Describe and Operate Beam Pump Module D - HDC · 2018. 5. 14. · account downhole pump operation,...

Describe and Operate Beam Pump

Human DevelopmentConsultants Ltd.

Module DOptimize Beam Pump Operation

Training Module

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DESCRIBE AND OPERATE BEAM PUMP Module D

Optimize Beam Pump Operation

May, 2009


© 2009 HDC Human Development Consultants Ltd. All rights reserved. No part of this publication may be copied, reproduced, stored in a computer or retrieval system, published, distributed, or transmitted in any form or by any means whatsoever, including without limitation by mechanical means, photo copying, recording, digital or electronic media, the Internet, or otherwise, without the express prior written permission of HDC Human Development Consultants Ltd. (HDC). HDC grants to the purchaser of a Single User License (as defined in the agreement with such purchaser) a limited license to store the electronic file(s) on one computer only and to make a single paper copy of this publication. HDC grants to the purchaser of a Site License (as defined in the agreement with such purchaser) a limited license to store the electronic file(s) on one local area network server accessible by individual users' computers at one site or location only and to make paper copies of this publication for a company’s employees at the same site or location only. Each site or location must purchase a separate Site License for employees at that site. HDC grants the purchaser of a Corporate License (as defined in the agreement with such purchaser) a limited license to store the electronic file(s) on its intranet and on computers at company sites or locations and to make paper copies for any or all employees. Nothing in the foregoing restricts, amends or abrogates the provisions of the agreement between HDC and the purchaser of the applicable license. Any copying or use other than pursuant to such a license is illegal. For further information, please consult the applicable license agreement. This publication is designed to provide general information regarding the subject matter covered. Care has been taken to ensure the accuracy of the information and that the instructions contained in this publication are clear and reflect sound practice. The user understands that HDC is not providing engineering services. The user understands that any procedures (task steps) that are published or referenced may have to be modified to comply with specific equipment, work conditions, company standards, company policies and practices, legislation, and user qualifications. HDC does not make any representations, guarantees, or warranties of any kind whatsoever with respect to the content hereof and the results to be achieved by implementing the procedures (task steps) herein. To the maximum extent permitted by applicable law, in no event shall HDC be liable for any damages whatsoever (including without limitation, direct or indirect damages for personal injury, damages to the environment, damages to business property, loss of business profit, or any other pecuniary loss). The use of the information and procedures (task steps) herein is undertaken at the sole risk of the user. ISBN 978-1-55338-045-0 Canadian Cataloguing in Publication Data 1. Oil well pumps. I. HDC Human Development Consultants. TJ901.D484 2009 622’.3382 C2009-902507-8 This training kit consists of the following parts: ♦ Training Module and Self-Check ♦ Knowledge Check and Answer Key

♦ Blank Answer Sheet ♦ Job Aid

Published by HDC Human Development Consultants Ltd.

Published in Canada

HDC Human Development Consultants Ltd. Website: www.hdc.ca E-mail: [email protected] Phone: (780) 463-3909



May, 2009 Page I of II


Foreword Beam pumps are used to lift a variety of liquids from subsurface wells to the surface. Beam pumps are commonly used at: oil wells to lift the oil to the surface gas wells to remove accumulated water which would

prevent the gas from entering the wellbore coal bed methane wells to remove water from coal seams

While HDC’s Describe and Operate Beam Pump series of training kits addresses beam pumping oil wells, the content applies to any beam pumping application. The series consists of four modules, listed below. These modules are designed to address the needs of oil well operators responsible for operating, monitoring, and optimizing existing beam pumping oil wells. The modules are task focused (i.e., center around what the operator does, why he/she does it, when he/she does it, and how). The modules are sequential: Module A is a prerequisite to Module B and so on. The four modules in the series are: Module A—Describe and Monitor Wellhead, Sucker Rod

String, and Subsurface Pump Module B—Describe and Monitor Pumpjack and Prime

Mover Module C—Describe Beam Pump Operation Module D—Optimize Beam Pump Operation

