Pdb-3043z Production Engineering: Semester 5/3

PDB-3043Z PRODUCTION ENGINEERING Semester 5/3

By : Dinesh Kanesan ([email protected]) Tel No : 05 368 7295 Room No : Block L-1-44

Course Learning Outcomes (CLO) At the end of this course, students should be able to: ❑ CLO-1:

Evaluate well performance concepts

❑ CLO-2:

Design well performance using Nodal analysis concepts

❑ CLO-3:

Propose well stimulation techniques

❑ CLO-4:

Design artificial lift systems

Course Contents ❑ Introduction to Petroleum Production ❑ Reservoir Deliverability

❑ Inflow/ Outflow Performance (IPR/VLP) ❑ NODAL Analysis

❑ Artificial Lift Methods ❑ Matrix Acidising

❑ Hydraulic Fracturing ❑ Sand Control

COURSE PLAN Topic Artificial Lift Methods Matrix Acidising Hydraulic Fracturing Formation Damage & Sand Control Revision + Test 2

Week (s) 7-8 9-10 11 12 13-14

ASSESSMENT PLAN Assessment Quizzes (3) Tutorials (3) Test 2 Total

Score (%) 3 9 13 25

References ❑Main References 1. Economides, M.J.; Hill, A.D.; and Ehlig-Economides, C. (2008): ‘Petroleum Production System’, Prentice-Hall PTR

2. Guo, B.; Lyons, W.C.; and Ghalambor, A. ((2007): ‘Petroleum Production Engineering: A computer Assisted Approach’, Elseviers’ Gulf Professional Publishing, Oxford, U.K

References ❑Secondary References 1. Lake, L.W. (2007): ‘Petroleum Engineering Handbook’, SPE Richardson

2. Gray, F. (1995): Petroleum Production in Non-Technical Language’, Second Edition,Pennwell Corporation 3. Cholet, H. (2000): ‘Well Production Practical Handbook’, Technip 4. Allen, T.O. and Roberts, A.P. (2004): ‘Production Operations 1 and 2’, Fourth Edition,OGCI and PetroSkills Publications. 5. Beggs, H.D. (1991): ‘Production Optimization Using Nodal Analysis’. OGCI Publication.

CLASS POLICY ❑Attendance/Punctuality ❑Plagiarism

❑Honesty & Commitment ❑Adherence to Datelines (Online Quizzes)

❑Tutorials/Examples/Extra Help (Team spirit) ❑Check updates on U-Learn

LECTURE TIMES

Production Engineering 1 Artificial Lift (Part 1)

Learning Outcomes Towards the end of lecture, you should be able to: 1. Explain the production.

importance

of

artificial

lift

for

hydrocarbon

2. Describe different types of artificial lift technique. 3. Describe the selection criteria of artificial lift. 4. Describe the concept and methods.

components of different artificial

5. Perform basic pump design and simplified ESP design.

Introduction ❑ Hydrocarbons will normally flow to the surface under natural flow when the discovery well is newly completed. ❑ The fluid production will normally lead to: ✓ A reduction in the reservoir pressure ✓ An increase in the fraction of water being produced ❑ All these factors reduce or may even stop the flow of fluids from the well. ❑ The remedy is to include within the well completion some form of artificial lift. ❑ Artificial lift adds energy to the well fluid which allows the well to flow at an economic production rate. ❑ Artificial lift is required when a well is no longer flowing or when the production rate is too low to be economic.

Introduction ❑ Is it possible for this well to flow naturally under any conditions?

Figure 1. Artificial lift fundamentals

Introduction ❑ Is it possible for this well to flow naturally under any conditions? ✓ Yes. ✓ If the well productivity Index is sufficiently high and the produced fluid contains enough gas that the flowing fluid pressure gradient gives a positive wellhead pressure. ✓ But, the well has to be "kicked off" (started flowing) by swabbing or other techniques.

What is Swabbing?

Introduction ❑ Figure 2 shows how installation of a pump a small distance below the static fluid level allows a limited drawdown (Δp1) to be created. ❑ The well now starts to flow at rate q1.

❑ Higher production rate will occur when the pump is relocated to the bottom of the tubing, provided the pressure drop across the pump remains the same. ❑ The advantage of placing the pump near the perforations is that the maximum potential production can now be achieved. (Figure 3)

❑ Artificial lift design requires that the pump to be installed is matched to the well inflow and outflow performance.

Introduction

Figure 2. Pump creates a small drawdown and flowrate

Introduction

Figure 3. Installation of a pump below the perforation interval.

