Well completion and testing

WELCOME TO THE STUDENTS
7th Semester (Mining)
Bogura Polytechnic Institute, Bogura.
Md. Majedur Rahman
B. Sc (Hon’s), M. Sc in Geology & Mining, RU
Instructor (Tech)
Mining and Mine Survey Technology
Bogura Polytechnic Institute, BOGURA.
Presented By
Prepared by Md. Majedur Rahman, E-mail: majedu1r_ru6871@yahoo.comMay 29, 2020 1

Petroleum Well Design & Completion
Course Code No. 69372
Prepared by Md. Majedur Rahman, E-mail:
majedu1r_ru6871@yahoo.com
May 29, 2020 2

Chapter-10
Understand the well completion and testing
10.1 Describe well completion methods.
10.2 State well head equipment.
10.3 Define well testing.
10.4 Describe Drill Stem Test (DST)
10.5 Describe well testing operations.
10.6 Describe high pressure and high temperature testing.
10.7 Mention benefits and limitations of well stimulation.
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Informal definition:
The high time of the well when engineer and personnel comes to
decide whether to install the production casing in order to initiate the
production at the surface or it should be abandoned .
Technical Definition:
Well completion means to prepare the well for production by installing
the necessary equipments into the well in order to allow the safe and
controlled flow of HCS at the surface.
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10.1 Describe well completion methods.