Modules A and B include: descriptions and principles of operation of typical surface

and subsurface beam pumping oil well equipment operating variables reasons for specific operating requirements causes for variables to change, consequences, symptoms,

and operator responses to abnormal operations monitoring tasks related to the equipment a walkthrough where the operator identifies the equipment

at his/her site self-check review questions a stand-alone knowledge check




Module C provides: a description of a typical beam pump wellsite an overview of beam pump oil well safety production monitoring and record keeping a description of routine beam pumping tasks:

– respond to oil well shutdowns – start up pumpjack oil well (engine) – start up pumpjack oil well (motor) – check pressure safety switch – pig flowlines – put sucker rod pump on tap – shut down pumpjack oil well; lock out; secure for

maintenance – change pumpjack stuffing box

self-check review questions a stand-alone knowledge check a stand-alone checklist for monitoring beam pump operation

Module D provides: a description of well performance analysis a description of pumping system analysis a description of pumping oil well diagnostics:

– fluid level detector – dynamometer – pumpjack load analysis

a description of pumping unit adjustments: – balance the pumping unit – change pumping speed – change stroke length – lower/raise sucker rod string – adjust casing gas or downstream pressure

a description of the operator’s role in optimization self-check review questions a stand-alone knowledge check a stand-alone troubleshooting table for beam pump

operation

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Contents

Foreword I

Training Objectives 1

1 Introduction 1

2

Crude Oil Composition, Reservoirs, and Well Production 4 2.1 Crude Oil Composition 4 2.2 Crude Oil Reservoirs and Recovery Methods 5 2.3 Reservoir Conditions that Decrease Productivity

of Beam Pump Wells 12

3

Analyzing Well Performance 16 3.1 Well Production Records 17 3.2 Diagnostic Tests to Identify Wellbore and/or

Reservoir Problems 18 3.3 Tests to Determine Well Casing Fluid Level 19 3.4 Tests to Determine Well Fluid Composition 20 3.5 Testing to Determine Well’s Production Potential 22

4

Analyzing Beam Pumping System Performance 24 4.1 Calculating Well Operating Costs 25 4.2 Determining that the Pumpjack is Balanced 25 4.3 Analyzing Downhole Pump Operation 28

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Contents (continued)

5

Using Fluid Level Detectors and Dynamometers 28 5.1 Fluid Level Detector 28 5.2 Dynamometer 31 5.3 Processing Diagnostic Test Data 35

6

Adjust the Pumping Unit 37 6.1 Change Pumping Speed 38 6.2 Adjust Casing Gas Pressure 42 6.3 Balance Beam Pumping Unit 43 6.4 Change Stroke Length 47

7 Operator’s Role in Optimization 48

8 Self-Check 50

9 Self-Check Answer Key 54

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Prerequisites Module A—Describe and Monitor Wellhead, Sucker Rod String, and Subsurface

Pump Module B—Describe and Monitor Pumpjack and Prime Mover Module C—Describe Beam Pump Operation

Training Objectives

Upon completion of this training kit, you will be able to: Describe oil composition, reservoirs, and well production Describe well performance analysis Describe pumping system analysis Describe diagnostics − fluid level detector − dynamometer − processing diagnostic test data

Describe pumping unit adjustments − change pumping speed − adjust casing gas pressure − balance the pumping unit − change stroke length

Describe the operator’s role in optimization

1 Introduction A beam pumping system at an oil well (shown in Figure 1) consists of: a pumpjack (beam pumping unit) at the surface a downhole pump (sucker rod pump at the bottom of the well) a sucker rod string (including polished rod) which connects

the pumpjack to the downhole pump a prime mover (internal combustion engine or electric motor)

which provides the energy for pumping the well

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Figure 1—Beam Pumping System at a Cased Oil Well





Optimizing an oil well means maximizing oil production as cost-effectively as possible (without damage to the beam pumping system, well, and reservoir). Well optimization is achieved through the joint efforts of oil well operators, company engineers, and third party well service contractors. To optimize an oil well, engineers conduct studies to analyze: current well performance. This analysis takes into account

well design and history, daily production records, and production and diagnostic test data provided by well operators or third party contractors.

beam pumping system performance. This analysis takes into account downhole pump operation, prime mover efficiency, and beam pump/sucker rod loading.

