Basics_of_petroleum_Engineering_for_well.ppt

Petroleum Engineering

1. Advanced Well Testing
Abdesselem BELARIBI

2. Objectives
Thiscourseisdesignedforwelltestingengineersisordertoupgradetheir
knowledgetopreparethemfortheprofessionalpositions.
ThisCouldbeachievedby:
•Linkingthemeasureddatawiththeeffectofitonthecustomerdecisions
•PreparetheEngineersforunderstadingallofwelltestequipments(Guns,
Downholetools,gauges,wellheads,surfacetestingequipments)
•Preparetheengineerforunderstandingthevariouswellsconditionsbefore
testingsame(Naturaloilorgaswells,Pumpingwells(ESP,GasLift,Sucker
Rod,Stimulatedwells
•Makethetestengineerqualifiedenoughtosetinmeetingwithcustomersto
discussthebusinessplans

3. 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

4. Introduction:
The Reservoir:
Asubsurfacegeologicalformation,porousandpermeable,usually
ofsedimentaryoriginthataccumulatesliquidhydrocarbonsor
naturalgas,inanstructureortrapsealedbyimpermeablebarriers.

5. Introduction:
Reservoir Engineering Objectives:
oDeterminationofHydrocarboninplace
oReservesEstimation(recoveryfactor)andproductionprofiles(attachatime
scaletotherecovery)underalternativeexploitationschemes
oEstablishwellpotentialandtheirevolution(wellperformance)
oOptimalfielddevelopmentplaning&execution
oReservoirmanagement(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

6. 2-Reservoir Rock Properties

7. 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

8. b
mab
b
p
V
VV
V
V
Porosity

f Porosity

9. Rock Matrix and Pore Space
Rock matrix Pore space

10. 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

11. Fig 1-
Effect of Grain Size on Permeability

12. Reservoir Rock Properties
2-Permeability:
Thepracticalunitofpermeabilityisthemili–Darcy(md)
Formationpermeabilityvaryfrom0.01mdtoseveraldarcies
Thepermeabilityasdescribedaboveforflowofasinglephase
homogenousfluidistermedabsolutepermeability,k.
Grainsizealonedoesnotaffectporositybutdoesaffect
permeability.Inintergarnularporositytype,thepermeabilityis
governedbytheporethroats.
Thepermeabilityitisgenerallyanisotropicinthatitisadirectional
quantity.
Permeabilityisdependentuponthearrangementofgrainsandthe
typeofcementationprocessthathasoccurred

13. Fluid Saturation
•The saturation of the fluid is the fraction of
the pore volume occupied by that fluidvolumePore
fluidofVolume
S

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

15. Saturation vs Grain Size

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

17. Reservoir Rock Properties
3-Wettability & Capillary Pressure:
Thesimultaneousexistenceoftwoormorefluidsinaporous
medianeedstermslikewettability,capillarypressureandrelative
permeabilitytobedefined.
Initiallyreservoirrockscontainsonlywater(thewettingphase)
Duringmigration,apressuredifferentialisrequiredforthe
Hydrocarbon(non-wettingphase)todisplacewater,equivalentto
aminimumthresholdcapillarypressuredependentonporesize.
Capillarypressuremaybedefinedasthepressuredifferenceacross
acurvedinterfacebetweentwoimmisciblefluids;
Pc= 2 б COS Φ/r
б=theinterfacialtension,Φ=thecontactangle(lessthan90forthe
wettingphaseandr=theradiusoftube.

18. Contact Angle as a Measure of Wetting

19. 3-Wettability & Capillary Pressure:
Oil-Water Contact : Transition Zone

20. 3-PVT & PHASE
BEHAVIOUR OF
PETROLEUM RESERVOIR
FLUIDS

21. PETROLEUM RESERVOIR FLUID COMPOSITION
Reservoir Gassesare 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 Oilsare 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.

22. PETROLEUM RESERVOIR FLUID COMPOSITION
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 : C
nH
2n+2.
Napthenic: cyclic compounds composed of saturated
rings. Basic Formula : C
nH
2n.
Aromatic: unsaturated cyclic compounds.

