Pnaaw239 PDF
Pnaaw239 PDF
Pnaaw239 PDF
A
Special Presentstion
Canduciad by IPCS
for
Presented
by
IPCS
Intermutional Petroleum '.onsulting Services
1200 New Hampshire Avenue, N.W.
Suite 320
Washington, D.C. 20036 U.S.A.
Telephone Numbers. (202) 331-8214
(202)331-8215
Telex Number 248826 WOS
CONTENTS
WELL PERFORMANCE
GAS LIFT
Torque Calculation......................................... 37
Counterbalance ............................................. 37
Power Requirements......................................... 42
SUBMERSIBLE PUMPS
Introduction ................................................. I
Example Problem............................................ 8
Failure Analysis........................................... 17
PROBLEMS
SOLUTIONS
Well Performance
The basic elements determining well productivity, that is flow rate, can
P "ran k" PG
Pt Psep. Gas
0
PC
Oil water
I /
Domog" and Pw
non-radial flow region
The driving "force", or energy for flow is pressure and this is dissipated in two
ways, one is work against gravity and the other is work against viscous drag, or
"friction". The total drop in pressure from the reservoir, at the "drainage
radius" of the well, to the storage tank can be separated into parts thus:
2
Number Domain P
Drainage Radius Pr - Ps
to "skin" of Well
II "Skin" of Well to P5 - P
Bottom Hole
V Separator PSep - Po
to Tank or
PSep - G
These are described as follows:
P - P is determined by reservoir properties and drive mechanisms:
r s
permeability, porosity, thickness, relative permeabilities, capillary
fluid viscosities, and densities; solution gas, fluid expansion, gas cap, or
water drive and flow rate.
level and temperature, pipe and choke size, and pipe line length.
pressure level and temperature, flow rate, pipe diameter, roughness and
Icngth.
Well Production Testing
This consists of simply measuring the amount and type of fluids produced
and is routinely carried out using a gas-oil separator and a stock tank, with a
device such as an orifice meter to measure gas flow rate and a hand tape to
measure amounts of oil and water ir. the stock tank. Modern techniques use
PI = J q
P-P
r w
where conventionally
Here for q = qo, oil Pi is defined and for q=qo+qw , total P I is defined.
while flowing and when shut-in. The long-term shut-in bottom-hole pressure is
a measure of Pr*r
Productivity Index
J = PI= P q-P
r w
gives
q -2 -rr kh =_ constant
3~r
This can be used for the domain rw to re, the drainage radius with P =Pr
at re to show that
- 0.0070kh I
Pr Pw
Bl1, kn -re
w
fluid viscosity and B the fluid formation volume factor. The term SD isa
flow near the well-bore and/or damaged or improved permeability near the
r
SD = (, -- s ) n rre
r
w
This quantity is positive SD > 0 for ks < k and negative for ks > k.
SD > 0 could result from fresh water filtrate from drilling mud entering the
STB!DIf t./Psi.
being non-constant, that is, the PI measured at one drawdown, P "rPw' will
not have the same value as one measured at another drawdown, even at the
It is obvious that the productivity index in a real well will not be a simple
empirical method to account for these effects by solving the material balance
equations for radial flow based upon Darcy's law, with some approximations,
for "gas" and "oil" flow with gas coming out of solution in the oil. Flow is
From many runs of the numerical integration he showed that to a very good
approximation the graph of stabilized oil flow rate at the well, versus flowing
relationship
P P
-- q - 0.20 Ly -.
0800(
( w )
)2
qmax r r
Where qMax is the maximum flow rate into the well resulting when bottom
7
Performance -Relationship.
MIDVO 10
ORIONWA, -. . [ * 21S0 plot
BL)8LE PO4NT - Z130 psi
2400 CRi.0C OL PVT CHAATCI TICS 1 8 - NP/N . % 4%
AhO RE..ATIV. P'-"EA(BILITY itv
.
CHARAC"ERISTICS FROM RE 7 aI
WELL SPACING * ZO ACRES
" 00 02 04 06 08 i
o 0
i.
00
aJ400
PRODUCING RATE R./fZl.)-ax)
FRACTIONI OF MKAXPIUM
As given above this relationship does not include well damage, or "skin",
effects. The effect of a "skin" of higher flow resistance near the well is to
given flow rate. Thus the P in the above equation is the undamaged Pw and
the actual Pw' say Pw' is less by Ps, the pressure drop across the "skin".
The usefulness of the IPR lies in the fact that a measurement of Pr and
the flow rate q at one bottom-hole pressure determines the entire curve:
9
above and solve for qMax; then all coefficients are determined.
flow capability of a well at some bottnm hole pressure other than that used to
determine J is shown in the .i 7'- b.O, The dotted straight line below is
represented by
P = p
w r jq
and clearly this predicts a Pw nO on the Vogel curve except at one point, the
point used to determine 3. i.e., the intersection with the Vogel curve.
op-_p (+.8 )
r w r r
and the6 one can define
* qm
30 lir
PAl--pr 10 = . 7r
w, r r
Slope =
- Slope=
_ _ __ _ _
___ __ ____ _ __ 0
0
10
2Trrh K 0 P
B I0 dr
0 0
sre K0
sq or = 2Trh J dP
r Pw
w
Now as P IV Pr all
-
pressures will approach P r and saturation distribution
const.; obtain:
K
J Iim5 2nh 0
o P P re IP B
r w Ln
r
w
V' qm'
1o0 Ko qm
0j 0 m
*Thus if from well test data, Pr' q' Pw a q is computed from Vogel Equation
and also K 0' 0' B are determined, one can forecast the new value of qm i
P P 2
IF qo = qm' ( I - .2 ( ) .8 ( w--7
r
Pr
When a shut-in well, either gas or oil, is opened to flow the bottom--hole
time. With the flow rate restricted through an orifice choke, or partially open
valve, the flow rate and bottom-hole pressure will stabilize to essentially
constant values. The valve may then be opened further resulting in another
transient period until a new q and P are established. Typical data for
- I
C1"
SI
Time. . hours
l ii
12
values Pw qI ; ,q2 ; etc. it can be shown from Darcy's law that one
p2 _p 2
r W1
wi constant
and the value of this constant characterizes the well production capability. In
fact
J1 2qiPr qi Pr
P-_p2.
2_ 2 Pr -P.