Because the interrelation between reservoir, wellbore, and pumping system components is very complex, beam pumping system operating parameters usually should not be changed until company engineers have completed their analyses and made specific recommendations. After completing their analyses, company engineers may prescribe specific adjustments to optimize the well (e.g., decrease casing pressure, increase pump speed, or decrease stroke length). The well operator (or a third party contractor) makes the adjustments and then closely monitors the well and beam pumping system to identify any problems. The operator may also be directed to perform additional tests so that the engineers can confirm the well is optimized or recommend further adjustments.

Section 7 of this module lists some of the operator’s specific monitoring responsibilities. The Job Aid that accompanies this module is a troubleshooting chart for diagnosing beam pumping system problems.





Because the operator is the person most familiar with the well and beam pumping system, he/she plays a key role in optimization. Critical tasks include: closely monitoring well production and beam pumping system

operation to identify changes reporting changes in production and/or beam pumping

system operation as quickly as possible. Timely reporting ensures problems are investigated/analyzed and rectified at an early stage––before a significant loss occurs.

conducting diagnostic tests carefully and according to the approved procedures. Properly-conducted tests provide engineers with the quality data (i.e., complete, accurate, and repeatable) needed to: – effectively analyze the well – determine beam pumping system adjustments to optimize

the well making the adjustments to the beam pumping system and

reporting the results back to the engineers

2 Crude Oil Composition, Reservoirs, and Well Production

2.1 Crude Oil Composition Crude oil composition varies depending on the depth and type of the reservoir and the age of the well. Most crude oil is a mixture of oil, water (typically a brine solution), gases, and solids (sand or sediment). The relative proportions of these components within a sample of oil are key factors for deciding whether production will be cost-effective. Crude oils contain two types of water: free (non-emulsified) water––water that can be readily

separated from the oil (e.g., by gravity) entrained (emulsified) water—water that cannot be readily

separated from the oil. Water has combined with the crude oil and emulsifying agents in the oil (specific types of naturally-occurring solids or liquids) to form an emulsion.





The amount of water in the crude oil from a given well generally increases over the life span of the well. Crude oils also contain: free and/or dissolved gases (e.g., methane, ethane, hydrogen

sulfide) solids, including hydrocarbon residues (e.g., asphaltenes and

paraffin) and non-hydrocarbon particulates (e.g., sand, mud, silt, clay)

As described in Module C, many wellsites are equipped with a two or three-phase separator for separating the entrained gases, liquids, and solids from the oil. Oil with emulsified components requires additional treatment to separate the water from the oil.

Emulsions An emulsion is the suspension of one liquid in a second liquid. Crude oil emulsions are either: oil droplets surrounded by water

OR, water droplets surrounded by oil

Emulsifying agents in the reservoir/wellbore (e.g., waxes, paraffins, organic acids, salts, drilling mud, sand, shale) coat each droplet, stabilizing the emulsion and preventing the oil and water from separating readily. Crude oil emulsions are directed to specialized equipment (e.g., heater treater), where demulsifying chemicals and/or heat are applied to break the emulsion into separate components.

2.2 Crude Oil Reservoirs and Recovery Methods An oil reservoir is a porous rock formation that holds crude oil. As shown in Figure 2, some reservoirs have: an underlying or adjacent aquifer (a rock formation holding

water) an overlying layer of non-permeable rock that acts as a top

barrier to contain gases within the reservoir. The layer is known as the cap rock.





Figure 2—Oil Reservoir

To produce oil from a reservoir, different recovery methods are used. The three methods are: primary recovery secondary recovery tertiary recovery

Beam pumps can be used in all three recovery methods. When a beam pump is used, beam pump operation must be optimized to match reservoir conditions and oil production targets.

Primary Recovery In primary recovery reservoirs, oil wells are free flowing. The high pressure in the reservoir pushes the oil towards the well and up the well bore to the surface. The high pressure results from gas or water pressure on the oil: Gas Drive—In a reservoir’s gas cap, free gas pushes down

on the oil (see Figure 3) to force the oil to the surface. Water Drive—Water from an underlying or adjacent high

pressure aquifer pushes up on the oil (see Figure 4) to force the oil to the surface.





