estimated lifetime oil production by the third year of operation. With experience under our belt, the industry now has a much better understanding of these decline curves, which has allowed operators to more accurately predict and manage production in unconventional wells. This trend impacts the operator’s reservoir economics by influencing how capex and opex costs are invested, as well as informing the amount of time required to recover that investment, or payback period.
At the same time, this steep transition from high to low volume production has direct implications in the selection and design of artificial lift systems. Because unconventional wells require some form of artificial lift earlier in their life cycle to maximize recovery from the production zone, these technologies play an important role in unconventional wells. In horizontal wells, artificial lift systems help increase production and recover more reserves over time by reducing wellbore pressure, thus encouraging nearby oil to drain through fractures into neighboring areas of the reservoir.
However, selecting a type of artificial lift for horizontal wells is complicated by factors such as wellbore casing size, severity of the curvature of the well, and production flow rate. In horizontal well conditions where production considerably declines after a certain period, operators must select artificial lift systems capable of handling the wide fluctuations in production volumes. To achieve this flexibility, implementing different artificial lift types at different points throughout the life of the well has become the most widely accepted strategy. While the replacement of each system incurs additional costs, this tactic allows operators to maximize the early peak production with high-volume systems such as electric submersible pumps, and later switch to a rod lift system to continue production at lower flow rates.
Using Old Technology in New Environment
Perhaps one of the most critical turning points for the industry has been the development of artificial lift technologies specific to unconventional applications. When horizontal drilling began to gain popularity, artificial lift suppliers had not invented the specialized equipment available today. Without an alternative solution, operators simply installed the same artificial lift systems designed for vertical wells in horizontal wells. However, the conventional systems were not equipped to operate in the abrasive, unstable conditions of unconventional production, causing operators to experience frequent failures and excessive wear on the equipment.
To make production sustainable, the systems evolved to meet the requirements of the applications. By nature of innovation, the deficiencies of the existing technology became areas for improvement, ultimately leading to a new portfolio of solutions tailored specifically for unconventional wells. Today, these solutions include reinforcing the equipment with more durable, protective materials, designing pumps to prevent accumulation of solids, implementing gas management devices, and modifying pump configurations to allow greater flexibility and permit installation beyond the well’s vertical section.
While electric submersible pumps were once considered unsuitable for unconventional applications, today most horizontal wells are put on an ESP as the first form of artificial lift. This is almost entirely due to the advancements in technology which have enabled ESPs to operate effectively across greater flow ranges and improvements in gas/solids handling. Early objections to using ESPs in unconventional applications emphasized that the production volatility, the high dogleg severity of the wellbore and the potential for gas slugging would inhibit the ESP to produce fluid as efficiently as it would in a vertical well. Fortunately, the technological developments over the last five years have increased the ESP’s capacity to operate under these conditions. Figure 1 highlights the ESP modifications discussed in this section.
To withstand the presence of abrasives in the fluid, ESP manufacturers now produce pumps with more durable materials such as tungsten carbide and apply coatings for enhanced protection. Often referred to as “abrasion-resistant” designs, these pumps may also feature improved radial support to stabilize the shaft as well as tungsten-carbide bearings to reduce the impact of thrust on the equipment and extend the operating range. Due to the volatility of the fluid, this additional protection helps prevent excessive wear, extending the system’s run life.
Similarly, if sand or other solids are present in the production fluid, it can cause serious damage to an ESP. These solids can build up in the pump itself, causing blockages and consequently increasing the pressure inside the system beyond operational limits. Additionally, when fluid moves through the pump, it is flowing at such a high velocity that solids can quite literally wear through the pump stages. To improve the ESP’s solids-handling capabilities, stages can be designed with wider vane openings improve flow through the pump and prevent blockages. Additional features may include a system of internal grooves throughout the pump, which allow even greater maneuverability for smaller particles.
As mentioned earlier, horizontal wells can produce high amounts of free gas. Because the lateral section of the wellbore is rarely a straight line, undulations along the lateral section of the wellbore create hills and valleys, where gas is able to accumulate until it is forced out by the production fluid. Gas slugging poses a significant challenge for ESPs because as the gas enters the pump, the pressure drop and absence of fluid to cool the motor can cause gas-locking, forcing a shut-down of the equipment. However, there are several measures that can be implemented to alleviate this issue.
Gas separators are a special intake device which use centrifugal force to separate gas from the production fluid before entering the primary pump. While heavier fluids such as the oil or water move to the outer edges of the equipment housing and continue flowing through the ESP system, the gas is isolated from the mixture. After this separation, the larger gas bubbles can be filtered out into the wellbore while smaller bubbles enter the next phase of production – gas handling.