P-wi P.
r w1i
The difficulty with the flow-after-flow test is the long times required to
reach stabilized flow conditions. A modified procedure, also used in oil wells,
test. The 'ell is shut-in then opened to flow at a fixed rate for a period of
time At, with P read at times At,, At 2 , A t 3 , etc. The well is shut in
again !or a time equal to the total flow time. The process is repeated for a
higher rate, then for another, etc. Finally at the last rate the well is allowed
to flow until a stabilized Pw is reached. From these data on the gas well
? 2
one can plot P - Pw2 /s q for equal times of flow. i.e., using the P
r
say at 30 minutes of flow for each of the flow rates. On log-log paper this
should be a straight line whose slope is approximately unity for a gas well.
This is done for each of the elapsed times. Finally the one data point for
stabiiized flow is plotted and a parallel line drawn as shown in the sketch
below.
13
StabilizedC/ /
4 hr
1hr
6C / 0.2S hr
10
'//
o , Slope 1/n
,2 ~/ 3/
10~ /
102 2 10 2 5
Flow rate, q, stb/d
The point of this test is to establish a prediction equation for stabilized
flow conditions, thus defining a ' and an n for the equation (Fetkovitch)
q = J,(p 2 _p 2 )n
r w
Normally one would require at least two points (q, P ) at stabilized
conditions, which in a tight gas formation could require days to establdsh. This
method seems to effectively avoia the need for more than one stabilized flow
point because the above equation seems to fit data at corresponding times with
The basis for transient well testing resides in the fact that for single
phase flow, at pressures above the bubble point, Darcy's law and a material
14
Pgz)) = Pc
SV(p-
governing the transient pressure history within the reservoir. Here P is the
VP lc P
k_
for P, or for P- ogz with P - Pgz replacing P. This is the same form as
pressure Pr is
+70.6qB Ei(-
P = Pr kh " 632, kt
where
P = pressure at r, t (Psi)
= porosity (fraction)
and called the Exponential Integral Function. For x < 0.5 the approximation
which provide a lot of intuitive insight into flow and pressure behavior of
wells.
p
t=e'
lp4 I----
Pj
2
r 3
radius, r
P L4
L.
time, t
small r,
7 2P = 0
a steady-state solution.
yield new solutions thus, for example, to represent the pressure history in a
q=C , t > t
P rP- 70.6q
kh u B [1nr2
kn 6.32 kt + .5772]
r kh 24c
w
and
P
r
70.6 q !iB
kh
[ n 6.32 kt2
Ob1cr
5772
6.32 k(t-t5)
70.6 [ ;,n 2+ .5772 ]
kh 2
0rw
for t > t
s
simplifies to
#70.6 t+ At
kh Lt
with At being elapsed shut-in time after producing at rate q for time t s .
situation in a pressure build-up test. Some factors not accounted for in the
Many of these factors have been successfully treated and the literature on the
factors.
18
Pr Bounded Reservoir
(Circular)
P "
t + LE
Zn
At
Bounded Reservoir,
r pGas-Oil ."kfter-Flow".Production
Pw Phase Separation
i Bore
PP
t
t + At
Zn At
P
r
Closed Fault
Boundary
Pw
t + At
kn 6T
19
and porosity in the region between wells. This involves "pulsing" one well by
producing for a brief Deriod then shutting in and detecting the pressure
well and producing at a neighboring point above or below in the same well,
Perhaps the most useful modification of the simple test theory has been
rate q, there is ar, additional draw-down required to move fluid through a well
AP = + 70.6 B qj SD
s kh
with SD a dimensionless factor determined by the "skin". Thus adding this
"correction"
20
22
PP ~70.6 Bgi
qFp ~
r w kn SD+Ei( 6.32kt
are known one uses this equation on flowing data to estimate SD.
Bounded "Circular" Reservoir
~ e
r
state is
c(P-P o )
P= Oe
(1)
( )
(2) 0qPo I +c(P-Po
(3) c -
-V. (0 ) P
(4)
22
one plane at z = 0.
I r P !c ~Pa
r r r - k t
-P- 0 r R
(7)
2 rh h - q B rr
Wj ~r o0 w
P =P 0 t = 0
kt 2
Jo + Be c
(8) P - Po0 E (A 0
+ U (r,t)
where G(r,t) is any special solution of (7) we may need. For boundary
- + G(r,t)
(10) G (Rt) = 0
and
(2
DG q ij B0
= 2
(12) 'w't) +" 7knrw
w
23
Eq. (11) provides an infinite set of roots t3 , 1,2, ... , and it is clear that
Now show that usual zero separation constant solution is not acceptable for
(13) G A Pn r + B
and while this can satisfy the requirement at r = rw it does not satisfy the
(14) = B = constant
r 9r 9r k
= B R
A
(iS) k 2
(19) G = c
IcB r R 2 9r + C + Bt
2 2
Ij
24
the result
(20) B =qB 0
R r 2]hq~c
rR_
w
kt 2
(21) P - Po =
. [Yo( R) J( r) - J0 (R)
]
Y (M.r e
j=1 j j 0
qt B 0 q 1B 0 r2 _R 2inT
2
TER 2-r
] hc
2kh [R 2-r2]
Hurst and Van Everdingen (1949) obtained this solution in a different way and
give the evaluation of the A..
Note that in the series all exponentials go to zero. This is a pseudo steady
state solution with the same distribution of P - P0 versus r at any time but
negative for injection. We call this the "Tank Solution". The sketch below
tiime t -
time t-_
"Tank" Solution
radius, r
25
I i I I I I I I) I i /
20_
1* I
e
I
C._
-- I .. b.,,..9P,......Vh- e l vP..
;_
10- 2 1A -*.I
to-.-...- t I. 6.2
tests, pressure tests and fluid sampling are also carried out on wells before the
well is completed. Such tests are useful to evaluate a zone in a well for
completion.
DRILL ST EM
Method CIRCULATION
REVERSE
VALVE
stem testing is
Drill
* packer
BY-PASS VALVE
* flow control valves
a Fluid sampler II I
SAFETY JOINT
Different service companies
Lij
27
S DRILL STEM
PRESSURE
BY-PASS
I t SAFETY SEAL BY-PASS
VALVE IALVE OPEN
COLLAPSEr PACKER
PA
-SAFETY SSE
C K E R SEAL
ET " CLOSSEED
CLFSTD A E Y SSEAA
. LAACTIVATED i SAFETY SEAL PACKER
PACKER SET DEACTIVATED
y LEAACTIVATED PULLED
LOOSE
Sequence of opcrations for MFE tool. (After McAlistcr, Nutter and Lebourg.")