Figure 3—Primary Recovery: Gas Drive

Figure 4—Primary Recovery: Water Drive

For some reservoirs, the reservoir pressure is not high enough to obtain satisfactory production flowrates. In these cases, a beam pump is installed after a new well is completed. For other reservoirs, when a new well is completed, the reservoir pressure is adequate to obtain satisfactory free-flowing production. Over time, the pressure in the reservoir begins to drop. The dropping pressure causes the flowrate of oil from the well to drop. In response, corrective actions are implemented to maintain high oil flowrates, including: installing a beam pump on the well to pump the oil to the

surface from the primary recovery reservoir





implementing secondary recovery methods to

maintain/restore reservoir pressure and thereby maintain the oil flowrate

At beam-pumped wells in primary recovery reservoirs, the Operator: monitors production flowrate, pressure, and composition notifies company engineer in case of significant changes. The

changes may indicate problems with the well’s operation or with the reservoir’s gas/water drive.

Secondary Recovery In secondary recovery reservoirs, an injected flow of pressurized gas or water provides the reservoir pressure: the pressure may be sufficient to drive the crude oil towards

the well and up to the surface through free flowing oil wells the pressure may only be sufficient to drive the crude oil

towards the well. A beam pump then pumps the oil to the surface.

The following terms are used to describe the injection of a pressurized flow into a secondary recovery reservoir: Gas Injection—Pressurized gas (e.g., methane and ethane)

is injected into the reservoir’s gas cap (through injection wells)to maintain pressure on the oil below.

Waterflood—Pressurized water is pumped (through injection wells) into the water layer below the oil production zone. The source of the water is either: – recycled water (water separated from the oil at a battery) – surface water (from rivers and lakes)

When a new oil reservoir’s pressure is low, secondary recovery may be used to start oil production from that reservoir.





At beam-pumped wells in secondary recovery reservoirs, the Operator: monitors production flowrate, pressure, and composition notifies company engineer in case of significant changes. The

changes may indicate problems with the: – beam-pumped well’s operation – operation of the reservoir’s:

gas injection program and its injection wells waterflood program and its injection wells

Tertiary Recovery In some reservoirs, tertiary recovery methods are needed because: oil still remains in the reservoir after primary and secondary

recovery. The remaining oil is either emulsified with water or clinging as a coating to the reservoir rock and its pores.

the oil is so viscous that primary and secondary recovery are ineffective at removing any oil from the reservoir

Tertiary recovery methods mobilize the oil so that the oil flows towards the well. A beam pump then pumps the oil to the surface. Tertiary recovery methods consist of two types: miscible displacement thermal flooding

Miscible displacement—To recover more oil from a reservoir after primary and secondary recovery, miscible fluids are injected into the reservoir through injection wells. The miscible fluids used are: carbon dioxide gas hydrocarbon gases and liquids nitrogen gas

The miscible fluid acts as a solvent that sweeps through the reservoir. The miscible fluid dissolves: oil that coats the surfaces and flow passages of the reservoir

rock oil trapped in the pores of the permeable reservoir rock the film surrounding the droplets in an emulsion





The oil/water/miscible fluid mixture has a lower viscosity than the reservoir’s oil and thereby flows more easily to the production wells. At production wells, beam pumps then pump the fluid mixture to the surface for separation at production facilities. After separation of the oil/water/miscible fluid, the miscible fluid is reinjected. The injected miscible fluid may not sweep evenly through the reservoir. Instead, the fluid may flow directly (i.e., channel) towards a production well and miss areas in the reservoir with recoverable oil. To prevent channeling, a switching process is sometimes used at injection wells: a period of miscible fluid injection is followed by a period of

displacement liquid (typically water) injection. The process then repeats.

the miscible fluid advances evenly through the reservoir because the miscible fluid is moved along between batches of displacement liquid

At beam-pumped wells in miscible-flood reservoirs, the Operator: monitors production flowrate, pressure, and composition notifies company engineer in case of significant changes. The

changes may indicate problems with the: – beam-pumped well’s operation – operation of the miscible fluid injection wells – flow of the miscible fluid through the reservoir

Thermal flooding—In heavy oil reservoirs, the oil is so viscous that primary and secondary recovery methods cannot remove the oil from the reservoir. Oil recovery therefore starts with a tertiary recovery method known as thermal flooding. In thermal flooding, heat is added to the heavy oil reservoir to lower the oil’s viscosity to enable the heavy oil to flow to the wellbore. Three thermal flooding methods are described in Figure 5.

