Oil and Gas Artificial Fluid Lifting Techniques

Copyright © 2022 by Khosrow M. Hadipour. 826669

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CONTENTS

Discussion

Chapter IThe Pumping Units And Related Equipment

Chapter IISubsurface Fluid Pumps

Chapter IIIArtificial Fluid Lift Technology Using Gas Lift Equipment

Chapter IVArtificial Lift Technology Using Jet Pump And Hydraulic Pump

Chapter VElectric Submergible/Submersible Pump (Esp)

Chapter VIPrincipal Operation Of Progressing Cavity Pump

Chapter VIIPlunger Lift System

Published by K. M. Hadipour

Professional Petroleum Engineer

Oil and Gas Artificial Fluid-Lifting Techniques

The technical material presented below is based on forty-three years of practical experience in the oil and gas industry working for the Gulf Oil Company, Chevron USA, Pennzoil Companies, Devon Energy, and Americo Energy resources offshore and onshore in Louisiana, Mississippi, Texas, Venezuela, and New Mexico.

The subject material presented below is for information only and is not intended to be a guideline and/or work procedure for anyone to follow. We are not responsible for the information herein (in other words, we are not responsible for your work mistakes).

The presented material is not intended to promote and/or demote any entity or product mentioned in this book. The pictures and comments are based on practical facts only.

DISCUSSION

OIL AND GAS ARTIFICIAL

LIFTING TECHNOLOGY

T he purpose of artificial fluid lift is to create and apply an energy source to lift a static column of wellbore fluid out of a well to maximize and enhance oil and gas production. Hydrocarbon oil, gas, and water are originally trapped in the formation pore space under significant reservoir pressure. Some hydrocarbon oil and gas reservoirs may have high pressure, and some reservoirs may have low pressure.

When a well is perforated for production, oil, gas, salt water,

and solids will be forced out from the reservoir formation into the wellbore immediately and may flow to the surface naturally for some time (it depends upon the reservoir pressure and the fluid characteristics). Most oil-producing reservoirs will have sufficient pressure to flow for a long time. The continuous flow of fluids from the reservoir will cause oil and gas production to decline. As the well produces crude oil, water, gas, and formation solids for a long time, the reservoir pressure and energy are consumed and will no longer be able to bring the fluid to the surface.

The natural flow of oil and gas is the most cost-effective and efficient method of producing hydrocarbon oil and gas out of a well. As long as the formation pressure is greater than the hydrostatic column of fluid in the wellbore, the well may continue to flow naturally. The flow of oil and gas wells is easier to maintain and cheaper to operate. One must keep the flowing rate down to keep water, sand, and solids from entering the wellbore.

Natural well flow is based on the reservoir pore pressure and the completion techniques. Formation pressure is often referred to as pore pressure. All the oil and gas wells will have limited production recovery. The oil, gas, and water percent (%) ratios are subject to change with time.

Oil and gas wells are drilled and completed either vertically, laterally, or horizontally. Horizontal wellbores are subject to high risks and high rewards. Initial oil and gas production in horizontal wellbore drilling appears to be as high as several thousand barrels per day for several months; however, the risk and cost of borehole cleaning, troubleshooting, and artificial lifting will stay high for the remainder of the wellbore’s active life.

The completion and stimulation fracturing of horizontal boreholes may consist of several comingling perforated horizons of oil, water, and gas. The drilling and borehole cleaning of horizontal wells are generally costly and risky. It may be difficult to know which zones make the most water and gas. Remedial workover and artificial fluid lifting in horizontal boreholes are always costly and challenging to face.

Reservoir Fluid Behavior

Understanding reservoir and fluid characteristics can be valuable in artificial lifting decisions.

There are basically three types of reservoirs:

• Water drive reservoir

• Solution gas drive reservoir

• Gas cap expansion drive reservoir

(Misunderstanding the above reservoir characteristics before selecting artificial lifting equipment could cause major cost problems later.)

When the reservoir pressure becomes equal to the hydrostatic column of fluid in the wellbore, the well will stop flowing naturally. The fluid level in the wellbore will stall at or near the surface, with some gas bubbles in the solution. The bubble point is calculated to understand the reservoir characteristics. The bubble point is the function of the reservoir temperature, gas/oil ratio, and oil and gas gravity.

When the reservoir pressure declines below the hydrostatic head of the column of liquid in the wellbore, fluid will stall below the surface inside the casing/tubing string. The rapid decline of reservoir pressure will cause the hydrostatic head to become equal to or greater than the reservoir pressure. The fluid in the wellbore predominantly turns to heavy salt water.

The hydrostatic head is defined as pressure exerted by the column of fluids inside the tubing and/or casing string (the fluid is referred to as oil, water, and gas in the oil field). When a well stops flowing oil and gas, naturally, it will be reported as a dead well.