23. PETROLEUM RESERVOIR FLUID COMPOSITION
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].

24. PETROLEUM RESERVOIR FLUID COMPOSITION
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).

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

26. HYDR. PHASE-BEHAVIOUR-PURE SUBSTANCES
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.

27. HYDR. PHASE-BEHAVIOUR-PURE SUBSTANCES
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.

28. Phase Behaviour of a Single-Component

29. HYDR. PHASE-BEHAVIOUR-PURE SUBSTANCES
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

30. HYDR. PHASE-BEHAVIOUR-PURE SUBSTANCES
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

31. 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 <T
CAB
-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 %

32. 3-D Diagram of Single-Component System

33. Phase Diagram for Two Pure Components

34. HYDR. PHASE-BEHAVIOUR-PURE SUBSTANCES
Phase Diagram For Multi Component Mixture: [P/T Diagram]
TEMPERATURE
PRESSURE
Gas Phase Only
Liquid Phase Only
1oo %
60 %
0 %

35. 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.

36. Fluids and Fluid Types
The Effect of Separator Pressure

37. The Main Five Reservoir Fluids
BlackVolatileRetrogradeWetDry
Oil Oil Gas GasGas

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

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

40. 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
pointPressure
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

41. Field IdentificationBlack
Oil
Volatile
Oil
Retrograde
Gas
Wet
Gas
Dry
Gas
Initial
Producing
Gas/Liquid
Ratio, scf/STB
<17501750 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

42. 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.

43. Fig 1-33
Volumes in Surface vs. Downhole

44. PVT ANALYSIS RELATIONSHIPS
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.

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

46. PVT ANALYSIS RELATIONSHIPS
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.

47. PVT ANALYSIS RELATIONSHIPS
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
+

48. PVT ANALYSIS RELATIONSHIPS
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.

49. PVT ANALYSIS RELATIONSHIPS
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.

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

51. PVT ANALYSIS RELATIONSHIPS
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.

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

53. PVT ANALYSIS RELATIONSHIPS
Viscosity:
PVT PARAMETERS:

54. PVT ANALYSIS RELATIONSHIPS
Viscosity:
PVT PARAMETERS:

55. PVT ANALYSIS RELATIONSHIPS
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.

56. PVT ANALYSIS RELATIONSHIPS
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.

57. Reservoir Drive Mechanisms
and Producing Characteristics

58. 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.

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

60. 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

61. 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

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

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

64. •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.

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

66. Gas-Cap Drive in Oil ReservoirsTypical
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

67. •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.

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

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

70. 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
0Gas/oil ratio, MSCF/STB Water cut, %
Oil production rate,
Pressure, psia
Gas/oil ratio
Reservoir pressure
Oil
Water
MSTB/D

71. •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.
•

72. 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

73. •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.

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

75. Average Recovery Factors
Oil ReservoirsAverage 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

76. •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).

77. •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 circum-stances 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 pro-vide 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

78. •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

79. 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 be-comes 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.

80. WELL TESTS -GENERAL
•INTRODUCTION
Awelltestistakentomeasureoneormoreofawell'sspecificcap-abilities
underafixedsetofconditions.
Theterm"capabilities"relatestothewell'sproductiveability.Inwelltesting,a
distinctionbetweenanoilwellandgaswellisnecessarybecausethemethodof
expressingthewell'scapabilitiesdiffers.Inthecaseofanoilwell,itistheability
ofthewelltoproduceoil,water,andgaswiththeoilvolumebeingthebasic
measurementinbarrelsperdayandthegasvolumeexpressedascubicfeetper
barrelofstocktankoil.Foragaswell,itistheabilityofthewelltoproducegas,
andsometimesaccompanyingfluids,suchascondensateandwater.Inthiscase
thegasvolumeisthebasicmeasurementinmillioncubicfeetperday(MMCFD),
andthecondensatevolumeisexpressedasbarrelspermillioncubicfeet
(BCPMM).
Ineachcasethegas!volumeisbasedonsomeagreedstandardconditionsof
pressureandtemperature(forexample,14.65psiaand60°F).Thischapter
coversthoseIitemscommontobothoilandgas-welltesting.

81. RESPONSIBILITY FOR TEST
•Theresponsibilityformakingtestsisgenerallyassignedinseveralways,
dependinguponthesizeandcomplexityofacompany'soperations.Thetesting
maybedonebytheleaseoperator(or"pumper"asdesignatedbysome
companies),awelltester,oraservicecompanywhich~specializesinwell
testing.
• Theleaseoperatormayutilizethestandardequipmentgenerally,installed
atthebatteryforwelltesting.Thiswouldincludeaseparator,.stocktank,and
insomecasesatreater.Onmanyofthenewleases,multi-phasemetering
separators,andinsomecasesautomaticwelltestingequipment,isinstalledto
maketestingarelativelyeasyoperation.1Toavoidtheexpenseofanumberof
widelyscatteredstationarywelltestinstallations,someoperatorsmightprefer
topurchaseaportablemulti-phasetestunitwhichmaybehookedupata
battery,orwell,thedesiredteststaken,andthenmovedtoanotherlocation.
Theportableitestunitmaybeoperatedbytheleaseoperator,orawelltester.