Well completion is the process of making a well ready for production
(or injection) after drilling operations. This principally involves
preparing the bottom of the hole to the required specifications,
running in the production tubing and its associated down hole tools as
well as perforating and stimulating as required. Sometimes, the process
of running in and cementing the casing is also included. After a well has
been drilled, should the drilling fluids be removed, the well would
eventually close in upon itself. Casing ensures that this will not happen
while also protecting the wellstream from outside incumbents, like
water or sand
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General Procedure
To understand the concept of
well completion the following
equipment's must be studied
clearly:
1. Casing
2. Tubing
3. X-Mass tree
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1. Casing
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2. Tubing
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3. X-Mass tree
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Open hole well completion
In an open hole well completion the
production casing is just set above the
pay zone, while the entire deepen
bottom of pay zone is left uncased.
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Open hole well completion Advantage
• Maximum exposure of pay zone
• Less pressure drawdown during flow
• No formation damage occurs due to cementing and perforation.
• Less formation damage
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Open hole well completion Disadvantage
• Inability to plug off water or gas zones
• Inability to stimulate the separate zones within the productive zones
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Close hole well completion
• For the most common type of well completion today involves the
cased hole completion, in which the production casing and liner
are cemented and perforated subsequently.
• Select the sections of the pay zone we wish to produce
• Stimulate the separate pay zone from the well
• Multiple completion zones
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Liner Completion
• A Liner is installed across the pay
zone
• It can be divided into two: Screen
Liner and perforated liner
Screen Liner :
Casing is set above the producing
zone and
• an uncemented screen and liner
assembly is installed
• across the pay zone
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Perforated Liner Completion
Casing is set above the
producing zone and a liner
assembly is installed across
the pay zone and
cemented in place. The
liner is then perforated
selectively for production.
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Perforated Casing Completion
Production casing is
cemented through the
producing zone and pay
section is selectively
perforated.
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Tubingless or reduced diameter Completion
Production tubing
is perforated and
cemented
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Single tubing completion
• Simplest way of completing the well
• In this method well is completed by
single zone with single tubing
Multilateral completion
• In this multiple branches are drilled
from a single zone
• •It is used to improve productivity
from closely spaced target zones.
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Type of Flow
• Casing flow: large flow rate no tubing is required, used in middle east.
• Tubing and Annulus flow: large flow rate flow segregation.
• Tubing flow: Used widely in Malaysia due to safety, may use one more
tubing strings.
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10.2 State well head equipment.
Wellhead equipment is used to connect the tubing and casing to an oil or gas pipeline. The
casing is a permanently-installed pipe for lining the well hole to provide pressure containment
and prevent collapse. The wellhead is a flanged device that attaches to the casing.
Components of Wellhead Equipment
• Wellhead equipment includes components such as casing heads, casing spools, tubing head
spools, tees, and crosses. The casing head is part of the connection between the casing and
the wellhead itself. Typically, multiple pieces of wellhead equipment are integrated into a
wellhead assembly called a "Christmas tree". This wellhead assembly allows tubes to be
placed into the well while valves and chokes are used to control the flow of oil and/or gas at
the surface.
• Wellheads and wellhead equipment may be located on offshore platforms, in sub-sea
locations, or onshore. Wellheads are cemented in place and, typically, kept in place; however,
with exploration wells, wellhead equipment may be recovered for subsequent re-use.
Wellhead equipment is designed to support the casing and tubing strings, which may also be
suspended from the Christmas tree.
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The primary components of a
wellhead system are:
• casing head
• casing spools
• casing hangers
• choke manifold
• packoffs (isolation) seals
• test plugs
• mudline suspension systems
• tubing heads
• tubing hangers
• tubing head adapter
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Functions of Wellhead
A wellhead serves numerous functions, some of which are:
• Provide a means of casing suspension. (Casing is the permanently installed
pipe used to line the well hole for pressure containment and collapse
prevention during the drilling phase).
• Provides a means of tubing suspension. (Tubing is removable pipe installed
in the well through which well fluids pass).
• Provides a means of pressure sealing and isolation between casing at
surface when many casing strings are used.
• Provides pressure monitoring and pumping access to annuli between the
different casing/tubing strings.
• Provides a means of attaching a blowout preventer during drilling.
• Provides a means of attaching a Christmas tree for production operations.
• Provides a reliable means of well access.
• Provides a means of attaching a well pump,
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10.3 Define well testing.
• In the petroleum industry, a well test is the execution of a set of
planned data acquisition activities. The acquired data is analyzed to
broaden the knowledge and increase the understanding of the
hydrocarbon properties therein and characteristics of the
underground reservoir where the hydrocarbons are trapped.
• A Well test is simply a period of time during which the production of
the well is measured, either at the well head with portable well test
equipment, or in a production facility.
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Overview of Well Test
Most well tests consist of changing the rate, and observing the change in pressure
caused by this change in rate. To perform a well test successfully one must be able
to measure the time, the rate, the pressure, and control the rate. Well tests, if
properly designed, can be used to estimate the following parameters:
• Flow conductance
• Skin factor
• Non-Darcy coefficient (multirate tests)
• Storativity
• Fractured reservoir parameters
• Fractured well parameters
• Drainage area
• Distance to faults
• Drainage shape
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Purpose of Well Testing
Exploration wells
• Fluid sampling (Primary reason)
• Measuring the initial pressure
• Estimating a minimum reservoir volume
• Evaluating the well permeability and skin effect
• Identifying heterogeneities and boundaries.
Producing wells
• Verifying permeability and skin effect
• Identifying fluid behavior
• Estimating the average reservoir pressure
• Confirming heterogeneities and boundaries
• Assessing hydraulic connectivity.
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10.4 Describe Drill Stem Test (DST)
A drill stem test (DST) is a procedure for isolating and testing the pressure,
permeability and productive capacity of a geological formation during the
drilling of a well.
Originally, the objective of a drill stem test was to take a representative fluid
sample which, in the very early days of the oil industry, was obtained by
either bailing or swabbing. Following the introduction of a packer and a
downhole valve, the next step was the possibility of recording accurate
bottomhole reservoir pressures and temperatures. With the development of
downhole tools, which operated on annulus pressure and a downhole shut-
in valve with surface read-out, drill stem testing has become a generally
accepted safe method to meet the original objectives; to obtain a fluid
sample and reservoir data.
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In a drill stem test, information on the following parameters can be
obtained:
• Reservoir fluid type and properties
• Production rates and potential production problems
• Initial reservoir pressure
• Effective permeabilities
• Type of flow system
A drill stem test is the temporary completion of a well to gather
reservoir data. The three fundamental components are a retrievable
mechanically set packer, a downhole valve assembly (DST tools)
and drill pipe/tubing to surface.
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A drill stem test is the temporary
completion of a well to gather
reservoir data. The three
fundamental components are a
retrievable mechanically set
packer, a downhole valve
assembly (DST tools) and drill
pipe/tubing to surface.