An artificial lift begins when an oil and gas well ceases to flow naturally because of the depletion of reservoir pressure and natural fluid flow. Stimulating and fracturing the reservoir may extend the natural fluid flow longer. Once an oil or gas well stops flowing fluid, the artificial lift may begin with basic fluid swabbing to prolong the natural flow of the oil or gas well as long as possible while planning and preparing for an appropriate artificial lifting system.

Oil and gas reservoirs contain pressure. Some reservoirs may contain high pressure, and others may have low pressure (depending on the reservoir formation characteristics). Artificial lifting will reduce the hydrostatic head of the column of fluid significantly.

Hydrostatic pressure = 0.05195 × fluid density × fluid height

Hint: One gallon of fresh water is equal to one pound and is equal to 231 cubic inches.

Do You Know What Swabbing Is?

Swabbing is a temporary artificial lifting technique of pulling water, oil, and gas from a well using a swab unit (rig), steel wire rope, and mechanical swabbing tools. Swabbing the liquid out of the tubing string will reduce the hydrostatic head, and it may help the well flow naturally.

Mechanical swab tools and equipment consist of the following:

• Swab unit mast (swab rig)

• Swab lubricator with pressure control pack-off elements

• Swab line (9/16" steel wire rope)

• Rope socket

• Steel swab bar/bars

• Mechanical spank jars

• Swab mandrels

• Rubber and/or steel swab cups

Effective swabbing will begin when the reservoir’s bottom-hole pressure depletes or declines to a level lower than the hydrostatic column of liquid in the tubing and casing, preventing the well from flowing naturally (check the perforations to make sure they are not covered with sand).

The swabbing results may be utilized to determine the total daily fluid entry into a well (reservoir productivity and deliverability). Do not swab the formation sand and solids into the wellbore. An accurate reservoir output will assist you on the artificial lifting design and the selection of appropriate artificial lifting tools and equipment.

An effective swabbing method must be conducted in conjunction with a good-standing mechanical isolation packer and a seating nipple on the tubing string that is set above the perforations. Through the tubing, swabbing must be conducted with an isolation packer on the tubing string (set the packer at one hundred feet above the open perforations to avoid pulling formation sand in the hole).

When the well starts flowing, reduce the back pressure at the production facilities to help the well unload and flow for as long as possible. When swabbing through the production tubing, the tubing string must be in good standing without any hole/holes (never swab a well down to the seating nipple). A standard API seating nipple must be installed above the isolation packer before swabbing (make sure the no-go on the swab mandrel

will not go through the seating nipple).

There are two distinct swabbing methods:

• Through tubing

• Through casing

The daily production rate and the volume of fluid from a reservoir must be known before an artificial lifting design is applied (read The Field of Swabbing by the author of this book). If swabbing a well is no longer effective to keep an oil or gas well flowing naturally, an artificial lifting method may be implemented to change the wellbore fluid from static to kinetic energy lift.

The rapid pressure depletion of a reservoir is due to poor completion techniques and the waste of reservoir gas into the atmosphere (blowing down and flair burning). More than hundreds and thousands of pumping units appear to be on time clocks across oil fields (nearly 85% of oil wells are on time clocks).

Artificial Lift Methods in the Oil and Gas Fields.

Artificial lift is a vast subject to cover or discuss in this book. However, I will discuss the most important and practical parts of all the artificial operating techniques as we go along through this chapter.

• Keeping a well flowing naturally is highly cost effective and easy to operate.

An artificial lifting operation is a costly method, no matter how you may look at it. The choice and selection of an artificial lifting method is at your discretion. Everyone is in a hurry in the oil field to get that barrel of oil and gas out of the hole. I have seen many costly mistakes in drilling and the completion and selection of artificial lifting methods by new engineers and managers in particular.

• Evaluate the artificial types and decide what is good for the well (not what you like).

Evaluate the fluid characteristic subject to artificial lifting. Select the best alternative lifting method that is effective and efficient with a longer lifetime. Consider the effects of the fluid flow from the reservoir into the subsurface equipment. Understand the desirable and undesirable characteristics of the reservoir fluid, such as the following:

• Well depth (open perforated depth)

• Well condition(casing mechanical integrity)

• Volume of fluid per day

• Rate

• Temperature

• Gas pressure

• Gas bubbles

• Gas/oil ratio

• Oil viscosity

• Fluid density

• Mud/sand/sludge

• Corrosion type

• Emulsion

• Turbulence and fluid surge

• Fluid heading (natural or artificial)

Practical Artificial Lifting Methods in the Oil and Gas Fields

There are basically two distinct methods of artificial fluid lift:

