Basics_of_petroleum_Engineering_for_well.ppt

Advanced Well Testing
Abdesselem BELARIBI

Objectives
This course is designed for well testing engineers is order to upgrade their
knowledge to prepare them for the professional positions.
This Could be achieved by:
•Linking the measured data with the effect of it on the customer decisions
•Prepare the Engineers for understading all of well test equipments ( Guns ,
Down hole tools , gauges , well heads , surface testing equipments)
•Prepare the engineer for understanding the various wells conditions before
testing same ( Natural oil or gas wells , Pumping wells (ESP , Gas Lift , Sucker
Rod , Stimulated wells
•Make the test engineer qualified enough to set in meeting with customers to
discuss the business plans

Outlines
•Basics of petroleum Engineering for Well test engineers
•Why we test wells?
•What Customer need us to do?
•Purpose of well testing
•Testing Package configuration
•Testing natural flowing wells
•Coiled tubing & N2 units
•Testing dead wells
•Testing pumping wells (ESP , SR , Gas Lift)
•Well Stimulation
•Testing Stimulated Wells
•Customer need for each test
•Equipment Quality Control Administration

Introduction:
The Reservoir:
 A subsurface geological formation,porous and permeable , usually
of sedimentary origin that accumulates liquid hydrocarbons or
natural gas,in an structure or trap sealed by impermeable barriers.

Introduction:
Reservoir Engineering Objectives:
o Determination of Hydrocarbon in place
o Reserves Estimation (recovery factor) and production profiles (attach a time
scale to the recovery) under alternative exploitation schemes
o Establish well potential and their evolution (well performance)
o Optimal field development planing & execution
o Reservoir management (update & optimization)
Basic Area Of Knowledge:
• The properties of petroleum reservoir rocks
• The properties of petroleum reservoir fluids
• The flow of reservoir fluids through reservoir rock
• Petroleumreservoir drive mechanisms

Porosity
Represented by: φ
Range from 5 to 30%
– Primary: formed during deposition
– Secondary: formed after deposition
( Volume of Voids
Total Volume of Rock
) x 100
rombohedrally packed
spheres: f = 26%
grain sorting, silt, clay and
cementation effect porosity

b
ma
b
b
p
V
V
V
V
V
Porosity



f

Porosity

Rock Matrix and Pore Space
Rock matrix Pore space

Permeability
• There must be some continuity between pores to have
permeability.
• Q = A k/ M * dp/ dL
• A= Cross sectional Area
• M= Fluid viscosity
• dP= Differential Pressure
• dL= Length

Fig 1-
Effect of Grain Size on Permeability

Reservoir Rock Properties
2-Permeability:
 The practical unit of permeability is the mili – Darcy (md)
 Formation permeability vary from 0.01 md to several darcies
 The permeability as described above for flow of a single phase
homogenous fluid is termed absolute permeability, k .
 Grain size alone does not affect porosity but does affect
permeability. In intergarnular porosity type , the permeability is
governed by the pore throats.
 The permeability it is generally anisotropic in that it is a directional
quantity.
 Permeability is dependent upon the arrangement of grains and the
type of cementation process that has occurred

Fluid Saturation
• The saturation of the fluid is the fraction of
the pore volume occupied by that fluid
volume
Pore
fluid
of
Volume
S 

Saturation
• Amount of water per unit volume = f Sw
• Amount of hydrocarbon per unit volume = f
(1 - Sw)

In-Situ Saturation
Rock matrix Water Oil and/or gas

Reservoir Rock Properties
3-Wettability & Capillary Pressure:
 The simultaneous existence of two or more fluids in a porous
media needs terms like wettability , capillary pressure and relative
permeability to be defined .
 Initially reservoir rocks contains only water (the wetting phase)
 During migration , a pressure differential is required for the
Hydrocarbon (non-wetting phase) to displace water , equivalent to
a minimum threshold capillary pressure dependent on pore size.
Capillary pressure may be defined as the pressure difference across
a curved interface between two immiscible fluids;
Pc= 2 б COS Φ/r
б= the interfacial tension , Φ=the contact angle (less than 90 for the
wetting phase and r= the radius of tube.

