(2022010) New Mechanism of Sand Management Above ESPs
Presenters: Anderson Delgado, Jorge Espinosa, Gran Tierra; Luis Guanacas,  Gustavo Gonzalez, and Carlos Portilla,  Odessa Separator Inc.  

Extending the run life of wells with Electrical Submersible Pumps (ESP) becomes a crucial need since it is one of the most economically expensive types of ALS. Following the need, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump. This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump. Since the wells had sand problem history and it was necessary to review pump designs, pulling reports, and sensor parameters along with well conditions such as production, tubing size, and particle size distribution were analyzed to build the best design for every single well. In the design, the geometry of the well was assessed to accommodate the cable and CT line downhole. The Acordionero Field is characterized by heavy oil production (400-1000 BFPD), with a viscosity of 430 cP @ 150°F, API between 13-15, low water cuts (Between 3.9% to 20%), and high fine sand production (3000 - 5000 ppm). Cohembí Field wells produce between 1000 - 6000 BFPD, with API between 17-18, high water cuts (> 77%), and a high sand production between 500 - 3000 ppm. The wells selected had other types of sand control and management systems and were highly affected by frequent shutdowns. The Sand Regulator design was installed on 20 wells and was compared with the performance achieved using traditional sand control solutions. After the installation, production has remained stable in all the wells applied, allowing to reduce the PIP of the well from 900 psi to 500 psi. Less current consumption has been observed after each shutdown in all the wells, extending the run life of some wells from 108 days to more than a year. Sensor parameters were analyzed after each pump restart to determine how difficult it was to restart operation after shutdowns. Compared to the tools installed above the ESP, this sand regulator allows flushing operation through it with flow ranges from 0.5 to 5 bpm. In addition, the unconventional design of this tool has opened the door to a new concept of ESP protection that works in wells with light or heavy oil and can be refurbished or inspected completely without cutting the tool.

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New Mechanism of Sand Management Above ESPs
New Mechanism of Sand Management Above ESPs
Price
$7.50
(2022027) NON-CABLE Actuated Rod Rotator: Technology Development and Field Experiences
Presenters: Nicolas Guyubas, Martin Ruiz Palero, Daltec Oil Tools Rodrigo Ruiz, Duxaoil Texas LLC

The use of rod rotators is key to extend the life of sucker rod string couplings in all intentionally and not intentionally deviated wells. Its applicability has proved to be a low-cost solution, giving an even wear on sucker rod couplings, extending considerably their run time.
One of the major issues with conventional cable actuated rod rotators is the integrity of the cable, its installation and proper maintenance. It’s common to heard from operators losing the cable connection and ending up on a premature failure on sucker rod couplings due to localized wear.


Initially designed as a solution for long stroke belt driven units, where cable rod rotators weren’t reliable, a telescopic arm actuated rod rotator solves the issue with minimal down time. This innovation then was implemented in conventional pumping unit setups providing reliable rotations of sucker rod strings.


This paper describes the development process for the telescopic arm actuated rod rotator and the case studies in their initial set of applications in operation.
 

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NON-CABLE Actuated Rod Rotator: Technology Development and Field Experiences
NON-CABLE Actuated Rod Rotator: Technology Development and Field Experiences
Price
$7.50
(2022002) Optimizing Rod Lift Operations with Edge Computing
Presenters: Jared Bruns and Abhishek Sharma, Schlumberger  Will Whitley, Oasis Petroleum 

Modern sucker rod pump operations rely on pump-off controller’s, surveillance dashboards, and human intervention to maximize production and pump performance. As a result, rod pump operations often suffer from high manual workload, limited diagnostics and dynamic well conditions. For wells fitted with pump-off controllers and variable speed drives, challenges remain around data gathering and evaluation. Bringing well specific insights to action requires continuous physical supervision to ensure well uptime. Edge computing and Internet of things (IoT) technologies offer high frequency data gathering, real-time evaluation and a reliable mechanism to maximize rod pump productivity while automating redundant tasks. Advanced computations, enabled by edge computing, allow for a more comprehensive analysis of pump conditions that compliments and surpasses the capabilities of pump off controller automation. This paper will demonstrate how closed loop algorithms deployed on edge computers work to ensure the best operating conditions, autonomous dynacard evaluation and interventions, and a proactive approach to help manage anomalous, high failure wells. 

