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Study Evaluates Ability of Tailpipe Systems To Optimize Artificial Lift in Horizontal Wells

Topics: Artificial lift

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The performance of artificial-lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, gas slugging leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electrical submersible pump (ESP), gas slugs can cause cycling of the ESP, which may shorten run life significantly. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift.

Introduction

The two tailpipe systems were tested in a number of wells using SRPs, and one well was tested using an ESP. The goal was to

  • Reduce the frequency and magnitude of slugging behavior seen at the pump
  • Reduce the flowing bottomhole pressure without having to land pumps past the kickoff point (KOP)
  • Improve separation of free gas from the produced fluid before it reaches the pump intake

The two systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced-inner-diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a special cyclonic separator with a reduced-ID tailpipe, and the packer is located at the lower end of the tailpipe. The authors examined the differences between the two systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed in the complete paper to improve the design, installation, startup, and operation of these systems.

Some installations were outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet and outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial-lift system while also providing data for modeling the flow regime through the tailpipe. The modeling results were used to forecast long-term performance of the system as well production declines over time.

Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behavior through the tailpipe, separation effectiveness, and changes in production.

Background

Even after they are drilled, horizontal wells pose more challenges than vertical wells, particularly with regard to gas slugging and reservoir drawdown. Geometries such as toe-up, toe-down, or undulations can allow gas pockets to build in the lateral. Eventually, these gas pockets, or slugs, will flow into the vertical section, partially or completely displacing liquids. When they reach the artificial-lift system, slugs can cause incomplete fill­age in SRPs or cycling in ESPs.

Gas can enter SRPs for a variety of reasons, but one common reason is insufficient or nonexistent gas-separation equipment, which is typically designed on the basis of daily production rates. This is a reasonable approach when a well’s inflow is fairly consistent, but when production varies throughout the day, as is common in horizontal wells, the separator cannot prevent gas from entering the pump.

Similarly, gas in an ESP causes the pump to shut down frequently. This cycling stresses the motor and shortens its life. The design’s gas-handling equipment helps, but, like a rod pump, when the production varies, the pump may receive more gas than it is designed to handle.

These issues are significant drivers of failure rate and operating expense. Gas in pumps is one of the largest causes of artificial-lift failures in the operator’s Permian Basin operations, especially in horizontal unconventional wells.

The issue of drawdown is a primary point of concern when designing an artificial-lift philosophy. The usual approach is to evacuate the wellbore of liquids to maximize the drawdown on the reservoir and maximize inflow. To achieve these goals, the pump is landed as low as possible in the wellbore, ideally below the perforated interval. In a horizontal well, that would require running the pump around the curve into the lateral. For a rod pump, this would lead to high side loads and significant rod-on-tubing wear in the curve. For an ESP, it might mean running the pump with the shaft bent, which puts stress on the shaft and shortens run life.

To avoid these problems, the operator generally locates the pump in the vertical section for as long as possible, running it into the curve later in the well’s life. The pump is landed well above the depth of the lateral (typically 700 ft total vertical depth higher), resulting in 200- to 300‑psi additional backpressure on the reservoir, which can have a significant effect on the production rate.

Tailpipe systems offer the opportunity to address these issues. Although the physics of these systems is not addressed in this paper, the systems are designed to change the flow regime of the reservoir fluids as they travel through the curve to a pump intake in the vertical portion of the well. The intention is twofold: to mitigate the slugging behavior and to reduce the static head of the fluid column in the curve.

System Comparison

The two tailpipe systems tested comprise three key elements. 

  • A sized velocity string with an ID designed to change the flow regime as required
  • A tool to isolate the annulus between the casing and tubing to force the flow from the reservoir into the velocity string
  • A separator at the top of the string to separate gas from liquids before the liquids flow into the pump intake

There are two key differences between these systems. The isolation tool is at the top of the velocity string for System A and at the bottom for System B. Additionally, the flow paths are quite different for the two systems, as illustrated in Figs. 1 and 2.

              Fig. 1—Tailpipe System A separator.              Fig. 2—Tailpipe System A separator. 

 

The separator used for System A has flow paths similar to that of a conventional packer-style separator. Fluids flow from the tailpipe into the body of the separator, then turn a 90° corner to flow into the annulus between the tubing and casing. Separation occurs in that space, and the liquids fall down to a liquid dip tube, which carries the liquids to the pump.

The System B separator is different. Fluids from the tailpipe exit the separator head into the annulus in a near-vertical direction, which is assumed to be less turbulent to produce better separation.

Trial Details

To understand the utility and operating ranges of these systems, extensive field testing addressed the following questions.

  • Do the systems work as advertised?
  • If they both work, does one work better? Of particular concern with System A was the isolation at the top of the string. Would the annular space below the isolation provide a place for gas to build up and then slug into the velocity string? For System B, the main concern was about running full-diameter tools into laterals, with the potential for becoming stuck and having to fish them. Because the system is designed for solids to settle in the annular space above the isolation packer, could the tubing or even the packer become stuck?
  • Which parameters are useful to predict success—gas/oil ratio, pump intake pressure (PIP), total liquid or gas rate, or something else? For each useful parameter, what is the range of successful values? Are there dependencies between the variables? For example, does the range of good gas/liquid ratio vary with PIP?

Testing focused on SRP and ESP installations because they are more prone to problems with gas interference than gas-lifted wells. All but one of the test installations were SRPs, for which the tailpipe technology is most fully developed.

To study the behavior of the systems, pressure gauges were installed along the tubing string of three wells as follows:

  • One at the bottom of the velocity string
  • One at the top of the velocity string
  • One at the pump intake
  • One at the pump discharge

A large number of systems also were installed without gauges to confirm the findings in the gauged wells and helped determine operational success factors using conventional surveillance and monitoring tools. Success parameters focused on the pressure difference across the velocity string, PIP, pump fillage, and changes in production. Evaluation was ongoing, with changes made as results dictated.

Conclusions

This study is not yet complete, but the authors drew some firm conclusions. Tailpipe systems can achieve the effects for which they are designed, in particular slug mitigation and increased drawdown in some wells. Both systems can perform as intended, although questions remain about particular risks the different designs pose and about production variance in the trial wells. Details from the trial wells and additional conclusions are presented in the complete paper.

For a limited time, the complete paper SPE 190938 is free to SPE members.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190938, “Evaluating Tailpipe Systems Designed To Optimize Artificial Lift Performance in Horizontal Wells,” by C.R. Humphreys, SPE, B.N. Vangolen, SPE, A.P. Allison, SPE, D. Yin, SPE, and C. Yicon, SPE, Occidental Petroleum, prepared for the 2018 SPE Artificial Lift Conference and Exhibition–Americas held in The Woodlands, Texas, USA, 28–30 August. The paper has not been peer reviewed.

Study Evaluates Ability of Tailpipe Systems To Optimize Artificial Lift in Horizontal Wells

01 March 2019

Volume: 71 | Issue: 3

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