Gas Well Workshop Titles, Abstracts, Notes Page 2

2010 Appalachian Basin Gas Well Deliquification Seminar

Technical Presentations

/
Session:
I --- Pumping and Gas-Lift
/ Session Chair:
John Cramer, Range Resources
Presentation Title:
I-1 --- Liquid Unloading of Gas Wells
Using Multiphase Pumps / Company(ies):
Leistritz Corporation
Author(s):
Joseph E. Latronica / Contact Information:

Abstract:
Many producing gas wells are experiencing a reduction in wellhead pressure from increased liquid production as they mature. Producers are looking for new technologies to boost production in these mature wells. Multiphase boosting is one technology that can maintain economical late-life production since the wet gas and high gas/oil ratios are familiar to that of today’s multiphase pumping technology.
Multiphase pumping reduces the back pressure on the well by boosting the untreated well flow, allowing the reservoir to accelerate production. This presentation will focus on the most common multiphase pumps, twin screw positive displacement multiphase pumps.
Twin screw multiphase pumps work with fixed displacement, where each pumping chamber formed during the rotation delivers a constant volume from the inlet to the outlet. Liquids are essential in the operation of the multiphase pump utilizing the liquid to compress the gas forcing the flow to move from the suction to discharge. A minimum of 2 to 5% of liquid is required to maintain laminar flow, from chamber to chamber. Liquid management and collection allows the pump to handle 100% gas slugs. Obviously, liquid loaded gas wells are a perfect candidate for these pumps.
As the reservoir ages, the liquid becomes a serious constraint. The decrease in flowing pressure causes a drop in gas velocity and the liquids become too much to carry causing the well to become liquid locked. Multiphase boosting is a surface technique that will restore the gas flow in the well by lowering the wellhead pressure. This technique can be used in combination with a downstream compressor or with a downhole ESP, rod pump, etc. Multiphase pumps are driven by electric or hydraulic motors as well as gas or diesel engines and are being utilized as a portable means to restore aging wells in addition to permanent production boosting.
The twin screw multiphase pump is a straight forward technology based on a gas-tolerant pump design, which with its surface location, simplicity in operation, and reasonable capital cost is attracting increased interest. Successfully installed in many places, multiphase pumping has much more to provide in the oil and gas industry and is rapidly becoming a major tool for producing late life natural gas wells.
Notes:
Session:
I --- Pumping and Gas-Lift
/ Session Chair:
John Cramer, Range Resources
Presentation Title:
I-2 --- Sucker Rod Characteristics and Factors Affecting Sucker Rod Coupling Make Up / Company(ies):
UPCO, Inc.
Author(s):
Erik Tietz
Arun Sriraman / Contact Information:

Abstract:
Sucker rod pumping technology is being widely used for gas well deliquification. As a result of this, it is very critical to study and reestablish some of the critical parameters which constitute sucker rod-coupling make up. In order to establish this, a scientific study (strain gauge testing) was conducted to under laboratory conditions. This paper is divided into three different segments:
Segment 1: This segment addresses some of the important concepts which govern sucker rod-coupling make-up like stress, strain, toughness, notch sensitivity etc.
Segment 2: The technology in the manufacturing of sucker rods has improved to a large extent. As a result, the current displacement values do not truly reflect the technological advances made in this industry. This segment of the paper addresses the updated displacement values as a result of strain gauge testing conducted on all grades and sizes of sucker rods.
Segment 3: 70% of the failures in this industry are related to pin failures. Most of the pin failures can be eliminated by good recommended practices and knowledge in the field. This segment of the paper addresses the following key recommended practices which were established using strain gauge testing.
a.  Importance of using CD values instead of torque for make up process.
b.  Dry face vs. wet face make up.
c.  Life of a sucker rod.
d.  Selection of thread lubricants.
Notes:
Session:
I --- Pumping and Gas-Lift
/ Session Chair:
John Cramer, Range Resources
Presentation Title:
I-3 --- Is The Selection Of Artificial Lift Too Arbitrary? / Company(ies):
Consultant
Author(s):
Jim Hacksma / Contact Information:

Abstract:
In gas wells in particular, we often see the following “inconsistencies”:
●  Different operators using different artificial lift methods;
-  In virtually identical wells (that are sometimes just across the lease line).
●  The same operator using different artificial lift methods;
-  In virtually identical wells (that are sometimes just across the lease line).
●  An operator starts using different artificial lift in a field;
-  Simply because a different engineer has been assigned to the field.
-  The new engineer is not armed with any different facts - only different “opinions”.
It is contended that the “inconsistencies” described above are evidence that the artificial lift selection process is “too arbitrary”. The process may be largely arbitrary because our industry is being provided too little reliable information concerning the technical merits of each artificial lift method.
If the “technical merits” of each artificial lift method were more widely disseminated, better
understood by our industry, and more commonly used in the selection process; then the artificial lift selection process would yield “more uniform results”. Wells that are virtually identical would more often receive the same artificial lift and the inconsistencies described above would largely disappear.
This presentation is an attempt to help our industry do a better job of selecting artificial lift, clarifying the technical merits of several artificial lift methods, and comparing those methods. Methods analyzed are:
·  velocity strings
·  foam
·  plunger lift
·  beam pumping
·  continuous gas circulation
·  compression
·  gas lift.
Where possible, “outflow curves” (from Nodal Analysis) are used to analyze & compare the artificial lift methods.
Notes:
Session:
II --- Plunger Lift
/ Session Chair:
Tim Knobloch, James Engineering
Presentation Title:
II-1 --- Casing Plunger Applications and Development / Company(ies):
Multi Products Company
Author(s):
Robert McKee
Lindsey Nichols
David Bordwell / Contact Information:

Abstract:
Over the last two years there have been new designs and materials to make the concept of positive seal plungers work effectively in more applications. We will review equipment types/sizes, well applications, theory behind the application, and review actual case studies. There have been many new developments with the casing plunger including new size introductions from 2.5” through 5.5” tools, patented high pressure safety systems, new automation (control systems and algorithms), and many new mechanical design features. Casing plunger systems have also been designed for horizontal and vertical shale wells in the Marcellus.
Benefit: Casing plungers have the potential to provide an extremely cost effective lifting solution for many wells that are low pressure, low GLR, or even higher pressure special situations. Eliminating the need for costly tubing and saving the operators the capital cost and maintenance for pumping units, the Casing Plunger system provides a very attractive alternative.
Notes:
Session:
II --- Plunger Lift
/ Session Chair:
Tim Knobloch, James Engineering
Presentation Title:
II-2 --- Using Continuous Flow Plunger Technology to Deliquify Horizontal Wells in the Marcellus Shale / Company(ies):
Exco Resources
Production Control Services (PCS)
Author(s):
William Veigel
Justin Schubert
David Dahlgren / Contact Information:

Abstract:
Continuous Flow Plunger Systems are enabling producers to optimize the gas and fluid production of horizontal wells. Historically, many of these wells may have been thought to be at or above critical flow rates and, therefore, not typical plunger lift candidates. However, by recognizing the early signs of liquid loading in horizontal wells and effectively implementing continuous flow plunger lift, increased production and slower decline curves can be obtained.
The presentation will discuss the following:
·  Identification of continuous flow well candidates
·  Correct utilization of continuous flow plungers in horizontal well applications
·  Benefits of using continuous flow plunger lift in wells in the Marcellus Shale region
Continuous Flow Plunger Systems can provide an easy-to-implement and cost-effective method of increasing production and extending the lifespan of horizontal wells.
Notes:
Session:
II --- Plunger Lift
/ Session Chair:
Tim Knobloch, James Engineering
Presentation Title:
II-3 --- Field Validation of a High-Speed Plunger Concept / Company(ies):
ExxonMobil
Tim Knobloch, James Engineering
Author(s):
M. Gong
L. E. Harrison
P. C. Underwood
N. J. Crawford
R. Davis
B. L. Woods
E. Z. Monus / Contact Information:

Abstract:
Plunger lift is a cost effective artificial lift method for unloading water or liquid hydrocarbon from gas producing wells. Conventional plungers were designed for running in depleted low-pressure wells. In recent years, continuous-cycle plungers including two piece plungers have become attractive for their improved cycle efficiency. Further expanding the application range of plunger lift requires improving plunger falling ability against high flow rates.
The presentation describes a novel high-speed auto-cycle plunger targeting applications in the early life of high WGR wells when the well is still flowing above or near the critical rate. Improving plunger falling ability by minimizing friction drag is critical. Another challenge is to mitigate impact-induced damage to the plunger system. Various computer analyses and laboratory tests were conducted to improve plunger design and ensure plunger durability.
Initial field trials have been performed to validate the great potential for the high speed plunger. Lessons learned during plunger field trials will be discussed.
Notes:
Session:
III --- Horizontal Wells
/ Session Chair:
Rodney Bane, ExxonMobil
Presentation Title:
III-1 --- Liquid Loading in Horizontal Wells / Company(ies):
University of Tulsa
Marathon Oil Company
Author(s):
Cem Sarica
Rob Sutton / Contact Information:

Abstract:
All producing gas reservoirs, both conventional and unconventional, have water present in the formation. The presence of free water within a gas wellbore may hinder the production of the gas unless it is removed. The accumulation of water places extra backpressure on the reservoir and can reduce productivity by forming water blocks in the formation. Therefore, unloading of the wells is one of the most important production challenges. The unloading of the wells is especially challenging and not well understood for the horizontal portion of the well. There are several factors affecting the flow. Relatively low gas production rates make the water flow difficult which can lead to the accumulation in the well that adversely affects flow from the reservoir. Horizontal wells can have an undulating trajectory resulting in low spots for water to accumulate and not being removed. In other cases, the toe may be shallower or deeper than the heel of the well. These complex geometries further complicate the understanding and removal of water from the well.
Mechanisms of horizontal well liquid loading have not been studied much. The Turner critical velocity model and variations such as Coleman are not applicable for horizontal wells. On the other hand, an appreciable amount of knowledge on low liquid loading flow in pipelines has been accumulated over the last two decades. These studies can be classified into high and low gas flow rates. At high gas flow rates, the liquids are continuously produced and no accumulation or loading of the liquids are observed. While the low gas flow rate studies indicated accumulation of the liquids and irregular slugging. In this presentation, we will qualitatively discuss under what conditions the liquid loading should be expected. Video captures from various tests will be shown. We will also discuss what is needed for reliable loading predictions in horizontal wells.
Notes:
Session:
III --- Horizontal Wells
/ Session Chair:
Rodney Bane, ExxonMobil
Presentation Title:
III-2 --- Use of Soap Sticks in a Deviated Completion / Company(ies):
Pro-Seal Lift Systems
Author(s):
Dan Casey / Contact Information:

Abstract:
The factors that make some deviated profiles difficult to de-water with plunger lift can be overcome with an optimum application of soap sticks and well control. The operator shouldn’t assume that horizontal completions can be soaped in the same manner as vertical completions. Additionally, casing-size production tubulars differ in the soaping technique when compared with nominal diameter production strings. Guidelines are given for the proper placement of the soap stick, the quantities and frequency ofsoap stick use, the proper shut-in period (if any), the nature of the completion (deviated or vertical), and the allowable percentages of liquid hydrocarbons to be lifted.
Notes:
Session:
III --- Horizontal Wells
/ Session Chair:
Rodney Bane, ExxonMobil
Presentation Title:
III-3 --- Plunger Fall Velocity / Company(ies):
Echometer
Author(s):
Lynn Rowlan / Contact Information:

Abstract:
Data acquired at various wells will be used to correlate the construction features of different types of plungers with their fall velocity. Some construction features cause a plunger to fall rapidly, while other features cause the plunger to have a slower fall velocity. Well conditions (gas flow rate and pressure) have a significant impact on plunger fall velocity. The operator should know the conditions of the well and understand how these parameters impact plunger fall velocity. In general fall velocities determined for one field apply to all plunger lifted wells in the particular field, but fall velocities for the same type plunger can vary based on the well conditions. The published fall velocities can be used for each plunger type but may not be accurate for all wells, because fall velocity is impacted by following parameters:
1.  Diameter of Plunger – Larger is slower
2.  Effectiveness of seal between Plunger and Tubing – Better seal is slower
3.  Brush stiffness and seal
4.  Increased friction due to contact with the tubing
5.  Old age/wear increases plunger velocity
6.  Faster if valve opens to bypass sas
7.  Faster if tubing is worn OR slower if tubing is sticky
8.  Wellbore deviation
9.  Gas flow rate into the tubing
10.  PRESSURE OF GAS (High pressure is slow) and (Low pressure is fast)
By accurately measuring the plunger fall velocity, the proper shut-in time for the plunger lift installation can be determined. The knowledge of how various parameters impact plunger fall velocity allows the operator to ensure that the plunger has reached the bottom of the tubing by the end of the shut-in period. Setting the well’s controller to have the shortest possible shut-in time can maximize oil and gas production from the plunger lift well.