Overview of Artificial Lift Techniques

Figure 4. The common types of artificial lift

Overview of Artificial Lift Techniques ❑ Rod Pump A downhole plunger is moved up and down by a rod connected to an engine at the surface. The plunger movement displaces produced fluid into the tubing via a pump consisting of suitably arranged traveling and standing valves mounted within a pump barrel. ❑ Hydraulic Pump Uses a high pressure power fluid to drive a down-hole turbine or positive displacement pump Or Uses a high pressure power fluid to flow through a venturi or jet, creating a low pressure area which produces an increased drawdown and inflow from the reservoir.

Overview of Artificial Lift Techniques ❑ Electric Submersible Pump (ESP) Employs a downhole centrifugal pump driven by an electric motor supplied with electric power via a cable run from the surface penetrates the wellhead and is strapped to the outside of the tubing. ❑ Gas Lift Involves the supply of high pressure gas to the casing/tubing annulus and its injection into the tubing via the Gas Lift Operating Valve. The increased gas content of the produced fluid reduces the average flowing density of the fluids in the tubing, hence increasing the formation drawdown and the well inflow rate.

Overview of Artificial Lift Techniques ❑ Progressing Cavity Pump Employs a helical, metal rotor rotating inside an elastomeric, double helical stator. The rotating action is supplied by down-hole electric motor or by rotating rods.

Rod Pumps - Introduction ❑ Rod or beam pump was the first type of artificial lift to be introduced to the oil field. ❑ The most widely used in terms of the number of installations world wide. ❑ Suitable for low volume operations due to ✓ Low cost ✓ Mechanical simplicity ✓ Easy installation and operation ❑ Rod pumps can lift ✓ moderate volumes (1000 bfpd) from shallow depths (7,000 ft) ✓ small volumes (200 bfpd) from greater depths (14,000 ft)

Rod Pumps – Video 1

Rod Pumps – Video 2

Rod Pumps - Pumping Unit

Figure 5. Surface equipment for a rod pump

Rod Pumps - Pumping Unit ❑ The prime mover, normally an electric motor or gas engine drives a set of speed reducing gears. ❑ The connection between the surface pumping unit and the downhole pump are the polished rod and the sucker rods. ❑ The polished rod moves up and down through a stuffing box mounted on top of the wellhead. ❑ This stuffing box seals against the polished rod and prevents surface leaks of the liquid and gas being produced by the well.

Rod Pumps - Pump ❑ The pump is located near the perforations at the bottom of the string of sucker rods. ❑ It consists of a hollow plunger with circular sealing rings mounted on the outside circumference moving inside a pump barrel which is inserted into the tubing itself. ❑ The Standing valve is mounted at the bottom of the pump barrel while the Travelling valve is installed at the top of the plunger. ❑ The Standing and Travelling valves contain of a ball which closes the passage in the plunger and the pump inlet when the ball is seated. (as one-way or non-return valves)

Rod Pumps - Pump Operation ❑ The “UP” and “DOWN” movement of the pump barrel allows the fluid pressure in the pump barrel to open and shut the Travelling and Standing valves. ❑ The "Upward“ rod movement reduces the pressure within the pump barrel and the upward flow of fluid from the perforations below the pump lifts the Standing valve’s ball off its seat. ❑ The pressure due to the fluid column above the plunger keeps the Travelling valve ball on its seat. ❑ The situation is reversed during the “DOWN” stroke - compression of fluid within the pump barrel forces it to flow through the hollow plunger and to lift the Travelling valve off its seat; while ensuring that the Standing valve remains closed.

Rod Pumps - Pump Operation

Figure 6. Rod pump operation

Pump Design ❑ Positive displacement pump performance is evaluated based on the volume of fluid displaced. ❑ The volumetric flowrate displaced by a rod pump is:

where q : Downhole volumetric flow rate (bbl/d) N : Pump speed (spm) Ev: Volumetric efficiency Ap: Plunger cross sectional area (in.2) Sp: Effective plunger stroke length (in.)

Example 1 Determine the pump rate needed to produce 250 stb/d at surface with a rod pump having 2-in. diameter plunger, a 50-in. effective plunger stroke length and a volumetric efficiency of 0.8. The oil formation volume factor is 1.2.