-- r
Above is sequence of operations. A --
tool
TIME -
second flow-shut-in. I /
E. Unseat packer 7 .
F. Coming out of hole
NOTE: First flow removes mud .
"
I,,
Fluid [low is through a chol e (rrifice) and if critical flow occurs then
1-
, JM I
F C1P
t
estimated from collected fluid volume in drill pipe and a value for 1i is also
required.
Fluid Sampler
Note that the above tool collects a fluid sample at bottom-hole pressure
and temperature.
,)A
L SURFACE.
"..
,-
," . MANUAL
I
" I.
CHOKE
R91G
AIF-
, \ %./':.Y", DATA " ADJUSTABLE CHOKE = .. -
t , .1 HEADER
~iIII
I W OUproTdET de d
PUMP
I IlaPROL' ~h'N
OI
I >'i ':
."ID,'.G ,lDE.O
.*
4.Coime.dlierbii. nd stbiizd lo rt
J, '1 I, igh
...
:,,
: ..
':.,. ..
;...H.YDR
A.U,'Z .. .':E
.
Th. Otls Sprdu vit isdind whehe
p rovd
d''low ior
:_....
PT S. -.
,
..,;' ,.,."".,
.u;"co...
6. Cg on din ptfr maution suc .s
deine
o lowsSLadblowout Th~ IDINGutI'~
revnterstak SI (I'
tre Sd,.S Gnd t
De e.
4. Aon fe
n p b to ween rehbli/prou rck
sn nui
ti ofo (surron~dng.
prsur) thc.
~c Proilimit ortalre rarbon tap.
Codec onaitOiCvse
leased ~. clvWREIN
hdalcal.nge
~ pea~ ,.i.,.u. hi Ome
.9. removing
.LCTsIVrE
SEfucly 4. wne
RcC o re ire and presrur)
liis crwonn
rabi(HN and. orhydr
hdrocabonsn
own trate
bl~oi rvnlrsac h --
r~ ,vleer
atgcs
usgid ote e .
I sthouidh
orm inogd
n ca~l'spabciitoffoinx wth fluid. p u aility and
r ~r
r'en~ag.: g pfozedu~onIIra
te. of-pressur
tapretsure pt onlad lt e
n aw w n'bercormescn
p r stan'ti{
PUMP OPE
osorn
(elot ell. ' ii IwgttaL CyE.nm l.Aslt Ope .F)ptnta.i "lw( a el
GAS LIFT
(53%).
Gas lift involves the injection of high pressure gas (900-1500 psi)
energy to lift the fluid to the surface. Two techniques are used:
high rate and for a short time (2-10 minutes) with the objective
depth.
Fluid production:
Fluid production:
in
lift design.
Pressure Traverse
and gas/oil
hL
3)~~t Wf.\
f P
3
gas phase.
of operating parameters.
4
size, gas-liquid ratio and liquid rate. Other variables include: flow
surface tension.
Tubing Size
size.
0
R.TE SO0 B/D
to Mp
APi
!
*
20 :i, " t q,
~P, j.1.'
" p. t
0
0
1-
AO 0
so-~
I-
6I I I
tubing in relation to the liquid and gas rates the flowing pressure
Rate
-
-
13 2,042
1
1,680
1,37 1 . . ..
. .
5
1,025 1,072 1,285
6
950 972
1,092
SPI : 35.000
DI 2.441 in.
CUT = 0.000%
GLR 500 scfistb
Gas-Liquid Ratio
For a given tubing size, liquid rate, surface pressure and fluid
gas-liquid ratio.
GLR FBHP
0 2,938
100 2,669
200 2,234
300 1,783
400 1,398
500 1,175
600 1,042
800 913
1,000
862
1,500 801
3,000
752
5,000
768
10,000 915
0 q:200 B/D TU BNG . __
WOR : 0 E : 4
. o 35 dynes/ cm
?Q :065
2- ),. vories won P 5 T
T 100OO 014 (D) F
4
u- 3
C)
8
1
IO~~~ 20 2 0
ratio increases.
The effect is reversed for gas-liquid ratios greater
The limiting GLR corresponds -' the minimum flow gradient that
For a g~ven tubing size, gas liquid ratio and fluid properties
Note Reversol
TUBiNG SIZE : I-
WOR - 00
GLR 1000 SCF/STB
2 A\ ~T X 07 i',: 06 5
L7,, :72 dynes/cm
3 T : 00 C 0 14 (D F
u4 jj4
0
o 0
7
7-
6'
8
0
00
0 4 8 1 16 20 24 28
PRESSURE( 100 PSI)
occurs at the surface. This ef-Fect is due to the very low back pressur,
and the high mass rate in relation to the tubing size. It would not
10
the pressure at scme point in the well (usually BHP or well head
pressure). The point on the chart at the same pressure for the
particular gas-liquid ratio oi" the well, represents the point in the
move the fluid to the surface with enough pressure left at the tubing
General Guidelines
ft. of lift.
pressures is
p r - p +
Depth = f
0.15
Fb
rLurs-
I-O
il
-~ Fluid
Pc4of
- f\
13
the tubing the operating valve has to be above the point of balance.
The distance from the point of balance depends on the pressure drop
gradients Yaf and Ybf above and below the point of injection:
where
Df = depth of formation
For a given flow rate Pwf is constant so that changes in Dov and
af will
result in changes in the flowing tubing pressure Ptf
14
Tubing Size
Flowline Size
Liquid Flowrate
Separator Pressure
pressure.
The greater the casing pressure the deeper the point of injection
and smaller volume of injected gas to achieve the same flowing tubing
given condition.
For a given flowing tubing pressure:
'I
I I
SLR
A 3000
o I
6 flX
.. AAP ~wrI
6.~~Ui
For each case the variable of interest is the power for injection
tubing pressures.
z." Tv6;,A
,ijoo Br
FTP = zoo
FTP S00
- -PC - - - I F e- s r
njection pressure.
C1.
-FT9 Z- zoo
FrP-5
-T~j ?M1vrCIC
ec + in
17
power over the range of possible flowing tubing pressures, and the
Note that when various wells are involved having different produc
FTP- Zoo
?r:2 "
-- - FTrCZO
c4 o;, Prejjur .
18
in gas liquid
a
ratio will cause changes in tubing pressure. The
Q= 600 B/D
GLR Ptf
I \~..