Contact Angle as a Measure of Wetting

3-Wettability & Capillary Pressure:
Oil-Water Contact : Transition Zone

3-PVT & PHASE
BEHAVIOUR OF
PETROLEUM RESERVOIR
FLUIDS

PETROLEUM RESERVOIR FLUID COMPOSITION
Reservoir Gasses are mainly composed of Hydrocarbon molecules
of small & medium sizes and some light non-hydrocarbon
compounds (such as N2 & CO2).
Petroleum reservoir fluids are composed mainly of hydrocarbon
constituents.
Petroleum deposits occurring as a gaseous state are Natural Gas,
and in the liquid state as Petroleum Oil or Crude Oil.
Reservoir Oils are mainly composed of heavier Hydrocarbons.
Crude Oil composition is of major consideration in petroleum
refining to determine the suitable chemicals needed to extract the
products.

Crude Oils can be classified according to the type of hydrocarbons
which make up their composition:
Alkanes or Paraffinic: saturated hydrocarbon straight
chain. Basic Formula : CnH2n+2.
Napthenic: cyclic compounds composed of saturated
rings. Basic Formula : CnH2n.
Aromatic: unsaturated cyclic compounds.

Two models are used to describe the composition for physical
property prediction purposes:
Black Oil Model: is a tow component-description of the
fluid, where the two components are the fluids produced at
surface [stock tank oil & solution gas].
Compositional Model: is a compositional-description
based on the paraffin series.C+ component is a unique for
fluid and characterized by two properties [AMWT & S.Gr].

API classification for the crude oil according to the
following Equ.:
°API = (141.5/SGr) - 131.5
Where,
SGr : is the stock tank oil specific gravity OR relative
density (to water at 60 °F).

HYDR. PHASE-BEHAVIOUR- PURE SUBSTANCES
Phase Diagram For A Pure Substance: [P/T Diagram]
TEMPERATURE
PRESSURE
Gas
SOLID LIQUID
Pc
C
T
Tc

Phase Diagram For A Pure Substance: [P/T Diagram]
Vapor-Pressure Line: it is separate the P-T diagram conditions for
which the substance is a liquid from the conditions for which the
substance is a gas.
Melting Line: it is separate the P-T diagram conditions for
which the substance is a solid from the conditions for which the
substance is a liquid.
Triple Pont (T): Represent the P & T at which the solid, liquid & gas
are coexist under equilibrium conditions.
Critical Point (C)): The upper limit for vapor pressure line.
Tc: Temp. above which the gas can’t be liquified regardless of P.
Pc: Press. Above which liquid & gas can’t coexists.

Phase Diagram For A Pure Substance: [P/V Diagram]
Vaporization Of A Pure Substance At Constant Temperature
Hg
Liquid
TEST CELL
(A). Cell full of liquid===Pressure P1>Pv
(B). Hg removed ===Gas & Liquid Present
Pressure =Pv
(C). Hg removed ===more Gas & less Liquid
Present== Pressure =Pv
(C). Hg removed ===All liquid vaporized-Cell full
of gas== Pressure P2<Pv.

Phase Behaviour of a Single-Component

Phase Diagram For A Pure Substance: [P/V Diagram]
Point (A): Bubble Point.
At which first bubble of
gas liberate due to
pressure reduction.
Point (B): Dew Point.
At which first droplet of
liquid appear due to
pressure increase.
VOLUME
PRESSURE
Vapor
Liquid
L+V
A
B
T = Constant

Phase Diagram For Two Component Mixture: [P/V Diagram]
Liquid/Vapor line
becomes deviated due to
existing of two
components (one lighter
than the other).
Vapor line slope is much
steep than liquid line due
to difference in
compressibilities.
VOLUME
PRESSURE
Vapor
Liquid
L+V
A
B
T= Constant