Example 1 - Solution The downhole volumetric flowrate is calculated by multiplying the surface rate by the formation volume factor. Pump rate needed :

Electrical Submersible Pumps ❑ Electric Submersible Pumps (ESP’s) are a versatile form of artificial lift with pumps ranging from 150 to 60,000 bfpd in operation. ❑ The major components are: ❖A high voltage three phase electricity supply ❖The vent box ❖The downhole cable ❖The pump unit ❖Standard pump impellers ❖A rotary gas separator ❖The protector / seal ❖The electric motor ❖Downhole sensor package

Electrical Submersible Pumps

Figure 7. A well completed with an ESP

Electrical Submersible Pump – Video 1

Electrical Submersible Pump – Video 2

Basic Pump Selection ❑ The pressure increase that the pump is required to deliver (Total Dynamic Head)” or (pump discharge - suction pressure) is the sum of three components. ❖The hydrostatic head ❖The friction pressure loss ❖The surface pressure ❑ Thus, Total Dynamic Head, TDH:

Basic Pump Selection ❑ The hydrostatic head from the ESP to the surface is the density of the produced fluid in the tubing (ρfluid) multiplied by the TVD the ESP is installed (h) and the acceleration due to gravity (g). It is normally expressed in terms of the pressure generated by an equivalent column of water (Hwater).

❑ The Friction pressure loss in the tubing (ΔPfric) ❑ The surface pressure (Psurf) required to overcome flowline back pressure and flow the produced fluid to the separator at the required production rate.

ESP Performance ❑ The centrifugal pump unit employed in ESP’s is a dynamicdisplacement pump in which the pump rate depends in the pressure head generated. ❑ The relationship between pump rate and pressure generated for dynamic displacement pumps is called the pump characteristic (Figure 8). ❑ It is measured by the pump manufacturer in laboratory tests.

Electrical Submersible Pumps

Figure 8. A well completed with an ESP

Simplified ESP Design ❑ The simplified, manual procedure outlined below is to evaluate the installation of an ESP into a vertical well. Depth (h)

7,000 ft

Reservoir Pressure (Pr)

1,700 psi

Well Productivity Index (PI)

2 stb/d/psi

Tubing Internal Diameter (d)

2.26 in. / 0.188 ft

Surface Manifold Pressure (Ps) 50 psi Design Well Production (Q)

1400 stb/d

Produced Fluid Properties

Water

Fluid Density (ρf)

0.433 psi/ft

Viscosity (µ)

1 cp

Pump Setting

Opposite Perforations

Moody Friction Factor, (fm)

0.03

Fluid Specific Gravity (γ)

1

Simplified ESP Design ❑ The pipe friction loss (ΔPf) at the desired well production :

where fm is the moody friction factor, v is the fluid velocity and g the acceleration due to gravity {32.173 (ft/s2)}. The fluid velocity, v :

Simplified ESP Design ❑ The value of fm, is a function of the Reynolds Number, the pipe roughness and the fluid properties. The value of fm, is found from the Moody Diagram. (0.03 for this example)

❑ Next the required pump discharge pressure is calculated:

where Pd is the required pump discharge pressure PHH is the hydrostatic head due to the 7000 ft column of fluid Ps is the wellhead pressure required to transfer the fluid to the surface facilities (50 psi).

Moody Diagram

Simplified ESP Design ❑ The Flowing Bottom Hole Pressure and the pump intake pressure (PIn) are the same and can be calculated from:

❑ Using the pump performance chart (Figure 8), the head per stage (H) at 1,400 b/d is 58 ft and the hydraulic horsepower per stage (HHP) is 0.52 BHP.

❑ The number of pump stages (N) and the minimum electric motor power (HHP) required can now be calculated for a pump running at 2,915 rpm.

Simplified ESP Design

Simplified ESP Design

Simplified ESP Design ❑ Number of pump stages:

❑ Minimum electric motor power (HHP)

Electrical Submersible Pumps - Advantages High production rates Suitable for high water cut wells Controllable production rate Efficient Energy usage (>50% possible) Access below ESP via "Y" tool

Comprehensive downhole measurements available Can pump against high Flowing-Tubing Head Pressure Low surface profile for Urban and offshore environments Minimum surface footprint - 6ft well spacing Quick restart after shut down Long run pump life possible

Electrical Submersible Pumps - Advantages

❖ Well stimulation ❖ Perforating ❖ Installation and recovery of pressure memory gauges ❖ Running and retrieval of plugs ❖ Downhole sampling

Figure 9. The "Y"tool

Electrical Submersible Pumps - Disadvantages Susceptible to damage during completion installation

Tubing has to be pulled to replace pump Not suitable for low volume wells (<150bpd) Pump susceptible to damage by produced solids (sand / scale / asphaltene) High GOR’s presents gas handling problems

Power cable requires penetration of well head and packer integrity Viscous crude reduces pump efficiency (Viscous) emulsions may form over a range of water / oil ratios High temperatures can degrade the electrical motors

Question and Answers Pair ❑ Come up with one question on today’s topic / concept / formula / diagram. ❑ Work in pairs; Student 1 asks a prepared question and Student 2 responds; then Student 2 asks a prepared question and Student 1 responds. ❑ Discuss the questions that has unsatisfactory or uncertain answers with the whole class.