800 200
1500 270
/ 2200 235
3000 305
I3 . 3500 305
.30
-,-J
ROD
Fio W
19
PRESSURE (PSI/IICOO
C 7 1.-1.13 1.6 G 2- 5
86 86
-I
,,-I1 __ ..I__ I I
6000 ft
II 2.<o 2700
20
2 200 G'LIZ
R goo GLRP
Flow Ra
-1
Horlo Flow
Vertio Fiow
Wa Fl ow, <t
Fiew
.I
21
Tubing size
Flowing tubing'pressure
Depth of well
Depth of tubing
Production GOR
Production WOR
Design Steps
many methods.
of injection.
A
23
identical
flow rate.
Plot Pwf
3. From IPR calculate Pwf at the desired
from PS
Pwf"
Use gradient curves
surface.
in
casing pressure.)
(Ptf).
10.
Plot flowing tubing pressure
11.
Connect Ptf with point of
gradient line.
the injection of the gas volume necessary to achieve the design gas
liquid ratio.
number and spacing of the valves required to unload the well (unloading
valves).
3T.
0
To ,G,..
VT4,
T" V.I.. 0 -,
I- Cs 6. - 4I.6 B.9A-4.C)
SHaigd .
25
The process aims at reducing the fluid level in the annulus until the
The important aspect is that at any time only one valve should
be open and injecting gas. If this is not the case the efficiency of
Ge
., .,
e -VI,<;
iS
(C6 1
Mc" 1..
'1
VAI..a)
1
d -J
V. I... 1 F-.. TL,... VI F. T.i,,klo I.-
I B, , S-
CT, t i
back pressure.
Pressure valves
i Il "
I
I t -- *5
lo.
6- *000
,,. .....
Valve Mechanics
characteristics
C-)
27
Intermi-.tent Flow:
Large port size to allow quick injection
3. combination of I and 2
A. Unbalanced
Intermittent flow
Fc = Pd Ab
-P-
T~TV
SPp
LJ
28
F =F
C 0
Pd Ab = c (Ab - A ) + Pt Ap
SPd Pt (ApIAb)
c/open 1 - Ap/Ab
A
Let A = R
Ab
Pd - Ptk
P
Pc/open d 1 - Rt
Force to close = Fc = Pd Ab
Closing valve Pc = Pd
Assume R = 0.1
Pd = 700 psig
777 700 0 77
29
Closing
Pd Ab
Opening
P (Ab Ap) + P A
P b - _t
d t
cRo /
Tc/open P
1-R
(less) than P
Open to close
Pc (AB - Ap) + Pi Ap = Pd Ab
Pi A PPi
P
- P R
Pd Ab-
c Ab -Ap 1 --R
L6ellows
30
B. Balanced
Flexibl'e Sleeve
Pc/o > P F-
dDOOE OOE
od NRLHOUSING MANDREL HOUSING
Pc/c < Pd RESILIENT RESILIENT
SLEEVE
SLEEVE
'PC ,*%P
C
-- ENTRANCE , i p-ENTRAN CE
SLOTS SLOTS
_t
-FINNED FINNED
iRETAINER Pt RETAINER
PESILIENT RESILIENT
CHECK VALVE CHECK VALVE
DISCHARGE DISCHARGE
PORTS PORTS
Closing = PD AB
Opening = Pt
Ap + Pt (AB " Ap)
PD : t
,-
C~iokLJ
Fluid Operated Valve (Unbalanced)
Closed to open
Closing mD AB
=
Pt (AB- Ap)
I Opening
+ Pc (Ap)
-J P R
Pd =Pt (1 R) Pc
Also fluid operated valves
Differential Valves
PC Pt + 125 psig
~S~~12 fr;
32
Example: Data
Depth of Well
8000 ft.
% Water
95%
IPR
PI = 3
BHT
210 0 F
S.G. of Water
1.02
Solution GOR
200 SCF/Bbl
Static BHP
2900 psig
F.V.F.
Loaded to Top
Pressure Valves
25 psi casing pressure
33
Intermittent Lift
the tubing. Gas is then injected at a high rate into the tubing
34
at the gas lift valve, gas is injected into the casing annulus through
gas lift valve, gas is injected into the tubing string. Under ideal
upwards by the energy of the expanding and flowing gas beneath it.
The gas travels at an apparent velocity greater than the liquid slug
etration causes part of the liquid slug to fall back into the gas
When the liquid slug is produced at the surface, the tubing pres
sure at the valve decreases, increasing the gas injection through the
valve. When the casing pressure drops to the valve closing pressure,
time occurs during'which the fallback from the previous slug falls or
flows to the bottom of the well and becomes a part of the next slu
/r
35
gas was
initial tubing
PRESSURE (PSIG)
RECOVERY - I 75 BBLS
INITIAL SLUG - 2 345 BBLS
600- LIFT DEPTH, 5940'
600 , LMAXIMU,. PRESSURE
UNDERNEATH SLUG
500
0.
400
MINIMUM
300- AT VALVE
200 PRESSURE
PRESSURE
STABILIZATION
ESTABLISHED
100-
LSURFACE TUBING PRESSURE
0 I . 1 1 1 1i I I I I I
O 2 4 6 B 10 12 14 16 18 20 22 24 26 28
TIME (MIN)
tubing
as
at
of 208 psi
in about 12 minutes.
The minimum pressure represents
and
for 4-5
pressure.
The shape of the curve depicting
upon the
this point.
2. The top of the slug reached 4290 feet in about one minute,
4290 feet, but did not reach the pressure level of 600
as liquid fallback.
stabilized at 80 psi.
This represents the time required
38
cycle frequency.
The pressure recordings at 2493, 1685, 969 and 477 feet show the
same general trends as do those at 4290 and 5936 feet. The times at
which the slug reached these depths can be easily determined. After
The pressure curve at the surface (zero depth) shows the following:
'3.
5. The gas following the liquid slug (tail gas) has completely
Pumping
c) Hydraulic
producing by artificial lift (M 92% of all U. S. producing wells) about 85% use
rod pumping, 2% submersible and 2% hydraulic with the remaining 11% being
produced by gas lift. The majority (93%) of the rod pumping wells are
strippers (less than 10 B/day) although they usually produce greater volumes of
General Concepts
In all cases the pump provides energy to move fluid to the surface
allowing the use of reservoir energy only to move fluid to the wellbore and up
following.