HYDR. PHASE-BEHAVIOUR -PURE SUBSTANCES
Phase Diagram For Two Component Mixture: [P/T Diagram]
In the figure, system contain
two components
A-Lighter component
B-Heavier component
At Const Temp <TCAB
- At B.P: gas starts to liberate
& rich in comp. A.
- At D.P: last liquid disappear
& rich in comp. B.
TEMPERATURE
PRESSURE
Gas
Liquid
V = Const.
CA: Vapor Pressure Line for Comp. A
CB: Vapor Pressure Line for Comp. B
TcA TcAB TcB
PcA
PAB
PcB 1oo %
0 %

3-D Diagram of Single-Component System

Phase Diagram for Two Pure Components

Phase Diagram For Multi Component Mixture: [P/T Diagram]
TEMPERATURE
PRESSURE
Gas Phase Only
Liquid Phase Only
1oo %
60 %
0 %

CLASSIFICATION OF RESERVOIR FLUIDS
1-Oil Reservoir “Dissolved Gas in Solution” [Tr <Tc]
If the reservoir pressure initially >Saturation Pressure B.P.P
-The reservoir fluid is initially monophasic (undersaturated).
In the event that the reservoir
pressure becomes equal to
Saturation Pressure B.P.P
-Gas Cap could exists.
Note that at separator condition,
higher % of liquid saturation
will recover plus less % of gas.

Fluids and Fluid Types
The Effect of Separator Pressure

The Main Five Reservoir Fluids
Black Volatile Retrograde Wet Dry
Oil Oil Gas Gas Gas

Phase Diagram of a Typical Black Oil
Black Oil
Critical
Point
Pressure,
psia
Separator
Pressure path
in reservoir
Dewpoint line
% Liquid
Temperature, °F

Phase Diagram of Typical Dry Gas
Pressure
Temperature
% Liquid
2
1
Pressure path
in reservoir
Dry gas
Separator

The Five
Reservoir
Fluids
Black Oil
Critical
point
Pressure,
psia
Separator
Pressure path
in reservoir
Dewpoint line
% Liquid
Temperature, °F
Pressure
Temperature
Separator
% Liquid
Volatile oil
Pressure path
in reservoir
3
2
1
3
Critical
point
3
Separator
% Liquid
Pressure path
in reservoir
1
2
Retrograde gas
Critical
point
Pressure
Temperature
Pressure
Temperature
% Liquid
2
1
Pressure path
in reservoir
Wet gas
Critical
point
Separator
Pressure
Temperature
% Liquid
2
1
Pressure path
in reservoir
Dry gas
Separator
Retrograde Gas Wet Gas Dry Gas
Black Oil Volatile Oil

Field Identification
Black
Oil
Volatile
Oil
Retrograde
Gas
Wet
Gas
Dry
Gas
Initial
Producing
Gas/Liquid
Ratio, scf/STB
<1750 1750 to
3200
> 3200 > 15,000* 100,000*
Initial Stock-
Tank Liquid
Gravity, API
< 45 > 40 > 40 Up to 70 No
Liquid
Color of Stock-
Tank Liquid
Dark Colored Lightly
Colored
Water
White
No
Liquid
*For Engineering Purposes

PVT ANALYSIS RELATIONSHIPS
For gas production, we can use the compatibility factor “Z” to
relate the observed volumes of gas producing at the surface to
the corresponding underground withdrawal. [PV = ZnRT].
For oil production, the process will be more complex since both
oil & gas may withdrawal in the reservoir below B.P.P.
So, the basic PVT analysis required to relate the surface
production to underground withdrawal for an oil reservoir.

Fig 1-33
Volumes in Surface vs. Downhole

Solution-Gas Oil Ratio (Gas solubility) (Rs):=====SCF/STB
“ Volume of gas in standard conditions which will dissolve in
one STB of oil, when both are taken down to the reservoir
conditions”.
PVT PARAMETERS:
R = Rsi
When the oil is undersaturated with gas, I.e. it implies that it is
not possible to dissolve more gases into oil.
R > Rsi====and Rs decline
Below the bubble point pressure, gases will liberate and
amount of dissolved gases in one BBL become less.
Increase of “R” related to the higher gas flow velocity
comparing to oil.