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Optimizing Rod Lift Operations with Edge Computing
Optimizing Rod Lift Operations with Edge Computing
Price
$7.50
(01) INTELLIGENT ROD LIFT SYSTEM: FAULT DETECTION AND ACCOMMODATION
Presenters: Omar Al Assad, Justin Barton, Rogier Blom, Ravi YB, Mahalakshmi SB GE Global Research Gary Hughes, Eric Oestrich, Peter Westerkamp and Craig Foster GE Lufkin Automation

 Unplanned rod lift system outages often lead to long and costly repairs in addition to direct production loss. Leveraging design knowledge of the rod lift system combined with real-time condition monitoring represents a promising avenue to mitigate this problem. This study will demonstrate an application of advanced monitoring and diagnostic analytics on data from vibration, strain, current and voltage sensors installed in critical locations of a beam pumping unit.

 

When pumping conditions deviate from the norm, the operators are alerted with regard to pending failures, and a supervisory control layer takes immediate action to adjust the operational pumping speed profile to maintain production at a safe operational level or shut down the equipment in the event of imminent catastrophic failure.

 

This paper will review the sensor installations and data acquisition approach. Experimental field test results will be presented and discussed.

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Paper: (01) INTELLIGENT ROD LIFT SYSTEM: FAULT DETECTION AND ACCOMMODATION
Paper: (01) INTELLIGENT ROD LIFT SYSTEM: FAULT DETECTION AND ACCOMMODATION
Price
$7.50
(02) THE MEASUREMENT OF DOWN STROKE FORCE IN ROD PUMPS
Presenters: Paul Bommer, A.L. Podio and Grayson Carroll University of Texas at Austin

During the down stroke the plunger in a rod pump must fall through a barrel that is filled with fluid. The plunger will establish a free fall velocity that is determined by the forces resisting downward motion. The free fall of the plunger may not be large enough to correspond to the actual velocity necessary to match the pumping speed set by the pumping unit. In this case the plunger must be pushed into the barrel by a compressive force in order to match the pumping velocity. The compressive force may be large enough to cause buckling in the lowest section of sucker rods. The purpose of this paper is to test this hypothesis by presenting measurements of the free fall velocity of a plunger in a liquid filled barrel and the pushing force necessary to exceed the free fall velocity of the plunger in the barrel. Simple models are shown to relate the measurments to practice.

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Paper: (02) THE MEASUREMENT OF DOWN STROKE FORCE IN ROD PUMPS
Paper: (02) THE MEASUREMENT OF DOWN STROKE FORCE IN ROD PUMPS
Price
$7.50
(03) A COMPARISON OF VARIABLE SPEED DRIVES AND PUMP-OFF CONTROLLERS IN AN UNCONVENTIONAL RESERVOIR
Presenters: Hannah Mitchell and Lee Coggins Chesapeake Energy

Variable Speed Drives (VSDs) are a popular rod lift control system for operators that are willing to pay a premium for the promise that they can squeeze every last drop from a producing formation. However, initial results from the Eagle Ford suggest that VSDs may not be worth the additional expense when compared to the performance of their less complex cousin, the Pump-Off Controller (POC). In particular, high CAPEX and maintenance costs along with performance issues on gassy, sand producing, shale wells are leading some operators to choose POCs over VSDs for unconventional reservoir applications. 

 

Furthermore, brief disruptions in production have less of an impact on the reservoir inflow of tight shales than that of higher permeable conventional reservoirs. This study is based on the examination of the performance of Eagle Ford wells that were initially controlled by VSDs and then swapped to POCs.