J
2
tf -- - Pressure
it
Net
lift
- . .. Pump depth
Perf. Depth
Pwf Ps
Depth
The pump will be set at a depth greater than the Jiquid level in the casing
annulus to insure that sufficient head is available to flow into the pump
intake.
formation productivity. If the pump capacity is too large the fluid level will
drop to the pump level. Gas will enter the pump, reducing its efficiency and
possibly damaging it. If the pump capacity is too small the fluid level will rise
above that required to maintain the appropriate drawdown (Pr - Pw) and it
of gas in the flowing stream. Whenever possible pump depth should be such
that the intake pressure is greater than the bubble point pressure of the fluid
3
being pumped. For most applications this can only be achieved by letting tile
majority of the gas in solution evolve and rise through the annulus tobe
Liquid + Gas
Gas out
Gas
-Gas
* C"
00 0
Gas +liquid
-".Liquid
Pump
4
the downhole positive displacement pump from the surface beam pumping unit.
System components:
a) Pumping unit
- Prime mover
- Gear reducer
- Beam
- Counterbalance
c) Downhole pump
principal elements.
II 111kO;Ct N -
CASING --:-g_-
POIHRODS .LAMP--
PU PNUTE8 W PB.
CASING
CASING - CAIH
RN
SHOES
6
Production engineers are faced with two types of problems with regard
to rod pumping:
a) Design problem
b) Performance problem
In either case the design objective will be to produce at a certain oil flow rate.
a) Pumping Units
Conventional or Crank C
Counterbalance
Beam Counterbalance B
Air Counterbalance A
Mark II (Unitorque) M
Long Stroke
CONVENTIONAL UNITS
BALANCE
FULCRUM
* -. . . =
rOACE
COUNTEA
BALANCE
00 0
COUNTEU
rN,- 0 0WEIG"T
TKAVEI.INC,
STUFFI N(
BOIX
WISEAL IN
CJ I~IAI
ANC:F.
The following table presents the typical range of above parameters corresponding
C - 228 D - 200 - 74
Conventional, 228,000 in-lb Double gear reducer, 20,000 lb beam load, 74 in.
maximum stroke.
13
Applications
reducer.
Tapered rod sth'ings are commonly used in deep wells in order to optimize the
utilization of rods and reduce overall loading. API RPIIL presents
recommended combinations of rod sizes as a function of the diameter of the
pump plunger.
14
TABLE 4.1
ROD AND PUMP DATA
See Par. 4.5.
1 2 3 4 5 6 7 8 9 10 11
Plung. Rod Elastic
Diant., Weight, Constant, Frequency Rod String, % of each size
Rod" inchcs lb per ft in. per lb ft Factor, I
No. D W, E, F, 1 1 % % '
44 A ll 0.726 1.990 x 10"0 1.000 .. ......
.. ..............100.0
54 1.00 0.908 1.68 x 10"c 1.138 . 44.0 55.4
"
54 1.25 U.929 1.63:3 x 10 1 1.140 49.5 50.5
54 1.50 0.957 1.584 x 10-a 1.137 56.4 43.6
54 1.75 0.990 1.525 x 10-0" 1.122 64.6 35.4
54 2.00 1.027 1.460 x 10 t 1.095 73.7 26.3
54 2.25 1.067 1.391 x 10-0 1.061 83.4 16.6
54 2.50 1.108 1.318 x 10"0 1.023 .. 93.5 6.5
55 All 1.135 1.270 x 10.0 1.000 .... .... 100.0 .......
"
64 1.06 1.164 1.382 x 10 ' 1.229 ..... .... 33,3 33.1 33.5
6A 1.25 1.211 1.319 x 10-0 1.215 .. ..... 37.2 35.9 26.9
64 1.50 1.275 1.232 x 10"0 1.184 ......
........ 42.3 40.4 17.3
61 1.75 1.341 1.141 x '0.6 1.145 ....... .... .. 47.4 45.2 7.4
.
65 1.06 1.307 1.138 x 10.68 1.098 .. 34.4 65.6 .....
65 1.25 1.321 1.127 x 10 1.104 ........ .......37.3 62.7
.
65 1.50 1.343 1.110 x 100 6
1.110 41.8 58.2 ........
65 1.75 1.369 1.090 x 10. 1.114 46.9 53.1 .......
65 2.00 1.394 1.070 x 10-6 1.114 . 52.0 48.0
65 2.25 1.426 1.045 x 10.8 1.110 .... 58.4 41.6
65 2.50 1.460 1.018 x 10.6 1.099 .... 65.2 34.8 .....
65 2.75 1.497 0.990 x 10.6 1.082 ..... ... ..... 72.5
........ 27.5 ........
65 3.25 1.574 0.930 x 10.6 1.037 ... 88.1 11.9
66 All 1.634 0.883 x 10. 6 1.000 .. 100.0
75 1.06 1.566 0.997 x 10.8
-
1.191 27.0 27.4 45.6 . .
75 1.25 1.604 0.973 x 10 0 1.193 29.4 29.8 40.8
75 1.50 1.664 0.935 x 10"a 1.189 33,3 33.3 33.3
75 1.75 1.732 0.892 x 10. 66 1.174 37.8 37.0 25.1
75 2.00 1.803 0.847 x 10. 1.151 .. 42.4 41.3 16.3
75 2.25 1.875 0.801 x 10. 6 1.121 46.9 45.8 7.2
76 1.06 1.802 0.81]x 10.8 1.072 . 23.5 71.5
76 1.25 1.814 0.812 x 10-"6 1.077 30.6 69.4 .......
76 1.50 1.833 0.804 x 10 16 1.082 33.8 66.2
76 1.75 1.855 0.795 x 10. 6 1.088 37.5 62.5
76 2.00 1.880 0.785 x 10. 1.093 41.7 58.3 ........
76 2.25 1.908 0.774 x 10 ""c 1.096 46.5 53.5
76 2.50 1.934 0.764 x 10 6 1.097 50.8 49.2
76 2.75 1.967 0.751 x 10.8" 1.094 56.5 43.5
76 3.25 2.039 0.722 x 10 06 1.078 68.7 31.3 ....
76 3.75 2.119 0.690 x 10. 1.047 82.3 17.7
77 All 2.224 0.649 x 10. 6 1.000 100.0 ...
.
85 1.06 1.883 0.873 x 10 06 1.261 22.2 22.4 22.4 33.0
85 1.25 1.943 0.841 x 10.-6 1.253 23.9 24.2 24.3 27.6
85 1.50 2.039' 0.791 x 10 1.232 26.7 27.4 26.8 19.2 .......
85 1.75 2.138 0.738 x 10.0 1.201 29.6 30.4 29.5 10.5
8
American Petroleum
Lv
16
2 3 4 5 6 7 8 9 10 11
Plunger Rod Elastic
Diarn., Weight, Constant, Irelucncy Rod String, % of each Bize
Rod* inches lb per ft in. per lb ft Factor, I
No. D W, E, F, 11,4 11 1 % %
107 1.06 2.977 0.524 x 10" 1.18.4 16.9 16.8 17.1 49.1 ... ........