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Figure 5––Thermal Flooding Methods

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Beam pumps are used to pump the oil to the surface in all three thermal flood methods. At these beam-pumped wells, the Operator: monitors production flowrate, pressure, and composition notifies company engineer in case of significant changes. The

changes may indicate problems with the: – beam-pumped well’s operation – operation of the thermal flood program such as:

steam injection problems on a SAGD reservoir incorrect length of the steam injection cycle in a

cyclical steam stimulation reservoir problems with the flame front’s movement through a

fireflooded reservoir

2.3 Reservoir Conditions that Decrease Productivity of Beam Pump Wells

Well operators provide production testing results (from beam pump wells) to company engineers who monitor well productivity. Through monitoring, company engineers identify decreasing oil production, investigate the problem, and determine solutions. Oil production decreases because of: increased gas production increased water production production zone/downhole blockages

Increased Gas Production

Primary Recovery In a primary recovery reservoir, operating the beam pump at an excessive production flowrate can result in a sudden problem known as gas breakthrough (see Figure 6): Because of the excessive production flowrate, too much oil is

pulled from the reservoir area surrounding the well. The oil from further regions of the reservoir is not able to flow

in time towards the well to refill the depleted area. Instead, gas flows down from the reservoir’s gas cap to fill the depleted area around the well. The result is a: – rapid decrease in oil production – rapid increase in gas production

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Figure 6—Gas Breakthrough

Secondary Recovery In a gas drive reservoir, continued oil production from the beam pumped wells causes the thickness of the oil layer to decrease. The reservoir’s gas cap pushes down as oil is pumped from the wells. As the gas layer pushes downward, the well gradually begins to produce more associated gas. The increased gas production is detected through production testing at a field test separator or at an offsite tank battery.

Tertiary Recovery Because the interrelation between a tertiary recovery reservoir and its beam pumped wells is complex, well operators should consult company engineers when gas production increases from wells in: a reservoir undergoing miscible displacement. For example,

the increased gas production may actually be the injected miscible fluid that has channeled directly towards the beam pump well (without sweeping evenly through the reservoir).

a thermally flooded reservoir

Increased Water Production

Primary Recovery In a primary recovery reservoir (that uses beam pumps), the aquifer pushes upwards as oil is pumped from the wells. The water nearing the wells may cause either a gradual or rapid increase in the water produced by the well: a slow increase is the normal sign of an aging well. The water

layer is gradually rising evenly towards the well.

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a rapid increase is normally the result of operating the beam

pump at an excessive production flowrate and is known as water coning (see Figure 7): – As previously described, excessive production leaves a

depleted area around the well; oil from further regions of the reservoir is not able to refill the area in time.

– Water pushes up from the aquifer to refill the depleted area. The result is a:

rapid decrease in oil production rapid increase in water production

Figure 7—Water Coning

Secondary Recovery In a waterflooded reservoir that uses beam pumps, the bottom water layer pushes upwards as oil is pumped from the wells. The water nearing the wells may cause either a gradual or rapid increase in the water produced by the well: a slow increase is the normal sign of an aging well a rapid increase may be water coning (from operating the

beam pump at an excessive production flowrate) Increased water production may also be caused by problems with nearby waterflood injection wells. The injected water may be channeling directly through the reservoir towards the beam pump well.

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Tertiary Recovery Because the interrelation between a tertiary recovery reservoir and its beam pumped wells is complex, well operators should consult company engineers when water production increases from wells in: a reservoir undergoing miscible displacement a thermally flooded reservoir

Production Zone/Downhole Blockages During beam pump operation, the oil flow through the reservoir: erodes the reservoir rock which causes the rock to break into

fine particles (sanding) carries the particles towards the wellbore

As the solids flow towards the wellbore, they can settle and cause production zone/downhole blockages. The blockages are referred to as sanding off and can form: in the reservoir’s porous flow passages to the wellbore at the well’s perforations into the reservoir inside the downhole pump and production tubing