Hydraulic Pumps – Video 1

Hydraulic Pumps – Video 2

Hydraulic Pumps ❑ Hydraulic pumps use a high pressure power fluid pumped from the surface as the source of energy. ❑ This power fluid can drive a downhole turbine/positive displacement pump or flow through a venture/jet to create a low pressure area. ❑ Figure 9 shows how the flow of power fluid through the upper engine unit is translated into a flow of high pressure produced fluid during both the “UP” and “DOWN” strokes.

Hydraulic Pumps

Figure 8. A hydraulic pump

Hydraulic Pumps

Figure 9. Operation of a positive displacement hydraulic pump

Hydraulic Pumps ❑ Figure 10 shows the flow of power fluid through a venturi which creates a reduced pressure area where pressure energy is converted into velocity. ❑ This high velocity low pressure flow of the power fluid commingles with the production flow in the throat of the pump. ❑ A diffuser then reduces the velocity, increasing the fluid pressure and allowing the combined fluids to flow to surface. ❑ The power fluid consists of oil or production water.

❑ The power fluid is supplied to the downhole equipment via a separate injection tubing.

Hydraulic Pumps

Figure 10. Operation of jet / venturi pump

Hydraulic Pumps ❑ The exhaust fluid would commingle with the production fluid. ❑ A typical power fluid supply pressure of between 1,500 and 4,000 psi. is provided by a pressurizing pump.

❑ This pressure determines the pressure increase achievable by the downhole pump unit. ❑ “Clean” power fluid is required to avoid erosion of the downhole pump components. ❑ The power fluid from the pressurizing pump may supply one or more wells.

Hydraulic Pumps - Advantages Suitable for crooked and deviated wells. Reciprocating and turbine pumps can work at great depths (up to 17,000 ft). Very flexible speed control by the (surface) supply of power fluid Jet pumps have no moving parts and can handle solids

The power source is remote from the wellhead giving a low wellhead profile, attractive for offshore and urban locations. The power fluid can carry corrosion or other inhibitors downhole

The pump unit can be designed as a “free” pump

Hydraulic Pumps - Disadvantages Pumps with moving parts have a short run life when supplied with poor quality (solids containing) power fluid. A similar volume of power fluid and produced fluid is required, increasing the size of the production separators

Progressing Cavity Pumps - Video

Progressing Cavity Pumps ❑ Progressing Cavity Pumps are becoming increasingly popular for the production of viscous crude oils. ❑ A typical completion is illustrated in Figure 11 where a prime mover is shown rotating a sucker rod string and driving the PCP. ❑ Figure 12 illustrates the main components of a PCP. ❑ A steel shaft rotor of diameter d has been formed into a helix. ❑ The rotor is rotated inside an elastomeric pump body or stator.

❑ The rotor has been molded in the form of a double helix with a pitch of the same diameter and exactly twice the length of the pitch given to the rotor.

Progressing Cavity Pumps ❑ The rotor within the stator operates as a pump. ❑ The fluid trapped in the sealed cavities progresses along the length of the pump from the suction to the pump discharge.

❑ These cavities change neither size nor shape during this progression. ❑ As one cavity diminishes, the next one increases at exactly the same rate; giving a constant, non-pulsating flow. ❑ The flow rate achieved by a liquid filled PCP pump is directly proportional to the speed of rotation of the rotor.

Progressing Cavity Pumps

Figure 11. A well completed with progressing cavity pump.

Progressing Cavity Pumps

Figure 12.The cross section of a progressing cavity pump.

Progressing Cavity Pumps - Advantages Simple design High volumetric efficiency Tolerant of produced solids High energy efficiency

Emulsions not formed due to low shear pumping action Capable of pumping viscous crude oil

Progressing Cavity Pumps - Disadvantages High Starting Torque

Fluid compatibility problems with elastomers in direct contact with aromatic crude oils Gas dissolves in the elastomers at high bottom hole pressure

ARTIFICIAL LIFT SELECTION CRITERIA ❑Well and Reservoir Characteristics ❑Field Location

❑Operational Problems ❑Economics

Advantages of artificial lift methods compared

Disadvantages of artificial lift methods compared

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Q&A Session