107 1.25 3.019 0.517 x 10'- 1.158 17.9 17.8 18.0 46.3 ... ...
107 1.50 3.085 0.506 x 10""' 1.195 19.4 19.2 19.5 41.9 ....... ........
107 1.75 3.158 0.494 x 10 0 1.197 21.0 21.0 21.2 36.9
107 2.00 3.238 0.480 x 10- u 1.195 22.7 22.8 23.1 31.4
107 2.25 3.336 0.464 x 10"6 1.187 25.0 25.0 25.0 25.0 ......
107 2.50 3.435 0.447 x 10" 1.174 26.9 27.7 27.1 18.2 ......
107 2.75 3.537 0.430 x 10"0 1.15; 29.1 30.2 29.3 11.3
108 1.06 3.325 0.447 x 10- c 1.097 17.3 17.8 64.9 ........ ........ ........
108 1.25 3.345 0.445 x 10-6 1.101 18.1 18.6 63.2 ....... ........ ........
108 1.50 3.376 0.4.11 x 10" 1.106 19.4 19.9 60.7 ...... ..... ........
108 1.75 3.411 0.437 x 10"0 1.111 20.9 21.4 57.7 ...... ........ .......
108 2.00 3.452 0.432 x 10-8 1.117 22.6 23.0 54.3 .. . ........ ........
108 2.25 3.198 0.427 x 10-1 1.121 24.5 25.0 50.5 ...... ....... .....
108 2.50 3.5.18 0.421 x 10" 6 1.12.4 26.5 27.2 46.3 .... ........ ......
108 2.75 3.603 0.415 x 10-" 1.126 28.7 29.6 41.6 ........ ....
108 3.25 3.731 0.400 x 10 "( 1.123 34.6 33.9 31.6 ........ ....
108 3.75 3.873 0.383 x 10" 6 1.108 40.6 39.5 19.9 ........
109 1.06 3.839 0.378 x 10. 66 1.035 18.9 81.1 ...... ...... ........ ......
109 1.25 3.845 0.378 x 10. 1.036 19.6 80.4 ........ ........
109 2.75 3.930 0.371 x 10.0 1.051 29.4 70.6 ... ...... .......
109 3.25 3.971 0.367 x 10"0 1.057 .3%.2 65.8 ..... ..... ......
109 3.75 4.020 0.33 x 10. 6 1.063 39.9 60.1 .............
109 4.75 4.120 0.354 x 10" 0 1.066 51.5 48.5 .......... ........
*Rod No. shown in first column refers to the lurgest and smallest rod size in eighths of an inch. For example,
Rod No. 76 in a two-way taper of 7/8 and 6/8 rods. Rod No. 85 Is a four-way taper of 8/8, 7/8, 6/8, and 5/8 rods.
Rod No. 109 is a two-way taper of 1/4 and 1A rods, Rod No. 77 is a straight string of 7/8 rods, etc.
As the pump diameter increases the fluid load carried by the rods increases
b) Elastic Constant
Stretch of unit length of rod (0 ft) per unit load applied (Ib)
inlbf
Er Er lb-ft
I b
K Er x L = elastic constant of rod string of length L ( )
r
c) Frequency Factor F
c
N I
0-=Fc No N'0
o O
F = 1.085
I
I L
F
C
o0 4L
When sucker rods are combined into a rod string of a given length driving
Rod Stretch
For a total force F applied to a rod string of length L the rod stretch
S = Fx(ErL) _ F
r r -K
r
S r 12 E
F - LA L
A22 L3 _]
A3
For a unit operating with a polished rod stroke 5, the ratio of the rod
stretch to the stroke is a measure of the stiffness of the system and is defined
as dimensionless rod stretch. When F (the static load correponding to the
S F
Dimensionless rod stretch - r o
5 - SK
r
This parameter is used I.ncalculation of the pumping system performance.
This parameter expresses the relation between the speed of the pumping
unit, N (strokes per minute) to the fundamental frequency of the rod string.
(No or No'
0
2N0 2N0 2N
General!y asynchronous speeds (N = 5 '- are more
No N o
Maximum pumping speed corresponds to the asynchronous speed well below the
d) Downhole Pumps
21
of the tubing.
Types of Barrels:
L - liner
metal plunger.
H - heavy wall
S - thin wall
soft packed
P - heavy wall
-- Barrel
T.V.
p
22
The rod pump offers the advantage of complete replacement without having to
pull the tubing from the well. In the tubing pump both valves and plunger can
be replacedbby pulling the rods.
Tubing pumps offer the largest plunger area and thus the largest volumetric
displacement.
Pumping Cl
During one complete cycle fluid is admitted into the pump barrel and
then transferred to the tubing through the hollow pump plunger. During the
upstroke the fluid column in the tubing is supported by the sucker rods through
the travelling valve. During the downstroke the fluid is supported by the
-- -- /,
1 a * V,
DOWN UP TOP
Pump Capacity:
IF
It is a function of the net stroke of the plunger, the plunger diameter, the
Q = 0.15 x Ev x Ap x Sp x N
Ev = volumetric efficiency
Also a fluid load factor is tabulated, which corresponds to the weight per foot
specific.gravity of 1.00.
24
The following tables present this information for standard size pumps.
PUMP CONSTANTS
2 3 4
TUBING DATA
1 2 3 4 5
Elastic
Outside Inside Metal constant.
Tubing diameter, diameter. are., in. per lb It
size in. on. sq. in E,
- 80 pet efficiency
Nst Lift fluid Production - Barrels par day
of rluid 700 oo 900 1000
300 400 500 600
ft. 100 200
/ 14
2 3/ 3/4
1 V4
2 2 1it 1/2 2 3/4 2
200 11/2 2 1/4 2 1/4
1 1/4 13./2 3/
2 1/2 2 3/4
23/4 2 3/4 23/4
2 1/2 1 3/I 2 1/4 21/2
13/4 2 21/4 2 14 2 12
3000 11/4 11/2
2 1/142 L 2 1/ 2 14 23/4
11/4 1 3/4 2
4000 1 3/4 2 2
1 1/2
1 1/ 1 1/2
1 1/4
1 1/8
26
Pump Efficiency
fillage of the barrel. This in turn is related to the presence of gas, the
viscosity of the fluid being pumped and the pumping speed.
