Well Testing
Overview of the Equipment and Well Test Analysis
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Why Test Wells?
What kind of well do I have?
Is the well productive?
What are the flow characteristics of this well?
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Why Test Wells?
What kind of well do I have?
Is the well productive?
What are the flow characteristics of this well?
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Information from Well Tests
Reservoir information – Extents and structure structure – Permeability and skin
Samples for PVT analysis
Production estimation
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Equipment required for Well Tests
Downhole tools used to isolate and control the reservoir - a temporary completion of the well
Surface equipment designed to control pressure, separate
Gauges and meters used to record pressure, temperature and rates
Efficient disposal of well effluents (10,000 bbls/oil/day burnt equivalent to 67 Megawatt of energy - medium size Nuclear Powerstation) 4
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Well Test Applications Exploration
reservoir size, hydrocarbon volume, hydrocarbon type, productivity – (is this zone economic?, how large is the reservoir?)
Reservoir Development
pressure, permea drive mechanism
y, connec v y, pro uc v y, orma on amage,
– (what is the reservoir pressure?, how can we estimate reserves?, forecast future performance, optimize production)
Reservoir Management
pressure, permeability, drainage, sweep efficiency, formation damage – (is the well damaged?, stimulation treatment efficiency, why is the well not performing as expected?) 5
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Testing and reservoir development
Testing informs the state of the reservoir at the time of the test.
In case of unexpected production, testing helps the , and prodution optimization.
On mature reservoirs, testing information may steer to strategical decisions and the revision of recoverable reserves.
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Types of Well Tests Single-well tests
Drawdown (producing a well at constant rate beginning at time zero and measuring the resulting pressure response)
Buildup (shutting a well that has been
Multi-well tests
Interference tests (producing one well at constant rate beginning at time zero and measuring the resulting pressure rresponse at one or more o se we s
Pulse tests (alternately producing and shutting in (“pulsing”) one well beginning at time zero and measuring the resulting pressure response at one or more offset wells)
pressure response)
Injection (Similar to a drawdown test. Conducted by injecting fluid into a well at constant rate beginning at time zero and measuring the resulting pressure response)
Injection-falloff (Similar to a buildup test. Conducted by shutting in an injection well and measuring the resulting pressure response)
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7
What is a Well Test?
A test conducted by
Changing production rate at a well
Measuring resulting pressure response at the same well or
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S
O
: reservoir fluid withdrawal : well and reservoir systems : change in reservoir pressure
8
Introduction
•Well Testing is a technique that examines a significant portion of the reservoir under d namic conditions to determine its roduction capabilities & reservoir properties.
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Well Test Analysis
Input Information – Production rate (Q) – Well head pressure (Pwh) – Bottom hole pressure (P) – r
– Gauge depth – Datum depth – Formation thickness (h)
Output Information – – – –
Productivity Index (PI) Static gradient of fluid Permeability and skin Drainage radius
– Sample of fluids – Efficient of stimulation – Dual permeability / porosity phenomena
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Testing and reservoir development
Testing informs the state of the reservoir at the time of the test.
In case of unexpected production, testing helps the , and prodution optimization.
On mature reservoirs, testing information may steer to strategical decisions and the revision of recoverable reserves.
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Well Test Methods/Techniques
Surface Well Test (SWT)
Drill Stem Test (DST)
Pressure Survey (P/T – real-time – memory
PLT – real-time – memory
MRCD/CH RFT
Permanent Sensors
Echometer
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Types of Well Tests Single-well tests
Drawdown (producing a well at constant rate beginning at time zero and measuring the resulting pressure response)
Buildup (shutting a well that has been
Multi-well tests
Interference tests (producing one well at constant rate beginning at time zero and measuring the resulting pressure rresponse at one or more o se we s
Pulse tests (alternately producing and shutting in (“pulsing”) one well beginning at time zero and measuring the resulting pressure response at one or more offset wells)
pressure response)
Injection (Similar to a drawdown test. Conducted by injecting fluid into a well at constant rate beginning at time zero and measuring the resulting pressure response)
Injection-falloff (Similar to a buildup test. Conducted by shutting in an injection well and measuring the resulting pressure response)
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13
Reserves Definition
Reserves
Estimated quantity of oil and natural gas related substances anticipated to be recovered from known accumulations, from a given date forward, by known technology under specific reasonable outlook for the future
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Reserves: Definition
Proved Reserves These are the remaining reserves that can be estimated with a high degree of certainty, which for purpose of reserves classification means that there is generally 80% or greater . The reserves may be divided into proved developed and proved undeveloped to identify the status of development
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Proved Reserves The reserves are considered proved based on the following criteria
– Production and formation tests – Well Logs/ Core analysis
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Reserves: Definition
Probable Reserves These are the remaining reserves that are less certain to be recovered than proved reserves, which for purpose of reserves classification means that there is generally 40-80% . Both the estimated quantity and the risk weighted portion reflecting the respective probability should be reported .
