More than 90% of the oil-and-gas wells use some form of artificial-lift technology to enhance production and recovery rates, but the correct methods must be used to ensure optimum performance.
It’s a fact of oil-drilling life that no well can ever be drilled in a perfectly straight line down to the oil-and-gas reservoir. This makes what has come to be known as the ‘dogleg severity,’ or DLS, the bane of optimized oil recovery. Simply put, a DLS is caused by the topography that is encountered when the well is drilled. The amount and types of rock, dirt, grit and sand, along with a list of other hindrances, determine how serious the DLSs are, with some wells encountering so many obstructions in the drilling path that they may be forced to go horizontal at times, or even have the well bore end up in a corkscrew shape.
Oilfield operators have known about and combated the challenges that are created by DLSs for the better part of a century. In that time, they have developed different forms of downhole artificial-lift technology that are designed to improve operations in wells that are hampered by severe DLS characteristics.
The key to optimizing the artificial-lift operation is the pump that is sent to the bottom of the well, as this uses energy to send any trapped reservoir fluids racing to the surface. Over the years, many different modes of pumping technologies have been used in artificial-lift applications, but this article will illustrate why hydraulic jet pumps can be the most productive, cost-effective and reliable solution, especially for wells that have many DLS-caused twists and turns.
In the vast majority of these artificial-lift installations, the pumping technology of choice has been the sucker-rod pump (SRP). SRPs are mechanically driven from the surface with a motor-driven pumping unit that connects to the downhole SRP with a rod string. While SRPs have been proven to be very effective at increasing production rates in wells with relatively straight bores, they are not an ideal choice for wells with DLSs for a couple of significant reasons:
• Because of the presence of the rod string, SRPs can not be used in wells with horizontal sections, meaning that they can only be used to a certain depth, with the knowledge that additional product can lie deeper within the well, but can’t be reached by the SRP. • If an SRP is due for maintenance or needs to be replaced, a workover rig crew needs to come to the well site and pull the entire section of rod string and tubing out of the well bore. This can be an expensive and unsafe proposition, with an average cost of up to $50,000, and additional well-downtime costs also likely to be incurred, while any on-site work can increase the likelihood that a safety incident may occur.
These are noteworthy considerations for operators who must be concerned with optimizing capital expenditures and operating expenses, all while keeping an eye on the overall return on investment and the net revenues that are produced by each well.
A wellpad located in the Eagle Ford shale in south Texas that is operated by a prominent North American exploration and production company had three wells drilled in early 2015. The DLS of two of the wells was high, prompting the operator to consider various forms of artificial lift other than one that used SRPs.
Since the third well did not have pronounced or prohibitive DLS, it would use an artificial-lift system featuring SRP technology for its recovery operation. Because of the high DLS values in the other two wells, it was determined that the best course of action would be to use hydraulic jet pumps instead of SRPs in the artificial-lift system.
It was decided that a 'one pump, two well' setup would work best for the DLS-hampered wells, meaning that both wells would use one surface pump to provide power fluid to run each well. A 200 hp pump was chosen to send the power fluid down the 2-7/8 inch tubing to the jet pump and return the fluids up the 5-1/2 inch casing to mitigate the oil-recovery process.
This 'one pump, two well' design had a number of advantages for the operator. Both hydraulic jet pumps could be sent deep into the lateral well at close to 40-degree inclinations. Since the jet pumps had no moving parts, and despite the fact they are four ft long, they have the capability to move freely up and down the tubing, even in the sections with high DLS values. The operational costs were divided among the cumulative production from both wells, thus cutting the cost in half when compared to a conventional 'one well, one pump' system and being comparable in cost to an installation that relies on SRPs. Jet pumps also allowed for flexibility in production; as the pump was set deeper in the well, there was the possibility to increase the drawdown and produce more in the same time when compared to an SRP. Finally, the surface unit came with a rent/purchase option, giving the operator the flexibility to pay a month-to-month rent depending on the productivity of the wells
After a two-month trial run, the productivity rates of the jet pumps were compared to the SRP and they showed that pump downtime was lower. Additionally, the initial production rates of oil for all three pumps were compared and the production of the two jet-pump wells outpaced that of the SRP well.