Slippage of oil past the plunger also affects the volumetric efficiency.
3.6 x dx c x A P x 106
3
Q/leak v x L
c = clearance (inch)
In addition leakage of fluid past the valves reduces the pump efficiency
The cyclic nature of the rod and pump motion introduces sequential
loading and unloading of the sucker rods and tubing. The calculation of plunger
stroke thus requires correcting the surface stroke at the polished rod for the
elastic deformation (stretch) of the rods and tubing. The dynamic nature of
forcing oscillation of the rod string. The generalized problem including stress
wave propagation has been solved numerically for numerous cases of standard
In general terms
Sp = S - Sr - St + overtravel
SP.0
__ Fo
S Kr
1.0
F/
I -
Fo N
in
K Et L witere Et = tubing Elastic Constant lb-ft
12
t At E
I .20 F
.5 Sk,
- - .30 -
1. 4 40
1.3 .0 -- -
-
-
1.2
.15
p .05 --... *.
- - -
0.4--- - :
0,9 -
0.4Kt F i-
- - -- r .f
- - - ..-. - - i- - - - - - -
FIGURE 4.1
8'PLUNGER STROKE FACTOR
30
If the above dimensionless plot is not available the net plunger travel can be
calculated as:
12F o 1 L2 L3 12 F LT
S-
Spl + + TT E A
12 SN2 M L I _L 2 + L3
+TWr 70500 " A2
The above relation does not include dynamic effects caused by stress wave
propagation
(in )
At = tubing cross-sectional area
Calculation of Loads
minimum loads experienced during the pump cycle. These loads determine the
size of the pumping unit the torque rating of the gear reducer and the power of
J Rod !.oad =
Cts.
tor
motion.
07 Acceleration at
Angle 0o polished rod
Angle 7
32
where
'27T N radians/sec.
60
N = strokes per minute
v
velocity in/sec.
a = a Coscot so that
z
so that
machinery factor (m) dependent on the geometry of the unit and setting
a r/dynamic = r/ statgc (
- = acceleration factor = C
Then C MN2S
70500 (Dimensionless for 5 inches and N, Spm).
N max = 21150
33
The acceleration factor does nit include other effects due to vibration and
pumping speed is, and the elasticity of the rod string. They are expressed in
S)
F I
0.5
;00 o4.
.0 3 Fo
- 1o - - - - - - - - - - - - - - - - - - , - / _--- I
_ II - - -- ' -
0.4
03
02
oc Ol 0.2 . 0.4 05 06
N
No
FIGURE 4.2
F1
PEAK POLISHED ROD LOAD
35
VII
36
50
r
Sk r
F2 I. .
Skr... ....
....
.
No
N0
FIGIURE 4.3
F1
-k'- MINIMUM POLISHED ROD LOAD
Torque Calculation
Peak ?norque determines the size of the gear reducer for a given unit.
of crank.
S = stroke (inches)
Td = dynamic factor
Counterbalance
Upstroke
At crank:
Wf I"Wup
- -
-
wr:f t
Wfr w
WfrIWfr
rf
Downstroke
At crank:
Wrf
Wd n
wa
\ /
Wfr
Wb
wbf CB Tf
wa
Torque =(W
+ Wa Wfr
39
W + 2 Wrf = 2 Wb
VI Wrf + 1 Wf
b Wf +2 f
Wr
f
-W
r
- rb
7.85- I
7.85
W = 0.87 Wr
r
Ideal Counterbalance
Wb = 0.87 Wr + Wf
The above assumes that kinetic and frictional effects are the same in the
upstroke and downstroke. This is not true due to the unit's geometry.
2T
PT = ($ S2 K )x Sk r x S x Ta
r
Wrf
40
.I
N
PEAK TflAQUL. F ,R VALUES OF
Wfg/Sir :3 USE TOR~QUE A( JU5TNEHT
:
FOR OTHER VALUES OF Wa /Si,.
FIGURE 4.4
rT
..... PEAK TORQUE
75I N-
,0.6 %9 N
-5
Fk . F, \j
0.3 7 1.0%
0.2 '
15% N 0
-T-
0.
0.0/
w it
ADJUSTMENT :3%, FOR EACH 0.1 INCREASE IN ABOVE 0..
0
TOTAL ADJUsrMENT* 3 x 3 / 90/,
To - 1.00 4 0.09 : 1.09
FIGURE 4.6
T., ADJUSTMENT FOR PEAK TORQUE
W1
FOR VALUES OF Sr OTHER THAN 0.3
42
Power Requirements
Efficiency 0.35
dimensionless plot of peak polished rod horsepower from API RPI IL.
06 .t.~~
....
O B
.. I.I ..- - -- - F0 =
Fo
= .4
-r0
017 - Sk
.....
.
_.... ..
..
- F0 -
4 ~~~I~t7Fo
-1 --i-....
.....
'- - S-=
r 0.2
F Sk,
.
04r i Tv0 . k 0 .. I
0k0 . .J......
.. .I I ....
. 1. ,. V i i...... - 7 S
f_0- = 0 4 8 0 6
---
o- t 4":' "
N,
. ...
..... ---
FIGURE 4.5
pa /V
POLISHED ROD BMWS' POWVER
44
T Tensile Stren.gth
-T T T Mean Stress
-T/6
-T/3
Vm
Mil 6 Tar
provided
T in o
T and Tmi are obtained by dividing PPRL and MPRL by the rod's cross
max min
sectional area.
M
46
Whether the design involves selecting a new unit or using an existing unit
exceeding the:
Allowable Torque
Rod Stress
Formation Productivity
Fluid Properties
The productivity is used to calculate the depth of the working fluid level
at the desired rate. The fluid properties are used in the load calculations and
Pump depth
Pumping speed
Pump diameter
Then the plunger stroke and pump displacement are calculated and checked
with the desired rate. If not satisfied new parameters (rod size, pumping
speed, pump size) are selected until the rate requirement is fulfilled.
The loads are then calculated and used to select the appropriate pumping unit
Selection charts and tables published in API BUL11L4 are very usefu! in
A 912,000 144 . 96
s 912.000 168 96
000o
1 640,000 85 97.
" 640,000 100. 96.
1700
0 640.000 120 96
640.000 144 96
1600
1 640,000 ,68 85
640.000 120 87
140o 456.000 86 86
i, 45(3.000 86 96
1400
,2 456.000 100 96
130 4~5 6.000 120 96
120,
5 00 10 9
I- 320.000 74 76
, 320.000 74 85
<120
In
0
I.
-.