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Reserves: Definition
Possible Reserves These are the remaining reserves that are less certain to be recovered than probable reserves, which for purpose of reserves classification means that there is generally 10-40% . Both the estimated quantity and the risk weighted portion reflecting the respective probability should be reported.
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What Is A Well Test?
A tool for reservoir evaluation and characterization – Investigates a much larger volume of the reservoir than cores or logs – Provides estimate of permeability under in-situ conditions – – Provides estimates of distances to boundaries – Provides estimates of well deliverability – Allows capture of sample for PVT analysis
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Well Test Objectives
Exploration – – – –
Estimate Distances to Reservoir Boundaries Estimate Reservoir Pore Volume Estimate Initial Reservoir Pressure Estimate Well Deliverability
Appraisal – – – – – –
Measurements of the oil production rate Estimate Skin Factor Collection of the fluid samples Evaluation of the formation characteristics Influence of boundary conditions Determination of the initial reservoir pressure 20
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Well Test Objectives
Development – Estimate Skin Factor – Measurement of the average reservoir pressure within the drainage area of the well – Estimate the formation properties
Production – – – –
Estimate Skin Factor Diagnose Productivity Problems Estimate Permeability to Aid in Fracture Treatment Design Evaluate Stimulation Treatment Effectiveness
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Types of Well Test
Single well tests
Oil Well Drawdo Drawdown wn testtest- Pro Produc ducee a well at constant rate and measure the pressure response.
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Types of Well Test
Buildu Buildupp test – Shut Shut in a well well that has been producing and measure the pressure response.
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Types of Well Test
Injectio Injectionn test – Inject Inject fluid fluid into a well at constant rate and measure the pressure response.
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Types of Well Test Single well tests
Gas Well Isochronal Test – A series of drawdown and buildup sequences a eren drawdown flow rates, with each drawdown of the same duration and each buildup reaching stabilization at the same pressure as at the start of the test..
pwf1
pwf2 wf3 pwf4
t
t Q1
t Q2
t Q3 Q4
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Types of Well Test
Modified Isochronal Test A series of drawdown and buildup sequences a eren raw own flow rates, with each drawdown and buildup of the same duration.
Pwf Pwf Pwf 1 2 3 Q Q 1 2
Q 3
Pwf Q 4
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Types of Well Test
Flow After Flow test – A series of drawdown , more, followed by a build up.
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Types of Well Test Multi-well tests
Interference test – Produce one well at constant rate and measure the pressure response at one or more offset wells.
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Well and Reservoir Parameters
Near Wellbore Damage Wellbore Storage i s p , e v i t a v i r e d , e g n a h c e r u s s e r P
Early-time region
Permeability
Boundary Type
Middletime region
Late-time region
Elapsed time, hrs 29 Copyright 2007,
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Flow-Regimes and Reservoir Features Near wellbore (early time)
Reservoir behavior (middle time)
Boundaries (late time)
Wellbore storage (PSS)
Homogeneous (rad)
Single fault (hemi-rad)
Double porosity
Leaky fault (2 rad)
Low cond fracture (bi-lin)
Double permeability (2 rad)
Constant pressure
Limited entry (sph)
Composite (2 rad)
Channel (lin)
Horizontal well (sph or lin)
Layered reservoir
Wedge (pseudo-rad)
-conductivity fracture (lin)
∞
Skin
Closed reservoir (PSS)
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Why are Flow-Regimes Useful? Flow regimes, when recognized, can help the interpreter recognize what the reservoir looks like, i.e. what is the model
Depending on their succession and time of occurrence, it is possible to build a reservoir model with 3 distinct components:
– Near-wellbore model – Formation behavior – Boundaries The key: flow-regimes show simple mathematical relationship between pressure and time
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Near Wellbore Damage (Skin) 2000
p < pb
Mud filtrate invasion
i s 1500 p , e r s s e r 1000 P
p > pb
•Skin due to Invasion
•Skin due to Production hp
∆ps h
500 1
10
100
1000
10000
Skin due to Flow Regimefrom center Skin of duewellbore, to Partial Penetration Distance ft Copyright 2007,
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32
Reservoir Parameters
Initial Pressure
1300
1200 i s 1100 p , e r u s 1000 s e r P d 900 e t s u j d A 800
Permeability (from slope)
700
600 10000000
1000000
100000
10000
1000
100
10
1
Adjusted Horner Time Ratio
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Boundaries
Parallel Faults, Channels
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Productivity Oil Inflow Performance Relationship (IPR)
Gas Absolute Open Flow Potential (AOFP)
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Design Philosophy
Test design optimization – Test objectives – Reservoir parameters (basis of design) – es es gn cr er a an limitations – Test sequence and duration (pressure transient simulation)
Productivity analysis – Range of expected rates and drawdown values • PIPESIM* 2007 • •
ECLIPSE* 100 software WELLTEST* 200 software
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Basic Data
Fluid data – Average reservoir pressure – Average reservoir temperature – Bubble point/dew point pressure – Gas composition or specific gravity with co2 and h2s contents – Gas properties –compresibilty,viscosity,formation volume factor and z factor – Water properties –compresibilty,viscosity,formation volume factor and water salinity – Oil properties –compresibilty,viscosity,formation volume factor – CGR,GOR or solution gas liquid ratio – Total compressibility
•
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Testing Hardware
DST – Tools – Gauges – Equipment – Gauges
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DST Equipment
Isolate the target zone.