Solution-Gas Oil Ratio (Gas solubility) (Rs):=====SCF/STB
PVT PARAMETERS:
Pressure (psi)
Gas
Solubility
SCF/STB
Rsi
Pb Pr
UnderSaturated
Saturated
0

PVT PARAMETERS:
Oil Formation Volume Factor (o) :BBL/STB
“ Volume in barrels occupied in the reservoir, at the prevailing
pressure & temperature, by one stock tank oil plus its
dissolved gas”.
o increases slightly by pressure drop from Pi to Pb.
This is mainly due to liquid expansion & slope of that line is the
liquid compressibility, which increases near to the B.P.
o decreased steadily by pressure drop below Pb.
This is mainly due to liberation of dissolved gasses.

PVT PARAMETERS:
Oil Formation Volume Factor (o) :BBL/STB
Pressure (psi)
Oil
formation
volume
factor
BBL/STB
Pb Pr
UnderSaturated
Saturated
1
1.1
1.2
V1 Barrels
Of oil under
reservoir conditions
V2 barrels
of stock tank oil
V1-V2
Liberated Gas
+

PVT PARAMETERS:
Oil Formation Volume Factor (o)
Above B.P.Pressure: Producing GOR (R) = Rsi
So that by return the STB + Rsi to reservoir they will make I-bbl
of oil
Below B.P.Pressure: Producing GOR = Rs + (R-Rs)
So, that by return the Rs + STB to reservoir they will make 1-bbl
of oil. Also, by return the (R-Rs) back to reservoir it will
produce gas volume in the free gas cap.

Gas Formation Volume Factor (g):=====BBL/SCF
“ Volume in barrels that 1- SCF of gas will occupy as free gas in
the reservoir at the prevailing reservoir conditions”.
PVT PARAMETERS:
It increases as pressure decline sine the volume that 1-SCF of
gas will occupy at high pressure is less than that at low
pressure due to compressibility effect.

Gas Formation Volume Factor (g):=====BBL/SCF
PVT PARAMETERS:

Viscosity:
PVT PARAMETERS:
In general the viscosity is decrease by pressure decrease.
In reservoir fluids:
Above B.P.P: the viscosity decrease by pressure decline due to
gas expansion.
Below B.P.P : the viscosity increase by continual pressure
decrease due gas liberation from liquid.
Note that the oil viscosity ~ 50 times the gas viscosity.

Viscosity:
PVT PARAMETERS:
Pressure (psi)
Oil
Viscosity
cp
Pb Pr
UnderSaturated
Saturated
0

Viscosity:
PVT PARAMETERS:

PVT SAMPLES:
B.H.S is highly recommended in the beginning of reservoir life.
Thus each STB of oil in the sample should be combined with
Rsi SCF of gas.
Sampling an initial saturated reservoir coupe with two cases,
whether the GOR less than the actual (due to pressure <SCg) or
GOR higher than the actual (due to press.< B.P.P and the gas
has higher velocity comparing to oil).
For undersaturated reservoir, sample can be collected under
flowing condition.
For saturated reservoirs, either to bean CK down or to S.I well.

PVT SAMPLES:
Surface sampling: required to flow the well for several hours till
GOR stabilize. Then two recombination samples collected &
combined in lab using same GOR.

Reservoir Drive Mechanisms
and Producing Characteristics

 Drive Mechanism will govern the way of system depletion
process
RESERVOIR DEPLETION CONCEPTS
 Long term production capacity of reservoir will be defined by the
extent and rate of pressure depletion.
Abandonment level or depletion lower limit can be extent by the
injection of fluids into reservoir.
Basically the fluids to be produced as a result of its high pressure.
Then, reservoir system starts to deplete and it must therefore
compensate for loss by one or different sources.

