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Transient Testing and Artificial Lift

Nodal Analysis Workshop

Oil zone

Valve closed

Expandable rubber packer

Perforated anchor pipe

DST – Tools Run In

Nodal Analysis Workshop ═══════════════════════════════════════════════════════════════════════════════════

©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

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DST – Open to Flow

Oil zone

Valve open

Packer set

DST Pressure / Time Profile

Sequence of events reflected on pressure-time recording during a drill stem test.



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Hydraulic Diffusivity Equation

2

2

1 p 1 p + = ...........

r 0.0002637 ttcp

r r k

Fig. 5.1 – Idealized rate and pressure history for a pressure buildup test.

Idealized Rate & Pressure

Right before shut in we have a rate and flowing bottom hole pressure



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Horner Plot – Buildup Test Data

Horner Type Plot

2000

2100

2200

2300

2400

2500

2600

2700

2800

2900

1.0 10.0 100.0 1000.0

Horner Pressure Buildup Plot

Pws (psia)

P* = 2820

Pws1 = 2660

Pws2 = 2500

P1hr = 2450

(t + Δt) / Δt

Slope = (2660‐2500)/(1‐2)

m = 160 psi/cycle

m = 160 = 162.6qoμoBo/koh



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Permeability from slope (k in mD):

Skin:

Flow Efficiency:

162.6 o o o

o

q Bm

k h

s 1.151P

1Hr P

wf m

logk

o

oc

tr

w

2

3.23

PSkin

0.87 m s

FlowEfficiency P

r P

wf P

Skin

Pr P

wf

Pskin :

Parameters from Buildup Tests

Radius of Investigation

1

2

948it

ktr

c

2948 ti

ct r

k



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Type Curve Application

Summary

Transient Analysis should provide good values for K and S (assuming the right data for h was used).

This information can go into building a Theoretical Inflow Model.

The flowing bottom hole pressure and the pre-shut in rate (for a buildup) can be used to calibrate the model.



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What is happening when there is no curve intersection of well inflow performance and tubing string performance curve?

Reservoir energy has depleted and proper selection and design of the appropriate artificial lift system is necessary.

Artificial Lift – Defining the Need

Electronic Controller

DriveHead

Low rates Heavy oil

Some sandLow gas

High ratesGas supply

Offshore prod

Gas well Dewatering

Final depletionVery low cost

Heavy oilSome sand

Low gasHigh viscosity

Power fluidTemp testsHigh cost

SelectionGuide

Very high rates No sand, Low gas

Power source

Major Types of Artificial Lift Illustrated



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Surface Performance Analysis

Down Hole Performance Analysis

Rod Pump Well Completion

Rod Pump System Components

Surface equipment

Sucker rods

Downhole pump

Analytical techniques for:• Prime mover system• Rods• Pump at reservoir depth

Reservoir inflow from producing zone

Gas Lift

Continuous gas lift works by injection of high pressure gas into the casing annulus which enters the tubing at the operating valve and reduces the liquid gradient in the tubing, thus creating drawdown.

Pressure

Dep

th

PWF SIBHP

Gas in casing

annulus

Gas lift valves



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Gas lift mandrels with gas lift valves

Gas Lift

Gas lift valves in a tubing string side pocket mandrel provide the mechanical devices required for gas lift. Lift gas enters the tubing through the valves. There may be as many as 5–10 gas lift mandrels and valves in a tubing string.

The gas lift valve sits inside the mandrel pocket

Packing

Latch

Packing

Gas exits through holes in the valve nose

Gas enters through holes in the valve

OperationGas from the casing enters the area between the seals through holes in the mandrel

Mandrel pocket

Casing

G.L.GAS

Gas Lift



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Important Valve Components

Valve bellows grow in length with pressure

Dome area which holds nitrogen pressure charge

Valve seat

Schematic is an injection pressure operated (IPO)

valve (a.k.a. pressure valve)

Valve choke

Check valve retains nitrogen charge

Valve stem with ball tip

Check valve seats when gas lift valve is not pressured

Gas Lift

Gas Lift Design<> Unloading Valveso Operating Valve

<>

<>

<>

<><>o

Pressure (psig)

Tru

e V

ertic

al D

epth

(ft)

Gas Lifted Zone Depth PresPwf

Pftp

GL DesignFlowing Tubing Gradient

Gas Lift Completion Design



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Gas injected into the casing / tubing annulus results in the pressure pushing the fluid through each of the gas lift valves which are wide open.

This is a particularly dangerous time for the valves; if the differential pressure is too high, the liquid velocity can be enough to cut the valve seat; then, the valve will not be able to close and the design won’t work.

Gas Lift

Pressure

Dep

th

SBHP

QGL

Pressure

Dep

th

SBHP

Fluid may leave the top end of the tubing, or be pushed back into the reservoir.

Gas Lift

Operators must allow sufficient time for unloading and apply API RP 11V5 which states: (a) take 10 minutes for each 50 psi increase in casing pressure up to 400 psi, after which, (b) a 100 psi increase every 10 minutes is acceptable until gas injects into the tubing, and (c) to reach 1000 psi should require at least 2 hr, 20 min: a good practice is to assign an operator to the well for the duration of this operation.