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Paper: (03) A COMPARISON OF VARIABLE SPEED DRIVES AND PUMP-OFF CONTROLLERS IN AN UNCONVENTIONAL RESERVOIR
Paper: (03) A COMPARISON OF VARIABLE SPEED DRIVES AND PUMP-OFF CONTROLLERS IN AN UNCONVENTIONAL RESERVOIR
Price
$7.50
(03) A COMPARISON OF VARIABLE SPEED DRIVES AND PUMP-OFF CONTROLLERS IN AN UNCONVENTIONAL RESERVOIR
Presenters: Hannah Mitchell and Lee Coggins Chesapeake Energy

Variable Speed Drives (VSDs) are a popular rod lift control system for operators that are willing to pay a premium for the promise that they can squeeze every last drop from a producing formation. However, initial results from the Eagle Ford suggest that VSDs may not be worth the additional expense when compared to the performance of their less complex cousin, the Pump-Off Controller (POC). In particular, high CAPEX and maintenance costs along with performance issues on gassy, sand producing, shale wells are leading some operators to choose POCs over VSDs for unconventional reservoir applications. 

 

Furthermore, brief disruptions in production have less of an impact on the reservoir inflow of tight shales than that of higher permeable conventional reservoirs. This study is based on the examination of the performance of Eagle Ford wells that were initially controlled by VSDs and then swapped to POCs.

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Paper: (03) A COMPARISON OF VARIABLE SPEED DRIVES AND PUMP-OFF CONTROLLERS IN AN UNCONVENTIONAL RESERVOIR
Paper: (03) A COMPARISON OF VARIABLE SPEED DRIVES AND PUMP-OFF CONTROLLERS IN AN UNCONVENTIONAL RESERVOIR
Price
$7.50
(04) UNDERSTANDING AND MITIGATING DOWNHOLE CORROSION AND WEAR FAILURES
Presenters: Rob Davis, Michael Naguib and Bill Snider Western Falcon Energy Services

A discussion on different types of corrosion and wear (and their associated mechanisms) will be followed by an overview of commercially available mitigation techniques including their practical field applications downhole. Commonly available information that can be used to determine exactly why downhole failures occur will be reviewed.  The importance of using preferred life extension procedures to maximize the Mean Time Between Failures (MTBF) and solve the root cause(s) of downhole failures are also covered.  Finally, this paper includes a review of various metallurgical options, nonmetallic materials, chemical treatments, mechanical methods, liners and coatings currently used downhole focusing on the advantages and limitations of each product.  Commonly accepted practices and myths about downhole corrosion and wear will be exposed.

The objective of this paper is to assist production, completion, artificial lift and enhanced recovery engineers in understanding and avoiding downhole corrosion and wear failures cost effectively.

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Paper: (04) UNDERSTANDING AND MITIGATING DOWNHOLE CORROSION AND WEAR FAILURES
Paper: (04) UNDERSTANDING AND MITIGATING DOWNHOLE CORROSION AND WEAR FAILURES
Price
$7.50
(05) PUMP STROKE OPTIMIZATION: CASE STUDY OF TWENTY WELL PILOT
Presenters: William G. Elmer Encline Artificial Lift Technologies LLC

 The concept of Pump Stroke Optimization was introduced in September 2015 at the ALRDC Sucker Rod Pumping Workshop.  Significant benefits to the sucker rod pumping system are obtained by preferentially slowing the downstroke (when pump capacity exceeds a wells productivity), while keeping a fast upstroke. These benefits are: Less pump slippage, less gas interference, and higher pump fillage, which results in less strokes per day for the same production, which results in less downhole wear. Higher minimum load translate into less rod buckling forces. 

Pump Stroke Optimization also includes automatic adjustment of upstroke and downstroke speeds to keep from overpumping wells, and is particularly effective for horizontal oil wells.

The results of a 20 well 2016 test program will be presented.

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Paper: (05) PUMP STROKE OPTIMIZATION: CASE STUDY OF TWENTY WELL PILOT
Paper: (05) PUMP STROKE OPTIMIZATION: CASE STUDY OF TWENTY WELL PILOT
Price
$7.50
(06) A CASE HISTORY: 131 FAILURES TO 30 - FAILURE CONTROL PRINCIPLES IN THE MIDLAND BASIN
Presenters: Kevin Flahive-Foro Resolute Energy Corp.

Depressed oil prices drive producers to reduce operating expenses and maximize profit margins. Some of these expenses are necessary for day-to-day operations, and are dictated by vendor pricing. Others are a function of the operator’s activity, and can be controlled within certain limits. Workover costs are a prime example of these “controllable” expenses. That being said, well failure control programs are essential to maximizing profits and limiting expenses.