Installed just above the gas separator, a gas handler takes the remaining bubbles and homogenizes the fluid-gas mixture by reducing the bubble size and discouraging gas separation. At this stage, the goal is to break up the gas as much as possible and blend it into the fluid to reduce the amount of free gas that enters the main pump. This way, the fluid can maintain a certain level of buoyancy, providing natural lift for improved ESP production. Figure 2 illustrates the flow of gas and fluid as it moves through the gas separator and gas handler.
In addition to devices that can be installed downhole to regulate the composition of gas in the pump, variable speed drives (VSDs) play an important role in controlling the ESP system from the surface. As a protective measure to prevent the system from overheating, the ESP controller may be designed to automatically shut off in gas-slugging conditions. However, this behavior is not conducive to continuous, profitable production, especially where gas slugging may occur frequently. To bypass this issue, operators can program a VSD with software which allows the system to reduce the frequency of the drive, allowing the gas slug to work through the centrifugal pump, rather than shutting down completely. Frequent stops and restarts of the system reduce the system efficiency and can lead to cable/motor insulation degradation, costing an operator to lose production during shut-downs. By allowing the system to operate continuously, this advancement in VSD technology can significantly improve ESP performance and an operator’s return in otherwise challenging wells. Figure 3 compares two amp charts. The left image shows an ESP which is experiencing gas locking and shutdowns, while the image on the right illustrates normal, continuous operation.
Flexible Pump Designs
A more recent innovation in ESP technology for unconventional applications is the design of flexible joint connections to allow deeper installation into the curve and horizontal section of the wellbore. A standard ESP can withstand a maximum buildup rate of six degrees per 100 feet, which permits the system to be inserted in most long-radius horizontal wells without serious risk of bending the equipment. As more wells are completed with tighter radii, however, operators sometimes need an ESP capable of handling higher buildup rates. Due to the increased cost of flexible ESP systems and the potential for reduced pumping efficiency, these designs are most effective in circumstances where placing the pump further into the well results in significant production benefits.
However, there is little consensus regarding the gains achieved by deeper setting depths in horizontal wells. While it has been suggested that placing an ESP further into the lateral section can increase production volumes, this practice is largely dependent on the operator’s cost-benefit analysis of the investment versus the attainable production increase. Depending on the rate of buildup in the well, the durability of the pump, and the operator’s economic models, the decision to install a flexible ESP to achieve greater setting depths must be made on a case-by-case basis.
Artificial Lift Progression
After production in a horizontal well has decreased to the point where an ESP is no longer viable, operators must decide which subsequent forms of artificial lift to install downhole. However, the specific point in time at which this transition is made varies depending on the application and the operator’s production goals. Characteristics of the producing formation combined with the shape of the wellbore will impact the rate of decline in production, but the final decision in most cases is primarily driven by production economics.
Taking into account the operator’s reservoir management philosophy and the projected payback period, these factors will determine the optimal point of production, where the maximum amount of fluid is produced at the lowest operational cost. Figure 4 is an example decline curve which illustrates the typical progression of artificial lift types over the life of a horizontal well. It should be noted that the period of highest production makes up only the first few years, less than a third of the entire life of the well.
In most cases, an ESP is the first type of lift in the well and will stay downhole for the first year and sometimes longer. Once production has reduced to levels that would not be sustainable for an ESP, gas lift and rod lift are the most popular options for low-volume lift systems. Frequently, the selection of artificial lift types can also depend on the operator’s experience level and familiarity with one system compared to another. Similarly, there may simply be a preference in certain regions. For example, in the Wolfcamp region a large number of operators are installing gas lift, while rod lift claims an equal share of wells in the Bakken.
In conclusion, the explosion of unconventional wells throughout the U.S. has led to substantial innovations over the last 5-10 years. In addition to the knowledge gained as an industry over this time, advancements in the technology used to drill, complete and produce these wells have vastly improved the sustainability of horizontal production for the foreseeable future.
Lou Martensen is the Product Line Director at Valiant Artificial Lift Solutions. He has over 30 years of domestic and international experience specializing in marketing, business development, business management, manufacturing and sales management in the petroleum industry. Throughout his career, Lou has worked with some of the industry’s top artificial lift companies, including Baker Hughes, Borets, and GE Oil and Gas. His in-depth technical knowledge of ESP systems and global management experience provide Lou with the skills needed to successfully identify and achieve both company and customer objectives.