Perforate.
Control well flow.
Conve fluid to surface.
Acquire downhole data
Spot stimulation fluids
Well kill
Avoid swabbing
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DST packers Isolate the target zone Packers
Production – – – –
Permanent, run separate HPHT Floating seal assy Cost
Test – Retrievable, run on DST string – Set by string manipulation + weight – Needs slip joints for string expansion 41
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Slip-Joint
Allow for string contraction and expansion during testing
Internally balanced
2-4 normally run on a DST
Drill collars run below for adding weight on the Packer
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TCP Guns
Tubing-Conveyed Perforating (TCP) Advantages: – large guns fired underbalanced with well-control equipment in place – – long intervals efficiently perforated – variety of firing systems – ability to drop guns allowing future through tubing operations
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Well Control Flow
Test and Control Valves – Ball Tester valve - multi use – Combined Test and Circulating valves
u ng es er va ve
– Flapper or ball type- One shot
Safety Valves – Flapper or ball type - one shot
Circulating valves – Sliding sleeve – One shot and multi cycle
+ + + -
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Data Capture
Datalatch – Allow real time monitoring – WL running tool inside Tubing
DGA gauge carrier – Memory gagues
LINC – Power latch system
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Bottomhole Sample carrier
Sampling carrier to be run in the DST string
Samplers activated by
Up to 10 samplers in each carrier
PVT samples under reservoir conditions
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Surface Well Test Equipment
Control pressure and flow
Separate the well effluent
Meter and record rates, pressures and temperatures.
Provide sampling ports.
Storage or disposal of well effluents. 47
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Control Pressure and Flow
Flowhead
controls pressure and flow
allows movement of the test string
supports the weight of the test string
allows tools to be introduced into the well
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Control Pressure and Flow
Choke Manifold
contols wellhead pressure
controls flow rate – critical flow – sand and water production
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Control Pressure and Flow, Separator
Steam Exchanger
equipped with choke
raises the temperature of the well effluent
prevents hydrate formation
reduces fluid viscosity
breaks down emulsions before the well effluent enters the separator
requires separate boiler 50
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Test Separator
CAPACITIES AND RETENTION TIME
LEVEL CONTROL
OIL METERING
GAS METERING
SAFETY FEATURE
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Separator features
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Separator Measurements
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VX meter Venturi
Detector
P ∆
T
Composition Meter Flow 54
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Surge tank
Calibration tank
Used to calibrate flow meters in Separator
Allows all gas to be bleed off
Can be used to collect interfaces
Used for low flow rates
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Recorder
Surface Testing Acquisition Network
sensors and meters used to acquire: – pressure – temperature – flowrates • • •
oil water gas
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Disposal
Burners and Booms
efficiently dispose of the oil produced at the surface during an offshore well test
reduces storage and pollution problems
to limit the heat radiation on rigs, the burners are attached to booms to keep them at a safe distance from the rig 57
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SUBSURFACE SAFETY TOOLS Fixed rigs
Floaters rigs
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SAFETY SYSTEMS COMPULSORY ON ALL FLOATERS :
SENTREE
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Subsea BOP stack
Subsea test tree – Safety valve, ball and Flapper – Fail safe closed – – Shear ram can be closed – Retainer valve can be run above to trap string contence
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SenTREE 3 - Basic Tool Features Reduced length and modularity (compared with old generation: EZ-Tree) Can unlatch under full tension Unlatch at an angle up to 6 deg 1.5-in. coil tubing cutting capability Chemical injection point Hydraulically or Mechanically UNLATCH Connections: 3” ID & 5” ACME BOX x BOX Other version: SenTree 7 (ID= 7”) 15 Kpsi WP 61 Copyright 2007,
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