Oil Reservoir Drive
Mechanisms
• Solution-gas drive
• Gas-cap drive
• Water drive
• Combination drive
• Gravity-drainage drive

Reservoir Energy Sources
 Liberation, expansion of solution gas
 Influx of aquifer water
 Expansion of reservoir rock
 Expansion of original reservoir fluids
- Free gas
- Interstitial water
- Oil, if present
• Gravitational forces

Solution-Gas Drive in Oil Reservoirs
Oil
A. Original Conditions
B. 50% Depleted
Oil producing wells
Oil producing wells
Cross Section
Imagine testing
the same well
after 2 years

RESERVOIR
Oil Cum. Prod.
GOR
Reservoir Press
TIME-YEARS
Reservoir Pressure
GOR
Oil Production
1-SOLUTION GAS DRIVE MECHANISM

Solution-Gas Drive in Oil Reservoirs
Formation of a Secondary Gas Cap
Wellbore
Secondary
gas cap

• Example 1 -A Solution-Gas Drive Reservoir
• Well test data indicates that very early in the
producing life of the reservoir gas-oil ratios are
increasing and pressures around the well bores
are decreasing. Early detection of this type of
very inefficient drive can permit the installation
of a pressure maintenance program which may
more than double the recovery from the
reservoir.

Gas-Cap Drive in Oil Reservoirs
Cross Section
Oil producing well
Oil
zone
Oil
zone
Gas cap

Gas-Cap Drive in Oil Reservoirs Typical
Production Characteristics
Production data
1300
1200
1100
900
0
Pressure,
psia
Oil
production
rate,
Time, years
Gas/oil
ratio,
scf/STB
2
1
800
600
400
200
0
Reservoir pressure
Gas/oil ratio
Oil
1000
MSTB/D

• Example 2 -A Gas-Cap Drive Reservoir
• If gas production is not accurately reported,
wells might be drilled into a gas cap
unknowingly. This is an undesirable situation,
because the gas cap ordinarily must be
conserved as long as commercial oil production
is possible. By not producing the gas cap,
energy is conserved, and the recovery of a
greater amount of oil is possible.

Water Drive in Oil Reservoirs
Edgewater Drive
Oil producing well
Water Water
Cross Section
Oil Zone

Water Drive in Oil Reservoirs
Bottomwater Drive
Oil producing well
Cross Section
Oil Zone
Water

Water Drive in Oil Reservoirs Typical
Production Characteristics
Production data
Time, years
2
0
1
0
20
40
60
80
100
1900
2000
2100
2200
2300
40
30
20
10
0
Gas/oil
ratio,
MSCF/STB
Water
cut,
%
Oil
production
rate,
Pressure,
psia
Gas/oil ratio
Reservoir pressure
Oil
Water
MSTB/D

• Example 3 -A Water drive Reservoir .
• Well test data indicates water moving up dip in the
reservoir. With- out sufficient well testing, the water
movement may not be detected and in such
circumstances, a water flood might be commenced with
the 'same disastrous results as in Example 1. If water
production is not reported or sufficiently monitored,
unprofitable wells may be drilled into the watered. out
portion of the reservoir.
•

RESERVOIR DRIVE MEHANISMS
3-WATER DRIVE RESERVOIR
RESERVOIR
4-GRAVITY DRIVE MECHANISM
DEPTH
O.W.C
Present G.O.C
Initial G.O.C
Closed In
Low to moderate activity aquifer
Gravity Drive is typically active during the
final stage of a depletion reservoir

• Example4 -A Gravity Drainage Reservoir
• Well test data indicates that the wells high on the
structure go to gas, and the wells low on the structure
remain low gas-oil ratio producers. The progress of the
down-structure movement of oil can be traced by noting
when wells go to gas. These observations permit a
calculation of recovery efficiency, which in many cases is
so high that it would not pay to water flood. Without
accurate well testing, the change of the gas-oil ratios of
individual wells may not be reliably determined. A wrong
conclusion might be reached which could initiate an
expensive water flood that would not increase oil
recovery.