In 2014, Resolute Energy recognized the need for a more effective failure program in their Gardendale, TX asset. Through organizational, managerial, and engineering efforts, Resolute successfully decreased well failures by nearly 90 year-to-year, resulting in expense savings of nearly $4.5 million. 

These savings, along with other expense control efforts, cut lifting cost in half throughout the 101 wells. This paper describes these control efforts in detail to reinforce their importance, particularly in current market conditions.

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Paper: (06) A CASE HISTORY: 131 FAILURES TO 30 - FAILURE CONTROL PRINCIPLES IN THE MIDLAND BASIN
Paper: (06) A CASE HISTORY: 131 FAILURES TO 30 - FAILURE CONTROL PRINCIPLES IN THE MIDLAND BASIN
Price
$7.50
(07) SAND FLUSH PLUNGER PERFORMANCE IN THE HWY 80 FIELD
Presenters: Sergio Granados, Brad Rogers, Rodney Sands, Harbison Fischer Rowland Ramos and Albert Garza, Pioneer Natural Resources Matt Horton and Johnny Bunsen, Tommy White Supply

Field case studies for the patented Sand Flush Plunger™ (patent #8,535,024) have been performed at the Hwy 80 field operated by Pioneer Natural Resources. Pump repair and well conditions data was collected from the pump and well tracker systems used by the service providers of the field. 

 

Standard pump repair information dated since 1989, while the Sand Flush Pump begun usage on 2009.  Interestingly, the results show that the average run time for the Sand Flush Pump is 840 days out of 560 well workovers that used it, while for a Standard Pump (Metal and Grooved Plunger) is 561 days out of

5313 workovers. Within the 560 wells that have tested the Sand Flush Plunger, 165 used both types of plungers providing a more detail correlation. From these, the Sand Flush averaged 1307 run days compared to the 604 days of a Standard Pump.

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Paper: (07) SAND FLUSH PLUNGER PERFORMANCE IN THE HWY 80 FIELD
Paper: (07) SAND FLUSH PLUNGER PERFORMANCE IN THE HWY 80 FIELD
Price
$7.50
(08) REVIEW OF CASE HISTORIES IN HYDRAULIC LIFT FOR DIFFERENT WELL CONDITIONS THAT DEMONSTRATE THE IMPORTANCE OF INTEGRATED DESIGN AND EQUIPMENT SELECTION AS WELL AS A NEED FOR INCREASED PRODUCT DEVELOMPENT
Presenters: Jesse Hernandez, Global Petroleum Technologies Luis Alberto and Diaz Martinez, CTX-Energy Dubai

Gassy low pressure stratified reservoirs require special jet pump well completion and equipment selection considerations. These reservoirs often experience a 50% reservoir pressure decline within the first 14 months of production but can continue to produce for many years below the saturation pressure. Jet pumps can be installed in wells in many ways. The most common, lowest cost and simplest well completion design is the “casing free installation”, but as reservoir pressure declines below the saturation pressure, gas liberation often results in gas accumulation and slugging under the casing packer that is used in this design.

 

Beam pumping systems have proven successful in the Permian Basin for many years. The beam pumping system allows gas separation and gas flow up the casing annulus. A concentric coil tubing jet pump well completion offers downhole gas separation with options to improve desired effects. Successful case histories are presented to support the application.

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Paper: (08) REVIEW OF CASE HISTORIES IN HYDRAULIC LIFT FOR DIFFERENT WELL CONDITIONS THAT DEMONSTRATE THE IMPORTANCE OF INTEGRATED DESIGN AND EQUIPMENT SELECTION AS WELL AS A NEED FOR INCREASED PRODUCT DEVELOMPENT
Paper: (08) REVIEW OF CASE HISTORIES IN HYDRAULIC LIFT FOR DIFFERENT WELL CONDITIONS THAT DEMONSTRATE THE IMPORTANCE OF INTEGRATED DESIGN AND EQUIPMENT SELECTION AS WELL AS A NEED FOR INCREASED PRODUCT DEVELOMPENT
Price
$7.50
(09) THE EFFECT RELIEVING CASING PRESSURE HAS ON BOTTOM HOLE PRESSURE
Presenters: Mark Lancaster and Charlie McCoy Permian Production Equipment, Inc.