A) The mechanical artificial lifting method

B) The artificial gas lifting method

A. The Mechanical Artificial Lifting Method

1. Artificial lift using swabbing tools and equipment (short-term lifting)

2. Artificial lift using sucker rods and a beam pumping unit

(using a pump jack)

3. Artificial lift using hydraulic or jet pumps

4. Artificial lift using electric submergible/submersible pumps

5. Artificial lift using a rotary pump/progressive cavity pump (PCP)

6. Artificial lift using plunger lift tools (utilizing reservoir or compressed gas pressure)

B. ARTIFICIAL GAS LIFTING METHOD

The gas lift method is not mechanical fluid lifting. On the artificial lifting method, a high level of dry natural gas pressure is injected through the casing annulus to lift the wellbore fluid.

The gas lift method is the most effective and efficient method of all artificial lifting technology (it requires sufficient natural gas pressure and gas volume). Forty thousand barrels of fluid per day can be lifted using a gas lift system.

Artificial lifting is costly, and the mistakes of operating artificial lifts are more costly because of the selection of incorrect artificial lifting types, lifting designs, and operating techniques as well as poor wellbore managing.

The choice of method is at your discretion; go for it if you know what you are doing.

I will explain the mechanics on each of the above artificial lifting methods below.

Approximately 90% of oil wells in the United States are on some sort of artificial lifting method. Artificial lifting requires planning, design, knowledge, and practical experience. The components of an artificial lift are similar to the pieces of a puzzle that must be engineered and put together with accurate design and balance from start to finish.

Some of the artificial lifting methods consist of many moving components to operate and may be subject to repeated production equipment failure.

Information for Surface and Subsurface Equipment Designs:

• Reservoir input (fluid drawdown; fluid production per day)

• Accurate calculation and selection of appropriate lifting equipment

• Lifting depth (the subject of an accurate study)

• Selection of subsurface equipment types and sizes

• Casing and tubing mechanical evaluation (tubing, casing, and downhole integrity)

• Wellbore fluid evaluation (the volume of oil, water, and gas subject to lift)

• Selection of subsurface fluid pumping depth (packer and installation depth)

• Selection of tubing size and grades for a specific wellbore depth (H-40, J-55, N80, L80)

• Wellbore temperature, pressure, fluid density, corrosion evaluation, and cleanness of fluid subject to artificial lifting

• Availability of supporting elements/resources and equipment (natural gas and power)

• Selection of surface supporting equipment

• Selection of sucker rod string (one-size rod string vs. multiple tapered rod string)

• Cost and economic impact (production versus payoff)

• Available resources to accurately engineer the artificial lifting

• Bottom hole pressure

• Bottom hole temperature

• Fluid gradient

• Static fluid level

Artificial lift designs are based on the following information:

• Well depth — The plug back total depth (PBTD)

• Perforation depth — The depth of perforated holes in the casing at the zone of interest

• Bottom hole temperature (BHT) — The temperature at the midpoint of open perforations

• Static fluid level — The well fluid level at the static condition

• Static bottom hole pressure — The survey of wellbore pressure at the static condition

• Productivity index (PI) — The ratio of wellbore production to wellbore bottom hole flowing pressure

• Fluid density — The fluid weight (fresh water = 8.33 pounds per gallon vs. salt water = 9.4 pounds per gallon)

• Fluid viscosity

• Tubing size — The outside diameter of the tubing (2, 2 ⅜, 2 ⅞, 3 ½, 4.5")

• Casing size — The outside diameter of the casing (13 ⅜, 9 ⅝, 8 ⅝, 7, 5, 5 ½, 4 ½")

• Anticipated well production (based on the actual daily well test or fluid swab test)

• Anticipated theoretical daily production versus actual daily production (oil, water, and gas)

• Oil/water ratio

• Kickoff pressure/operating pressure

• Available gas lift/gas pressure

• Statues of sand, mud, and solids (how clean the well fluid is going to be)

• Gas/liquid ratio — The ratio of gas divided by total liquid production volume

• H2S/CO2 wellbore environment

• Wellbore mechanical condition — The physical condition of a casing and wellbore

• Other important downhole information (e.g., gravel pack, sand, shale, mud, solids)

Artificial lifting equipment will not operate properly in any oil or gas wells that produce sand and shale. The equipment will be subject to failure or become stuck. Sanded-up ESP equipment may cost you $200/foot to fish and to clean up the wellbore.

Be careful in your artificial lifting designs. Stop changing from one artificial lifting method to another (it will cost you). The cost of changing equipment in any artificial lifting well is high (e.g., changing submergible artificial lifting to gas lifting or beam pumping).

Carefully evaluate your initial lifting design/designs (get a second opinion if needed). Too many mistakes and poor decisions in artificial lifting designs may break down the financial foundation of any small company (e.g., dry drilling, bad completions, and poor lifting designs).