Combination Drive in Oil Reservoirs
Water
Cross Section
Oil zone
Gas cap

Average Recovery Factors
Oil Reservoirs
Average Oil Recovery
Factors,
% of OOIP
Drive Mechanism
Range Average
Solution-gas drive 5 - 30 15
Gas-cap drive 15 - 50 30
Water drive 30 - 60 40
Gravity-drainage
drive
16 - 85 50

• Example 5 -Gas Reservoirs
• Although in some cases the examples given are applicable to gas
reservoirs, they are primarily for oil reservoirs. There are other economic
reasons for testing gas wells. Under many gas sales contracts the volume
the gas pipeline company will take depends upon the volume a well is able
to produce. This is determined by well tests. In many states the allowable
of a gas well is determined by its performance in a special type of gas-well
test.
• These examples illustrate the reasons why well testing is necessary
and justified from an economic standpoint. How often, then, should a well
be tested?
• Here again, the answer is an economic one. In a new reservoir
where pressures are high, and wide fluctuations can occur, testing
may be on a daily, or weekly basis. Also, in reservoirs with gas
caps or an active water drive, fluid movement can be rapid and
tests should be frequent. When production is settled, varying little
between tests, testing can be less often (i.e. one test per month).

• Example 5 -Gas Reservoirs
•
• The same general statements apply to accuracy of well testing as
were made about frequency of testing. Generally it costs money,
both in equipment and in manpower, to improve accuracy.
However, operating personnel in all instances should obtain as
accurate tests as circumstances permit. In producing large
reservoirs, the installation of improved equipment, and more
extensive testing, will usually result in increased recovery of oil or
gas and much improved economics.
• The injection of fluids into a reservoir is a method for
improving the recovery of oil and gas. Fluid-injection projects,
such as water floods, and gas-injection projects, require close
control to be successful. This control can be achieved only if well
testing is adequate. Well tests provide the best means of
observing the movement of injected fluids and response to
injection.
• The careful measurement of injected fluids is as important as
the measurement of produced fluids. Fluids injected into
reservoirs include water, gas, and liquid hydrocarbons. Accurate
measurements of volume and pressure of injected fluids provide
basic information for reservoir calculations. Injection well volume
and pressure measurements are obtained in much the same
manner

• Secondary recovery Methods & relation
with well testing :
• Structure map for a field with oil & water
and/or gas injection wells.
• The effect of injection is monitored by well
testing.
• Differentiation should be made between
the formation water & the injected water

PREPARATION AND USE OF WELL-
TEST REPORTS
• Well test information flows from the original report of the field
man through numerous individuals, and is the official production
record of the company and the government. The flow chart shown
in Fig. 5 indicates the main steps.
• The well tester generally has a company prepared form for
recording well test data. It is the responsibility of the well tester to
accurately and completely record the test data, and promptly
forward the information. Usually, this form goes to the production
clerk who posts the data on a well record. Then, the well test data
is used to apportion the lease production, taking into account the oil
shipped, and the oil inventory. This data is reported to the
necessary government agencies, and becomes the official
production for the property. The company uses this data to maintain
a production history on each well and reservoir. This information is
shared with other operators so that field wide trends can be studied.
• A good well test program becomes a key source of data used
by company and government personnel to facilitate, improve, and
record the production of oil and gas reserves.

WELL TESTS -GENERAL
• INTRODUCTION
A well test is taken to measure one or more of a well's specific capabilities
under a fixed set of conditions.
The term "capabilities" relates to the well's productive ability. In well testing, a
distinction between an oil well and gas well is necessary because the method of
expressing the well's capabilities differs. In the case of an oil well, it is the ability
of the well to produce oil, water, and gas with the oil volume being the basic
measurement in barrels per day and the gas volume expressed as cubic feet per
barrel of stock tank oil. For a gas well, it is the ability of the well to produce gas,
and sometimes accompanying fluids, such as condensate and water. In this case
the gas volume is the basic measurement in million cubic feet per day (MMCFD),
and the condensate volume is expressed as barrels per million cubic feet
(BCPMM).
In each case the gas ! volume is based on some agreed standard conditions of
pressure and temperature (for example, 14.65psia and 60°F). This chapter
covers those I items common to both oil and gas-well testing.