We will show in multiple cases studies the effect of relieving back pressure on a oil well has in relationship to the producing bottom hole pressure, pump efficiency and over all economics of the well.

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Paper: (09) THE EFFECT RELIEVING CASING PRESSURE HAS ON BOTTOM HOLE PRESSURE
Paper: (09) THE EFFECT RELIEVING CASING PRESSURE HAS ON BOTTOM HOLE PRESSURE
Price
$7.50
(10) USING ROD GUIDES EFFECTIVELY IN VERTICAL WELLS: WEST TEXAS WATERFLOOD CASE HISTORY
Presenters: Rebecca J. Larkin BOPCO, LP

Metal to metal contact shortens the run life of both tubing, steel and fiberglass sucker rods.  Using sacrificial rod guides can extend this life at the expense of increased side and axial loading enhanced by Coulomb friction effects.  The problem is not limited to directional and horizontal wells.  Just how crooked are our vertical wells?  Simple inclination surveys insufficiently describe the wellbore path drilled.  Knowledge of failure history, inclination and azimuth of wellbore path, plus access to a rod design program provide insight into effective placement of rod guides and longer run life.  A case history from an established West Texas waterflood is presented to illustrate the application.

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Paper: (10) USING ROD GUIDES EFFECTIVELY IN VERTICAL WELLS: WEST TEXAS WATERFLOOD CASE HISTORY
Paper: (10) USING ROD GUIDES EFFECTIVELY IN VERTICAL WELLS: WEST TEXAS WATERFLOOD CASE HISTORY
Price
$7.50
(11) DYNOMOMETER CONCERNS
Presenters: James Lea, Mark Garrett, Mike Brock, and Cort Visniesiki PLTech, LLC

Downhole dynamometer cards can be generated by predictive and diagnostic wave computer programs. Those generated by the diagnostic program are best for trouble shooting as they are calculated from a measured surface card. Several aspects of the bottom cards are presented in discussed in this paper some of which are well known and used and some which are less recognized.

 

For cards showing gas fill, the location of the TV closing is not the location in the downhole stroke where liquid fill begins. However it is close for low pressure wells. The shape of the load release can indicate if the well has low or high intake pressure. The pump load is indicated if the card is scaled correctly and generated by approximately correct damping or drag coefficients along the rod. A delayed opening of the SV on the upstroke can indicate that the pump is not tightly spaced. The load release distance is incorrectly identified as an area where compression is occurring but this does not indicate compression in the rod above the pump but is where gas, is present, is being compressed below the TV and above the SV. Example are shown of the above.

 

If looking at only the downhole card, excursions below where the load pick-up began indicate a compression load in the rod above the pump. However high damping coefficients will reduce the apparent fluid load shown on the bottom hole dynamometer and will  also reduce the amount the bottom card may be showing apparent rod compression at the pump so the damping coefficients have an effect on apparent compression at the bottom hole card and these effects are illustrated. The shape of the bottom card can suggest if the damping coefficients are low or high. In general the predictive programs do not indicate compression at the pump unless pump resistance is guessed by the user but the bottom cards can indicate compression but the magnitude of indicated compression also depends on input for the diagnostic computer program.

 

Both the predictive and diagnostic programs can, under certain circumstance, indicate compression uphole from the pump due to dynamic effects. This can occur even with no pump resistance or rod compression at the pump.  Rod failure characteristics can show if the rod broke after repeated compression (pump resistance) but this is after the fact.

 

These factors and more are discussed and illustrated to hopefully make problem recognition easier for the operator.

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Paper: (11) DYNOMOMETER CONCERNS
Paper: (11) DYNOMOMETER CONCERNS
Price
$7.50
(12) ROD GUIDE STRATEGY FOR UNCONVENTIONAL BEAM PUMPED WELLS IN THE EAGLE FORD SHALE
Presenters: Leslie Malone Murphy Oil & Exploration Co.