Other materials can accumulate and cause production zone/downhole blockages: heavy hydrocarbons in the oil (such as waxes and

asphaltenes) can solidify in the reservoir and wellbore to block flow (referred to as waxing off)

minerals in the water that is produced along with the oil may settle as scale in the reservoir and wellbore

Specialty chemicals (such as corrosion inhibitors, scale inhibitors and dewaxing chemicals) are sometimes injected into the wellbore. However, if the chemicals are incompatible with the oil or reservoir rock, the chemicals can degrade and form deposits that block flow. Normal production tests and well production readings help the operator identify if blockages are present. Blockages are indicated by a decrease in: well production tubing pressure oil temperature at the wellhead

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Section 3.4 describes a production test to measure the solids content of the oil. Increasing solids content can be an early indicator that sanding off problems may be imminent. When blockage problems are detected, company engineers investigate the cause and determine the solutions to resolve the blockage problem. The solutions may be: one time actions to clear the blockage a program of routine actions to prevent well blockages from

occurring such as: – performing routine preventive downhole flushes – injecting specific chemicals to prevent scale/wax buildup

preventive practices used when making flowrate changes. Incorrect flowrate changes cause flow surges in the reservoir that break a lot of sand from the reservoir rock. To make correct flowrate changes, the flowrate: – must be changed gradually in small steps – must not be increased beyond a preset maximum

If the preventive actions do not have the desired effect, well operators must first consult with company engineers before making changes. Unapproved changes can cause new problems. For example, changing the types of injected chemicals may result in incompatible chemicals degrading and causing well blockages.

3 Analyzing Well Performance For wells equipped with beam pumping systems, operators typically provide engineers with two types of data for assessing well performance: daily monitoring data diagnostic test data (Sometimes, third party contractors

provide this information.)

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Engineers rely on well operators to provide quality (i.e., accurate and reliable) data. With good data, engineers can reliably: identify trends that indicate a problem may be developing in

the reservoir/wellbore recommend steps the operator can take to prevent

irreversible damage to the reservoir/wellbore

When unknowingly provided with bad data, engineers: may not identify actual problems and instead identify

non-existent problems recommend faulty actions that may cause irreversible

damage to the reservoir/wellbore Because well operators are familiar with each well’s normal production parameters, operators are likely to notice abnormal readings or test results: In case of abnormal readings/results, the operator takes

another reading or repeats the diagnostic test. If the abnormal reading/result is confirmed, the operator

checks to ensure the beam pumping system is operating properly. If no beam pump operating problem is identified, the operator promptly notifies company engineers who investigate and recommend corrective actions.

3.1 Well Production Records As described in Module C––Describe and Monitor Beam Pump Operation, company engineers rely on well operators to keep accurate records of each well’s production. Accurate records enable engineers to establish reliable benchmark production data for individual wells and for the entire reservoir. Significant changes (e.g., increasing or decreasing production trends) may indicate problems in the wellbore or reservoir.

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3.2 Diagnostic Tests to Identify Wellbore and/or Reservoir Problems

Reasons for Performing Diagnostic Tests Diagnostic tests of wells are performed for two major reasons: to establish and confirm production benchmarks for the well to identify specific problems in the reservoir and/or wellbore

Diagnostic Tests to Establish and Confirm Benchmarks Diagnostic tests are performed on new beam pump wells to establish production benchmarks (e.g., normal production fluid volumes, normal well fluid composition). The tests are repeated on a scheduled basis; company engineers use the test results: to confirm the well’s benchmarks remain unchanged to identify long term changes in the well

Diagnostic Tests to Identify Reservoir/Wellbore Problems If production trends indicate a potential problem with the wellbore or reservoir, the location and cause of the problem must be identified as soon as possible. Prompt action can prevent damage to the reservoir, wellbore, or beam pumping system. In case of an abnormal trend, engineers request diagnostic tests. Engineers use the diagnostic data from the tests to:

End of Sample A full licensed copy of this kit includes: • Training Module and Self-Check • Knowledge Check and Answer Key • Blank Answer Sheet • Job Aid

Describe and Operate Beam Pump Module D - HDC · 2018. 5. 14. · account downhole pump operation,...

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