82. 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.

83. PREPARATION FOR TEST WELL
•Themostefficientuseoftestequipmentismadepossible
throughanorganizedtestprogram.Inthismanner,the
propertypeoftestandthepropertimetotestisscheduled
accordingtolocalconditionsandthecharacterofthewells
involved.Regulatorybodiesmaysetthetimeandtypeof
testforwellsthatoperateunderaprorationschedule.
Regardlessofwhetherawellisproratedornot,reliable
testingrequiresplanning.
•Stabilization
• Preparingoilandgaswellsfortestinvolvesstabilizing
theproductionrateandpressure.Surfaceindicationsofwell
stabilizationare:
•Constantwellheadflowingpressure
•Constantgas-productionrate
•Constantfluid-productionrate

84. •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

85. •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.

86. •Therearemanywaysinwhichunreliabletestsareobtainedbecause
ofminorchangesinoperationduringthestabilizationperiod.
•Themostcommonchangesareadjustmentofchokesizes,short
downtimeorshut-in,modificationofpumpingstrokeorspeed,and
changesinseparatorpressure.Naturally,noneofthesechanges
shouldbemadeduringthetest.Itisnotfeasibletolist,ordiscuss
everyactiontakenwhichmighthaveadverseeffectonatest.These
thingsaretakenintoaccount,ifconsiderationisgiventothe
purposeofthetesttodeterminetheproductivityofawellundera
fixedsetofproducingconditions.Anyactionwhichchangesthese
conditionsdestroysthestabilityandthevalueofthetest.Hence,
theproperstabilizingofawellisimperativeforgoodreliabledata.

87. 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.

88. 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 up-stream, 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.

89. Equipment Check
Problems
• Everytestdoesnotalwaysproceedasplanned.Oftenstabilized
flowisdifficulttoachievebeforetestingbegins,generallyduetothe
natureofflowinthereservoirandwell,oroperationoftheequipment.
Somewellshaveageneraldecreaseinproductionrateandwellhead
pressureforlongperiodsofflow.Insuchcases,stabilizationisnot
practicalsospecialarbitraryrulesmustbesetuptoobtainusable
results.
• Cyclicchangesofproducingrateandwellpressurecanresult
fromliquidaccumulatinginthewellboreandthenunloading.Ahigher
productionratewillusuallyeliminatethisproblem.
• Sometimesalongflowlinewithachokeatthewellheadcauses
fluidsluggingintotheseparationequipmentandcanresultinerratic
productionrates.Itmaybe,necessarytotakethetestatthewellto
eliminatethisproblem.
• Whenawellmustbetestedunderheadingconditions,the
stabilizationandtestperiodsmustallowtimeforseveralcyclic
periods.Thisisnecessarytodeterminethatthewellisstabilizedas
nearaspracticalbeforestartingthetestandtoobtainaverage
wellheadpressureandproducingratevalues.

90. Equipment Check
Problems
•Theformationofhydratescanmakeitdifficulttoobtainareliablewelltest,and
mayrequireequipmentchangestoeliminatethisproblem.Changeswhichmay
bemadeareinstallationofaheaterupstreamofthehighpressureseparator,or
theuseofalowtemperatureseparator.Injectionofalcoholorglycolintothe
flowstream,orinstallationofabottom-holechokeinthewell,mayalsobeused
toeliminatethisproblem.
•SpecialprecautionsarenecessarywhenmeasuringgaswithaPitottube,critical
flowproverororificewelltester.Withthesedevices,thegasisreleasedtothe
atmosphereandthereisapossibilityoffireorsuffocation.Whenoneofthese
devicesisused,itshouldbeonelevatedterrain,whenpossible,anddownwind
atasafedistancefromanyvesselwhichmaypresentafirehazard.
•Extremecautionshouldbeexercisedinhandlinggasesandfluidscontaining
hydrogensulfide(H2S).Thishazardoussubstanceishighlytoxic,andunder
certainconcentration,cancauseillnessordeath.Specialprecautionsshouldbe
takenwhentestingwellswherehydrogensulfideispresenttobeassuredthat
exposurewillnotexceedthesafemaximumallowableconcentrationforthe
workperiodrequired.Selfcontainedbreathingapparatusshouldbewornwhen
hydrogensulfideconcentrationsarepresentthatmightbeinjurioustohealth.