Many tools and equipment lying down in oil fields are going to waste as the result of changing from one piece of artificial lifting equipment to another without any preplanning (you are costing the company and the shareholders a great deal). Risky artificial lifting ideas will make well productivity less attractive.

The Artificial Lift Methods in Oil Fields

The Fundamental Principles of Artificial Lift using Pump Jacks

Nearly 85% of oil wells in the United States are operating on the sucker rod–beam pumping method (sucker rods and pump jacks).

Beam pumping consists of two major parts:

A) The surface equipment (beam pumping unit)

B) The subsurface equipment (subsurface fluid pump and rod string)

The surface pumping unit and its related components consist of the following:

1. The pump jack — The surface beam pumping units appear in different sizes and shapes and may be referred to as pumping units or pump jacks.

2. The prime mover assembly — The prime mover is the main source of energy, which consists of the electric motor and/or the gas-driven engine.

3. The commercial electrical power consumption (electric provider)

Subsurface equipment consists of three distinct major parts:

1. The subsurface tubing string, of various sizes (ranging from 2 ⅜ to 4 ½)

2. The subsurface fluid pumps, of various types and sizes

a) Insert fluid pumps

b) Tubing pumps

3. The subsurface sucker rods of various sizes, types, and grades

a) Steel sucker rods

b) Fiber sucker rods

I

CHAPTER

THE PUMPING UNITS AND

RELATED EQUIPMENT

• The pumping units (pump jacks)

• The prime mover (electric motors or gas engines)

• The electric power source or natural gas-driven engines

A beam pumping unit is basically a large piece of steel equipment that may be called the pumping unit, workhorse, pump jack, or grasshopper unit. The main function of a beam pump is to reciprocate the sucker rods and the subsurface fluid pump by lifting the sucker rods and the production fluid.

The pumping unit (beam pump) is driven by an electric or gas-operated prime mover as the energy-generating source to make the pumping unit to operate (stroke up and down) and reciprocate the sucker rods, and subsurface fluid pump components to displace wellbore fluid to surface)

The prime mover is basically an alternating current (AC) electric motor of various levels of horse power and/or a gas-driven internal combustion (IC) engine (such as natural gas or propane gas). The prime mover is directly linked to the power conversion system.

Do You Know How a Pumping Unit Works?

The pumping unit consists of several moving components. Stay alert and stay safe. Working on pumping units may cause serious bodily injury or death. Most surface pumping units are mechanical operating equipment in oil fields. All the components of a mechanical pumping unit are linked and/or connected together (too many moving components).

The generated power energy from the prime mover transmits force to the pumping unit components above the ground and transfers the energy down to the subsurface sucker rods and the fluid pump down the well. The basic function of a pumping unit is to lift and reciprocate the downhole rods by changing the rotary motion at the motor to kinetic energy. The prime mover and the counterbalance stored energy are the main force in lifting the sucker rods and fluid loads (dynamic load consists of all the subsurface weights)

The Sequence of Motions of Beam Pump Components

• Generated Electric Power (Power Plant)

The electric power transmits energy (electromagnetic) to the prime mover on the pumping unit, making the motor’s shaft rotate at the required horse power (revolution per minute or RPM).

A prime mover can be any generating power source—an electric motor, a steam engine, or an IC gas-operating engine using propane gas or dray natural gas

• Prime Mover (Electric Motor)

The prime mover is directly connected to power conversion. The prime mover delivers the generated power by rotating two pulleys on the tail of the pumping unit (a small sheave at the prime mover and a large sheave or flywheel on the pumping unit’s gear box

or gear reducer).

• The pulleys are linked together with V-shaped rubber belts that extend from the small diameter pulley on the prime mover to the large diameter pulley (flywheel) on the pumping unit’s gear box shaft.

• The power band rubber belt is the main link of energy from the prime mover to the large flywheel pulley attached to the gear box shaft (on the pumping unit).

• Changing the size of the sheave on the prime mover will increase or decrease the speed (RPM) on the pumping unit.

• The shaft on the prime mover operates with a rotary motion.

• Changing the sheave on the prime mover to increase or slow down the RPM is basically cheaper and easier than changing the large flywheel on the gear box.

• When the attached pulleys rotate (rotary motion), the gear box shaft on the pumping unit will turn, and so do any attached components to the gear box (The seesaw action of the pumping unit is based on counterbalance).

• The gear box torque power will force the attached heavy crank arms

to rotate with a good counterbalance effect. Torque is the applied force to rotate the system. The shaft on the prime mover usually operates at high RPM speed but at lower torque.

• The downhole sucker rod’s weight is the major part of counterbalancing the surface beam