RESPONSIBILITY FOR TEST
• The responsibility for making tests is generally assigned in several ways,
depending upon the size and complexity of a company's operations. The testing
may be done by the lease operator (or "pumper" as designated by some
companies), a well tester, or a service company which ~ specializes in well
testing.
• The lease operator may utilize the standard equipment generally , installed
at the battery for well testing. This would include a separator, . stock tank, and
in some cases a treater. On many of the new leases, multi-phase metering
separators, and in some cases automatic well testing equipment, is installed to
make testing a relatively easy operation. 1 To avoid the expense of a number of
widely scattered stationary well test installations, some operators might prefer
to purchase a portable multi-phase test unit which may be hooked up at a
battery, or well, the desired tests taken, and then moved to another location.
The portable i test unit may be operated by the lease operator, or a well tester.

RESPONSIBILITY FOR TEST
• A well tester is usually employed by a company
which operates a large number of wells, and the
time required for well testing cannot be handled by
the lease operator. In this type of operation, the
well tester becomes specialized.
• In many areas there are well testing- service
companies which specialize in this field. Many
operators utilize well test service companies to test
new wells where regular test equipment has not
yet been installed. They are sometimes used for
special well tests, and for testing abnormally high
pressure wells where special test equipment is
required.

PREPARATION FOR TEST WELL
• The most efficient use of test equipment is made possible
through an organized test program. In this manner, the
proper type of test and the proper time to test is scheduled
according to local conditions and the character of the wells
involved. Regulatory bodies may set the time and type of
test for wells that operate under a proration schedule.
Regardless of whether a well is prorated or not, reliable
testing requires planning.
• Stabilization
• Preparing oil and gas wells for test involves stabilizing
the production rate and pressure. Surface indications of well
stabilization are:
• Constant wellhead flowing pressure
• Constant gas-production rate
• Constant fluid-production rate

• Stabilization
• Preparing oil and gas wells for test involves stabilizing the
production rate and pressure. Surface indications of well stabilization
are:
• Constant wellhead flowing pressure
• Constant gas-production rate
• Constant fluid-production rate
• The reason for stabilizing flow is to insure that the data obtained are
representative of actual well performance, ie., a retest under the same
conditions will yield the same results. It is equally important in de-
terming a well's actual day to day performance to stabilize the well
under the exact back pressure conditions as it normally produces. This
will afford a more realistic comparison of tests with actual daily battery
production, and wells requiring remedial action can be more accurately
identified. It is common procedure to preflow, or pump, a well for a
specified period of time prior to starting the actual test. The time
interval required may vary from well to well, but a 24-hour period will
.normally be sufficient for oil-well stabilization. Stabilization criteria for
gas wells vary considerably, and are discussed in detail in Chapter 4.
Most state regulations specify a definite stabilization period, and this
requirement must be met

• A well is considered to have "stabilized" or reached stabilized flow
when, for a given choke size or producing rate, the flowing, or
pumping, bottom-hole pressure reaches equilibrium, and remains
constant. This condition is evidenced at the surface by a relatively
constant wellhead pressure in the case of both flowing and pumping
wells. Another indication of well stabilization may be obtained by
observing the gas-meter chart. A chart showing constant static
pressure and symmetrical differential pressure indicates well
stabilization. The test results on a non-stabilized well are not
reproducible, and they will not compare with previous, or future test
data.
• There should not be any change in operation of equipment
after the stabilizing period begins and during a test. Any adjustment
of equipment that causes a change in the pressure upstream of the
choke on a flowing well, or in the casing and wellhead pressure on a
pumping well, can result in erroneous data. Hence, the stabilizing
period should be started over after such a change preparatory to
conducting the test.