Murphy is currently operating 500 beam pumped wells in the unconventional Eagle Ford Shale play in South Texas. There are numerous challenges to beam pumping operations in the Eagle Ford, which included paraffin, corrosion, solids, deviated wellbores, slug flow, and foamy gassy fluid.

 

One of the challenges, deviated wellbores, led to an increased frequency of failures due to metal to metal contact between the rod coupling and the tubing. The development of a rod guide strategy has significantly reduced the failure frequency of tubing and parted rod couplings due to wear.

 

The development of the strategy includes data from the failure data base, the use of tubing scanning, the proper placement of the guides and the use of the proper guide material.

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Paper: (12) ROD GUIDE STRATEGY FOR UNCONVENTIONAL BEAM PUMPED WELLS IN THE EAGLE FORD SHALE
Paper: (12) ROD GUIDE STRATEGY FOR UNCONVENTIONAL BEAM PUMPED WELLS IN THE EAGLE FORD SHALE
Price
$7.50
(13) CASE STUDY - GAS INTERFERENCE: MANAGE OR MITIGATE
Presenters: Leslie Malone Murphy Oil & Exploration Co.

Murphy is currently operating 500 beam pumped wells in the unconventional Eagle Ford Shale play in South Texas. There are numerous challenges to beam pumping operations in the Eagle Ford, which included paraffin, corrosion, solids, deviated wellbores, slug flow, and foamy gassy fluid. 

 

One of the challenges, foamy gassy fluid, led to a study of the effectiveness of downhole separators. The results of the case study will be presented along with conclusions on the ability to manage or mitigate gas interference in the beamed pumped wells Murphy operates in the Eagle Ford Shale asset.

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Paper: (13) CASE STUDY - GAS INTERFERENCE: MANAGE OR MITIGATE
Paper: (13) CASE STUDY - GAS INTERFERENCE: MANAGE OR MITIGATE
Price
$7.50
(14) PATENTED OILFIELD RFID SOFTWARE AND HARDWARE PACKAGE DELIVERS IMPROVED DOWNWELL PRODUCT ACCOUNTABILITY, QUALITY CONTROL, INVENTORY MANAGEMENT AND ASSET TRACKING
Presenters: Jon Martin, Matt Herget AND Daniel Long RFG Petro Systems

RFG Petro Systems’ provides custom wireless and digital serial number tags for use within the well-bore infor and attached to the rod string components to assign its recorded quality control system data (batch mation, pressures, times, temperatures, manufacturing date/conditions) and logistics of the product from creation to end-of-life. RFG’s custom hardware and software package allows for the user to scan a product at any time and retrieve its manufacturing and logistics history, better controlling inventory management and asset tracking. By creating new time/date stamps and specific user-controlled instances within the system during the products use, data can be linked with a time-stamp to track and trace how great a product performs over time. Every instance and data-set taken is provided to the manufacturer for continuous product improvement. RFG can license this patented product, software, use and application to manufacturers leading to greater transparency and enhanced products for industry.

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Paper: (14) PATENTED OILFIELD RFID SOFTWARE AND HARDWARE PACKAGE DELIVERS IMPROVED DOWNWELL PRODUCT ACCOUNTABILITY, QUALITY CONTROL, INVENTORY MANAGEMENT AND ASSET TRACKING
Paper: (14) PATENTED OILFIELD RFID SOFTWARE AND HARDWARE PACKAGE DELIVERS IMPROVED DOWNWELL PRODUCT ACCOUNTABILITY, QUALITY CONTROL, INVENTORY MANAGEMENT AND ASSET TRACKING
Price
$7.50
(16) CONTINUOUS RODS - WOLFCAMP SHALE
Presenters: Blake Myers EP Energy

This presentation will provide information about the operational advantages and disadvantages of continuous rods.  By removing the pins and couplings in a deviated well, side loading is distributed across a larger area reducing the severity of wear on the rods and the tubing.  The types of continuous rods will be reviewed and operational data presented to assist others in evaluating their potential use of continuous rods.