10.5 Describe well testing operations.
Well testing procedures are carried out on all newly drilled wells to
determine the characteristics of the well and the formations it passes
through. Most often the main goal of the well tests is to determine the
productivity potential of a new well. Well testing involves an array of
measurements and multiple types of downhole instruments for gathering
information on the well characteristics.
Well tests are conducted to quantify well characteristics, production
potential, and reservoir properties. Well tests are essential for exploration
and production drilling, well maintenance, and geothermal field
management. The tests ultimately help in optimal and sustainable utilization
of the geothermal resource.
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•Borehole Seismic Techniques
•Single-Well And Cross-Well Seismic Imaging
•Vertical Seismic Profiling
•Formation Testing Techniques
•Well Log Techniques
•Acoustic Logs
•Cement Bond Log
•Cross-Dipole Acoustic Log
•Caliper Log
•Chemical Logging
•Density Log
•Gamma Log
•Image Logs
•Mud Logging
•Neutron Log
•Pressure Temperature Log
•Single-Well and Cross-Well Resistivity
•Spontaneous Potential Well Log
•Well Testing Techniques
•Downhole Fluid Sampling
•Earth Tidal Analysis
•Flow Test
•Injectivity Test
•Static Temperature Survey
•Stress Test
•Tracer Testing
•Vertical Flowmeter Test
Well Testing Techniques

10.6 Describe high pressure and high temperature
testing.
High pressure/high temperature (HP/HT) wells are those where the
undisturbed bottom hole temp at prospective reservoir depth or total depth
is greater than 300°F or 150°C, and either the maximum anticipated pore
pressure of any porous formation to be drilled through exceeds a hydrostatic
gradient of 0.8 psi/ft, or a well requiring pressure control equipment with a
rated working pressure in excess of 10000 psi. Drilling wells with these
characteristics pose special challenges.
A test to measure static filtration behavior of water mud or oil mud at
elevated temperature, up to about 380°F [193°C] maximum (450°F [227°C]
maximum if a special cell is used), usually according to the specifications
of API. Although the test can simulate downhole temperature conditions, it
does not simulate downhole pressure. Total pressure in a cell should not
exceed 700 psi [4900 kPa], and the differential pressure across the filter
medium is specified as 500 psi [3500 kPa]. Because these cells are half the
size of the ambient filtration area, HPHT filtrate volumes after 30 minutes are
doubled.
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Drilling fluid considerations
Where possible, high temperature wells are drilled with oil-based fluids
(OBFs) or synthetic-based fluids (SBFs), because of the thermal
limitations of most water-based fluids (WBFs). Such limitations of WBFs
include:
• Temperature-induced gelation
• High risk of CO2 contamination from the formation being drilled
and/or from the degradation of organic mud additives
• Increased solids sensitivity that is related to high temperatures
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HPHT or High Pressure, High Temperature is defined as
those Wells with a bottom hole temperature greater than 150°C
(300°F) and requiring pressure control equipment with a rated
working pressure of above 69 MPa (10,000psi) (S.P.E E&P Glossary,
HPHT, 2013).
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An HP/HT viscometer typically is used to monitor the temperature stability of
the drilling fluid, and to evaluate its rheological properties at up to 500°F and
20,000 psia. This test is especially useful for determining whether high-
temperature flocculation occurs in water-based muds. The test results can be
presented graphically by plotting the change in viscosity with respect to
temperature over the heating and cooling cycle, which establishes a baseline
for recognizing indicators of temperature instability.
There are a number of ways to minimize problems with temperature
gelation, including:
• Eliminating lignite and lignite derivatives from the WBF formulation
• Lowering the bentonite concentration
• Supplementing the high-temperature water-based system with synthetic
polymers and copolymers
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10.7 Mention benefits and limitations of well
stimulation.
Well stimulation is a well intervention performed on an oil or gas
well to increase production by improving the flow
of hydrocarbons from the reservoir into the well bore. It may be done
using a well stimulator structure or using off shore ships / drilling
vessels, also known as "Well stimulation vessels"
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May 29, 2020
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Any Questions
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THANKS TO ALL
May 29, 2020 39

Well completion and testing

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