The two jet pumps were kept in operation and after nearly two years, the production returns from the jet-pump wells have been substantially more than the returns from the SRP well. The jet pumps also had more run time than the SRP well with less workover time required. Finally, and most significantly, the jet-pump wells produced 71% and 92% more cumulative oil than the SRP well. Even though the overall operational efficiency of the jet pumps was lower, this was made up by the increased uptime and production levels that were being experienced in the two jet-pump wells.
In the end, since the jet pumps resoundingly demonstrated that they could deliver greater flexibility, lower downtime and increased production, the exploration company has chosen to make them one of its primary choices for artificial-lift solutions going forward.
While the SRP has proven to be a reliable pump for artificial-lift in wells with relatively straight drilling paths, the better solution for DLS-dominant wells is the hydraulic jet pump.
Hydraulic pumps in general can be more effective than mechanical pumps because they are powered by existing or produced well fluid that is pressurized at the well’s surface and sent through the tubing to actuate the downhole pump. More specifically, hydraulic jet pumps have been designed to increase production-rate capacity from the deepest wells with the most severe DLSs, and whether they are traveling through sand, paraffin, heavy oil, water, gas or corrosive fluids.
There are certain features and benefits that help make hydraulic jet pumps the 'champion' of DLS-well recovery operations:
• They can be retrieved and serviced by simply reversing the fluid flow, which brings the downhole pump to the surface. This eliminates well downtime and can be done at a cost of as little as $2,000, a far cry from the previously noted $50,000 that it can cost to service a well that is equipped with SRPs. • Jet pumps have no moving parts, which eliminates wear and tear on the tubing, as well as the aforementioned pulling and replacement costs that can be associated with the other types of pumps that are used in artificial-lift applications. • Because jet pumps have no moving parts, they are very rugged and can have long downhole lives. If they do require maintenance, they are easily repairable in the field, which minimizes repair and replacement costs. • The size of a typical jet pump ranges from four to six feet and can easily be handled by one person. In addition, the small sizes allow the pump to easily travel down the tubing with severe DLSs.
There are a couple of reasons why operators might hesitate when considering the use of jet pumps. One, they are generally not very efficient when compared to a positive displacement pump like an SRP. Secondly, they require a high-pressure surface pump and piping. Also, in some cases where frac tanks have been used, pitting and corrosion of the tubing was found. Closer study determined that oxidation was the cause of the pitting and corrosion because oxygen was allowed to enter the power fluid. This shortcoming can be solved by using a closed-loop system for distributing the power fluid and treating it before use with the proper oxygen-scavenging chemicals.
In the end, though, these perceived drawbacks of hydraulic jet pumps can be overridden by the fact that they are less costly to maintain, along with being less complicated to operate, with any time and cost savings more than making up for any operational inefficiencies.
With all that being said, and most importantly, the jet pump, unlike its SRP cousins, is able to go where it is needed most, no matter the configuration of the well or the degree and type of DLSs that are encountered. The goal of any oil-production regime is to optimize the amount of oil and gas that makes its way to the surface in the most cost-effective and reliable way possible. The jet pump checks all the right boxes, particularly when used in high-DLS wells.
There’s no doubt that oil wells with drilling paths that feature high dogleg severities can take a significant 'bite' out of production rates. By extension, wells that do not produce at optimum levels do not create enough revenue to keep them viable, despite the large amounts of recoverable reserves that may be tantalizingly within reach. That’s why artificial-lift can be such an important part of optimizing the returns in an oilfield, but, again, only if the system functions at the height of reliability and cost-effectiveness. Artificial-lift systems that deploy hydraulic jet pumps have been proven to overcome the ill effects of wells that are beset by DLS concerns and are a tried-and-true way to ensure that all wells are capable of reaching their required production rates.
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