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Paper: (16) CONTINUOUS RODS - WOLFCAMP SHALE
Paper: (16) CONTINUOUS RODS - WOLFCAMP SHALE
Price
$7.50
(17) GAS LIFT-JET PUMP HYBRID COMPLETION REDUCES NONPRODUCTIVE TIME DURING UNCONVENTIONAL WELL PRODUCTION
Presenters: Osman A. Nunez-Pinon, Toby Pugh and James Hubbard Weatherford International Inc.

The addition of a sliding sleeve door (SSD) to the tubing string, installed between the deepest gas lift mandrel and the annular packer, will allow the deployment of a wireline-set jet pump. The backup jet pump provides a valuable and cost-effective alternative in several potential scenarios: when unloading fracking fluids before beginning gas-lift production, when restoring production after an unpredicted shutdown of the gas-lift compression system, and when the producing water cut becomes higher than expected.

This simple but ingenious dual-purpose completion approach has already proved to solve the problem of unconventional well production load-up during the early production stage of gas lifted systems. The information provided in this paper will help operators plan, design, deploy, and operate a dual-purpose gas lift-jet pump well completion.

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Paper: (17) GAS LIFT-JET PUMP HYBRID COMPLETION REDUCES NONPRODUCTIVE TIME DURING UNCONVENTIONAL WELL PRODUCTION
Paper: (17) GAS LIFT-JET PUMP HYBRID COMPLETION REDUCES NONPRODUCTIVE TIME DURING UNCONVENTIONAL WELL PRODUCTION
Price
$7.50
(18) ELECTRICAL SUBMERSIBLE PUMP PERFORMANCE IN THE PERMIAN (DELAWARE) BASIN UNCONVENTIONAL FORMATION
Presenters: Peter Oyewole, BOPCO LP Marshall Gilbert, Summit ESP

Achieving consistent, sustained run life with electrical submersible pumps in the unconventional play of the Permian Basin can be difficult due to a variety of harsh well conditions. More specifically, high free gas rates and abrasives contribute to the majority of well service call outs.  Common operating practices are well established to some positive effect, such as running at lower frequencies to mitigate abrasive wear and loading motors appropriately for efficient operation.  BOPCO operates several wells in the area and looked to further optimize ESP production in order to reduce operating expense and increase profitability.  Working together with Summit ESP, a new set of operational standards for these unconventional wells was developed and initiated using a step-wise approach to analyzing individual well performance and operating parameters, then comparing results across the field as various processes and tools were implemented.  In conjunction with the traditional settings, the team implemented a more robust sensor package including a discharge pressure gauge and tubing and casing transducers that are monitored by a highly trained ESP Well Management Team to assist in all troubleshooting.  Further, new gas handling technologies have proven successful in improving up-time with fewer shutdowns.  This dynamic combination has proven to be more efficient and profitable.

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Paper: (18) ELECTRICAL SUBMERSIBLE PUMP PERFORMANCE IN THE PERMIAN (DELAWARE) BASIN UNCONVENTIONAL FORMATION
Paper: (18) ELECTRICAL SUBMERSIBLE PUMP PERFORMANCE IN THE PERMIAN (DELAWARE) BASIN UNCONVENTIONAL FORMATION
Price
$7.50
(19) GAS LIFT IN A BEAM WORLD: GETTING YOU WELLS, FACILITIES AND PERSONNEL IN ORDER
Presenters: Kyle Ritcher, Jason Wolf and Keith McKenzie Occidental Petroleum Corporation

This paper will discuss well applicability for gas lift installations, including identifying the best candidates for lift conversion, reasons for converting including benefits in a capital constrained environment.  We’ll discuss GOR, deviated wells, solids handling, typical production rates, while comparing to other popular lift types’ efficiency and range. 

 

While particular wells may be good candidates based on the aforementioned criteria, surface considerations also play a pivotal role in gas lift installations.  We’ll discuss infrastructure impact of electric vs gas powered compressors, as operators seek to minimize grid impact of artificial lift.  Field-wide opportunity costs of gas & electric supply, fluid processing considerations at CTBs, and permitting will also be discussed.  Finally, this paper will cover  operating considerations and installed equipment to enable successful operations (metering, control, protection, all-weather reliability, automation/surveillance, safety). 