QGL



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Gas Lift

Pressure

Dep

th

SBHP

Once the fluid level is below the top valve, gas will enter the tubing and begin lifting the well; if the tubing pressure is less than the SBHP, the reservoir will begin to contribute; first production from the reservoir is normally recovered completion fluid.

QGL

Pressure

Dep

th

SBHP

Gas Lift

When the second valve is uncovered, gas will begin to enter the tubing.

QGL



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gas from casing 500

mcfd

gas tocasing 500

mcfd

gas fromcasing 500

mcfd

+500

-500

With more gas leaving casing than entering, the injection pressure must fall.

-500

Looking at just the top two gas lift valves

Gas Lift

With IPO valves, the injection gas rate into the well at the surface must be regulated to control the gas entry to approximately the design rate of onevalve; when two valves share injection gas, the pressure in the casing annulus will fall.

Pressure

Dep

th

SBHP

Gas Lift

When the casing pressure falls enough, with a good design, the top valve will close, based on valve mechanics.

QGL



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Pressure

Dep

th

SBHP

Gas Lift

Since there is still more casing pressure than tubing pressure at the bottom valve, and, the bottom valve is still open, the injection gas will continue to displace the fluid in the annulus until the third valve is uncovered.

QGL

Pressure

Dep

th

SBHPWhat happens if the third valve injects too much gas?

Gas Lift

Once again, with injection gas leaving the annulus through two valves, the casing pressure will fall until the second valve closes. If there are more valves deeper, the unloading process continues.

QGL



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Pressure

Dep

th

Gas Lift

The gas lift completion has completed the unloading of the completion fluid and is now set up in operating mode. Gas lift technicians now carefully monitor the performance of the completion and make minor adjustments accordingly.

QGL

Pw

f

Rate

A B C

Gas Lift

Observe the effect of injecting different injection rates into the well.

Case “ A” is a small amount of lift gas, case “B” is an increased amount of gas, and case “C” is a further increase in gas rate injected.

These 3 cases would generate three production rates.



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Pro

duct

ion

Rat

e

Gas Injection Rate

A

BC

Gas Lift

A graph of production rate vs the three different gas lift gas injection rates produces the lift gas performance curve.

Pro

duct

ion

Rat

e

Injection Rate

technical optimum

economic optimumoptimum within

constrained group

Gas Lift

In most cases, there is a limited amount of gas available for all the wells.

The optimum rate must be determined within the constraints of the total gas available for a group of wells.



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ESPAn electric submersible

pump consists of downhole equipment

Pump

Intake

Motor

Cable

Equalizer

And...

ESP

Cutaway view of pump diffuser section, gas separator, and cable

Diffuser

ESP



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ESP Principle

Using Bernoulli’s equation* (expressed in “energy per unit mass” in steady state) in presence of a pump.

ρg ∆H + ρ ∆V2/2 + ∆Pp = > constant <

=> ∆Pp = ρ ∆V2/2

Where: g = gravitational acceleration constant, in m/s2

∆H = altitude variation, in m∆Pp = pressure increase provided by the pump, in Pa ρ = density of the fluid, in kg/m3

V = velocity at the impeller outlet, in m/s

Hence: The dynamic head ∆H is independent of the densityThe pump delivery pressure depends on the density of the pumped fluid.

* The increase in the speed of a fluid occurs simultaneously with a decrease in pressure or a decrease in the fluid’s potential energy.

Thus, for a given impeller at a given rotational speed, the more rate, the less head as shown on the plot of the pump curve on the TDH vs. Rate graph below.

The pump curve quantitatively shows the head that the pump can supply at a given rate (and rotational speed).

TD

H

Rate

Pump Curve

ESP



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Vendors show an operating range on their pump curves that do not define the safe range, but a range inside of the highest efficiency.

The relationship of the most efficient range to the danger areas of upthrust and downthrust is not known in most pumps, so the efficiency limits are used instead.

Rate

TD

H

UpthrustDownthrust Efficient

ESP

Total Dynamic Head (Primary Design Requirement)

The TDH required to pump the reservoir inflow capacity refers to the sum of the following:

1. Net well lift component - HL

2. Well tubing friction loss component - HF,

3. Wellhead discharge component - HD

with all expressed in pressure units of head (in feet/meters).

TDH = HL + HF + HD

GAS SEPARATOR

HL

HD

HF

ESP Total Dynamic Head – TDH



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H-27ESP

PumpCurve

ESP PUMP Curve For 5-1/2” Well Casing

BHP

Head Capacity

Pump Efficiency

ESP Manufacturer Pump Curve

Progressing Cavity Pump

Applications:• Heavy oil • Stripper well rates• Varying inflow• High water cut• Gas well dewatering

•



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Plunger Lift Unloads fluids from low

energy wells.

Plunger travels to well bottom and “swabs” fluid to the surface.

Continual removal of wellbore fluids reduces BHP.

System operates on continuous cycle.

Lubricator

Solar Panel

Controller

Motor Valve

Plunger

Plunger Catcher

Gas

Bottom Hole BumperSpring Standing Valve

Well Fluid

Seating Nipple / Tubing Stop

Plunger Lift System Components

Surface



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COPYRIGHTcloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · Operators must allow sufficient time for unloading and apply API RP 11V5 which states: (a) take