• There are many ways in which unreliable tests are obtained because
of minor changes in operation during the stabilization period.
• The most common changes are adjustment of choke sizes, short
downtime or shut-in, modification of pumping stroke or speed, and
changes in separator pressure. Naturally, none of these changes
should be made during the test. It is not feasible to list, or discuss
every action taken which might have adverse effect on a test. These
things are taken into account, if consideration is given to the
purpose of the test to determine the productivity of a well under a
fixed set of producing conditions. Any action which changes these
conditions destroys the stability and the value of the test. Hence,
the proper stabilizing of a well is imperative for good reliable data.

Equipment Check
• A periodic routine check should be made of all well
test equipment to insure that it is in good working order.
Properly maintained equipment will result in accurate
well tests which reflect true productive capacity. The
frequency for checking well test equipment will vary de-
pending on the producing characteristics of the wells and
associated problems. If a well test appears inaccurate, a
check of equipment should be made in order to
determine the problem.

Equipment Check
• The following well test equipment check list is offered as a guide:
• Check for leakage.
• Check operation of control valves, dump valves, and back-pressure valves.
Be sure that moving parts are free and easy to operate.
• Check to be sure the choke is not cut or obstructed, and in the case of an
adjustable choke, be sure it will zero properly.
• Check position of valves to be sure the fluid being measured is properly
isolated, and the proper valves are open, in order to avoid damage to lease
equipment.
• Check for use of applicable tank tables in cases where test tanks are being
used to determine production.
• Check calibration of both liquid and gas meters.
• Check thermometers and pressure gages for proper calibration.
• Check to be sure that the orifice plate is clean, flat, free of nicks, and sharp
enough to peel the flat of the finger nail when scraped lightly against it.
The sharp edge of the plate should face upstream, and the beveled edge
downstream. The plate should be sized so that, with normal gas flow, the
differential pen will read between 30 and 70 percent of the full-scale
reading (i.e., on a 100-in. chart, between 30 and 70 in.) and never below 5
percent of full scale.
• Check for accumulations of paraffin, mud, or sand in meters and test
vessels.

Equipment Check
Problems
• Every test does not always proceed as planned. Often stabilized
flow is difficult to achieve before testing begins, generally due to the
nature of flow in the reservoir and well, or operation of the equipment.
Some wells have a general decrease in production rate and well head
pressure for long periods of flow. In such cases, stabilization is not
practical so special arbitrary rules must be set up to obtain usable
results.
• Cyclic changes of producing rate and well pressure can result
from liquid accumulating in the well bore and then unloading. A higher
production rate will usually eliminate this problem.
• Sometimes a long flow line with a choke at the wellhead causes
fluid slugging into the separation equipment and can result in erratic
production rates. It may be, necessary to take the test at the well to
eliminate this problem.
• When a well must be tested under heading conditions, the
stabilization and test periods must allow time for several cyclic
periods. This is necessary to determine that the well is stabilized as
near as practical before starting the test and to obtain average
wellhead pressure and producing rate values.

Equipment Check
Problems
• The formation of hydrates can make it difficult to obtain a reliable well test, and
may require equipment changes to eliminate this problem. Changes which may
be made are installation of a heater upstream of the high pressure separator, or
the use of a low temperature separator. Injection of alcohol or glycol into the
flow stream, or installation of a bottom-hole choke in the well, may also be used
to eliminate this problem.
• Special precautions are necessary when measuring gas with a Pitot tube, critical
flow prover or orifice well tester. With these devices, the gas is released to the
atmosphere and there is a possibility of fire or suffocation. When one of these
devices is used, it should be on elevated terrain, when possible, and downwind
at a safe distance from any vessel which may present a fire hazard.
• Extreme caution should be exercised in handling gases and fluids containing
hydrogen sulfide (H2S). This hazardous substance is highly toxic, and under
certain concentration, can cause illness or death. Special precautions should be
taken when testing wells where hydrogen sulfide is present to be assured that
exposure will not exceed the safe maximum allowable concentration for the
work period required. Self contained breathing apparatus should be worn when
hydrogen sulfide concentrations are present that might be injurious to health.

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