 

Operating practices, maintenance, training, and personnel costs are discussed in this final section, as gas lift is only successful with qualified operations personnel.  We’ll compare and contrast gas lift operations to other lift types, and will feature differences in surveillance & troubleshooting.

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Paper: (19) GAS LIFT IN A BEAM WORLD: GETTING YOU WELLS, FACILITIES AND PERSONNEL IN ORDER
Paper: (19) GAS LIFT IN A BEAM WORLD: GETTING YOU WELLS, FACILITIES AND PERSONNEL IN ORDER
Price
$7.50
(20) TUBING AND WELLHEAD INTEGRITY PRESSURE TEST
Presenters: Joseph Norman, Forty A&M LLC Lynn Rowlan, Carrie Anne Taylor and James N. McCoy, Echometer Company

When a hole in the tubing, HIT, is suspected, then confirm the HIT with a pressure test.  If no fluid is produced to the surface, then the test is performed by shutting down the well and pumping clean treated water into the tubing.  The tubing is usually pressured up to 500 psi(g) and the pressure is held for a time period.  If a hole is present, then the tubing pressure will quickly leak off.  A collar leak can take much longer time to leak off. If fluid is produced to surface, then the typical procedure is to use the sucker rod pump to increase surface pressure by pumping against a closed valve. 

 

If a sudden drop in production occurs, then a recommended practice is to pressure test the tubing, casing check valve, and tubing back pressure valve.  High speed tubing pressure data acquired in conjunction with a dynamometer test provides the operator with enhanced troubleshooting capability.

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Paper: (20) TUBING AND WELLHEAD INTEGRITY PRESSURE TEST
Paper: (20) TUBING AND WELLHEAD INTEGRITY PRESSURE TEST
Price
$7.50
(2014001) NEW TECHNOLOGY REDUCES ELECTRICAL ENERGY CONSUMPTION OF SUCKER ROD PUMPS BY 25%
Presenters: Anthony Allison, Weatherford

Lower lifting cost in the oil field is a never ending task. Over the years, many products from pump off controller to fiberglass rods have been used successfully to lower energy cost and extend the life of the well. MotorWise integrates the latest technologies, to substantially lower lifting costs even more. MotorWise combines two technologies: Soft Start and Power Synchronizing to deliver the precise amount of energy to the pump jack in real time. The technology has been deployed on over 2,000 wells in the Permian Basin. Three years of field data confirm the reduction in kWh and KW. This presentation will explain how MotorWise technology is applied in the oil field, the short and long term benefits and the return on investment math.

 
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Paper: (2014001)NEW TECHNOLOGY REDUCES ELECTRICAL ENERGY CONSUMPTION OF SUCKER ROD PUMPS BY 25%
Paper: (2014001)NEW TECHNOLOGY REDUCES ELECTRICAL ENERGY CONSUMPTION OF SUCKER ROD PUMPS BY 25%
Price
$7.50
(2014001) NEW TECHNOLOGY REDUCES ELECTRICAL ENERGY CONSUMPTION OF SUCKER ROD PUMPS BY 25%
Presenters: Anthony Allison, Weatherford

Lower lifting cost in the oil field is a never ending task. Over the years, many products from pump off controller to fiberglass rods have been used successfully to lower energy cost and extend the life of the well. MotorWise integrates the latest technologies, to substantially lower lifting costs even more. MotorWise combines two technologies: Soft Start and Power Synchronizing to deliver the precise amount of energy to the pump jack in real time. The technology has been deployed on over 2,000 wells in the Permian Basin. Three years of field data confirm the reduction in kWh and KW. This presentation will explain how MotorWise technology is applied in the oil field, the short and long term benefits and the return on investment math.

 
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Price: $7.50
Paper: (2014001)NEW TECHNOLOGY REDUCES ELECTRICAL ENERGY CONSUMPTION OF SUCKER ROD PUMPS BY 25%
Paper: (2014001)NEW TECHNOLOGY REDUCES ELECTRICAL ENERGY CONSUMPTION OF SUCKER ROD PUMPS BY 25%
Price
$7.50

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NEXT CONFERENCE: APRIL 17-20, 2023