100
17
320,0--0
320,000
86
100
85....
86
w 1000
,. 228.000 64 75
90020 228.000 74 75
900
V) o1 228,000 74 85
620 160.000 54 65
23
130 160,000 54 75
2A o4 160.000 64 75_
700 160,000 "64 85.
2 1 14.000 48 55 .
600
27 1 14.000 .48 64.
zoo 26 220 1 14,000 54 65
2t 1 14.000 54 75
AOo 80.000 42 55
1,2
80.000 42 54
27 L 20 to3 80,000 48 54
-"-
33 80,00OCO- 54
32 21S 80.000 54 64
- . 24 . j 57.000 36 54
7 3334 29 57.000 42 54
300 36 48 54
-oo
: 57.000
3 4 7 D
0 2
TORQUE: 640.OC
BEAM RATING:-36,50C
STROKE: 8E
w
13/4""" R............
DESiiN:
" -9
37 BEAM LIMIT- 36,500 2 1/2, -
36
35
%/
~33
32
'- 3/A "
31 2200 PROD.
3 3/4"
30 2000
2"
:. 29 01&oo 11
m 3 3/A"
2a t2wioo STRESS 2 3/11, /
w
w m 2 3 '4'*
27 U 1400
U, 2-7
026 n1200 2
-- "
2 3/4" /
2 1/41 2 114'1
2 2"
100
3 3/4"' 3/4"1 - 3/4-F
25 30 35 40 45 0 55 60
wDEPTH. 100 FT.
30
2r12 3/A" 1 t/A"
2,3/''122 2_ 2 1/4".
20 2 3,/4- - 2 1/2''
0 3 3/4"
I- t' 3 3/4"
LUFKIN INDUSTRIES, INC.
Field:
County: State:
Plunger Dia.: Inches - Tubing Size _ Inches - Rod Size: - Pumping Speed SPM
3. Fo/SKR = +. =
6. BPD (100% eff.) Pump Const. Table I x SPM x Stroke x SP, Tabie 3 _xa ax_
8. WRF/SKR = _- =
CONVENTIONAL UNITS
MARK II UNITS
25. NOTE: Do Not Use Less Than One Size Smaller Reduced Than Required For Conventional Unit March 1973
50
Dynamometer Survey
The load-displacement curve is measured at the polished rod during one
or more complete pumping cycles. The resulting diagram is compared with
theoretical or with previously measured diagrams in order to identify abnormal
characteristics.
upstroke
load
Wf
- downstroke friction
Wrf
up
e-
stroke length
52
b) Influence of acceleration
decrease due to
acceleration
I I
stroke length
. gas compression
V_T l - -_ . - Wrf
T.V. /
opens
stroke length
53
load
stroke length
load
maximum load
minimum load
stroke length
0
Atlantic Field - Arkansas
Ir
GAS ANCHOR
-- 3/4_.2"-A. r 5/8" _ "
SUCKER RODS: 1 __ 7/8
0-,507i7II:MA .-
.15-.30:NI 3,00-3-50"
TYPESTEELC ,07.
-314 .N_.LI-T PLGR.
P 1- I <
PUMP 2 IN. -. CA
MOTOR 2r HP ELETRI
PUMPING UNITJ-L&--8.LMr---- 2 85 2 0
PEAK TORQUE . IN.-0: 0
UNIT RATING: LOAD-25-M000L-
GEAR BOX: SINGLE. DOUBLE X RATIO
SMOOTH OPERATION.
THESE DYNAMOMETER
CARDS SHOW VERY
8
A REASONABLE
CHANCE
THIs
MEANS THE SUCKER RODS
HAVE
OF THE CORROSIVE
FOR :ROUBLE-FAEE
OPERATION
IN
SPITE
UNIT STRESS Is 26,000 PsI.
FLUID CONDITIONS.
10L
RANGE
7,700 LB
SPCED
18 8PM
STROKE
64 IN.
POL ROD HP
11.02
ENGINE
RPM 1170
TIME
11:00 AM
ZEKIV
RANGE
7,700 LB
18 SPM
SPEED
STROKE
64 IN.
POL ROD
HP 10.64
ENGINE RPM
1170
TIME
11:15 AM
ZERO
55
42
STROKE LENGTH 1t, S.P.M. 2 A.V.E. 22.3 PrT 2
No
CASING SIZE!LtFET 2025 TUBING SIZF 2 I 4-
GAS ANCHOR No TUBING ANCHORED No
SUCKER RODS: I - 7/6 __ 3/4'202e . 5/8" '
1035 CARBON SaZ In
TYPE STEEL
PUMP 2 --. /4 ' 7 c - PLGR.SIZE 1-_/4 IN- z
PUMPING UNIT TWIN CRANK MOTOR IA HP - 4-vTi r W-
UNIT RATING: LOAD-1I-0.4Lrin
fi PEAK TORQUF 57,000 IN.-LL 0
GEAR BOX: SINGLE DOUBLE L RATIO.2933/1 -
THESE CARDS ARE CHARACTERISTIC OF LOW PRODUCTION OR
DIFFICULT TO
DECREASE THE PUMP DISPLACEMENT ENOUGH
10 I
MAX LOAD 6,800 LS
RANGE 5,000 LB
SPEED 20 sPM
-STROKE 42 IN.
POL ROD HP 1.71
ZERO TIME 11:30 AM
RANGE 4,200 LB
SPEED 20 sPM
STROKE 42 IN.
POL ROD HP I .14
TIME 12:15 PM
ZERO
56
0*
AGITATING
REASON SHOULD PUMPED AT A SLOW SPEED.
BE HIGHER
SPEEDS OF OPERATION WILL
ONLY PUT INCREASED LOADS
RANGE 6,400 Lb
SPEED 17 SPM
STROKE 64 IN.
TIME 8:05 AM
ZERO
RANGE 1,200 LB
SPEED 13 SPM
STROKE 64 IN.
TIME 8:35 AM
ZERO
57
o.
Gaines County Field - West Texas
5300 FT FORMATION LIME
TOTAL DEPTH 6
DAILY PRODUCTION: Oil 10 " WATER . SP. GRAV.-
STROKE LENGTH 44 IN.
S.P.M. 16 A.V.E. 23.1 PET 2.
FLUID LEVEL: STATIC - PUMPING- Low B.H.P.
PROGRESSIVE PUMP-OFF OF A
WELL. A TAPERED STRING
ZERO
58
0-
RANGE
9,400 LB
SPEED 16 sPM
STROKE 56 IN.
ZERO
RANGE 9,400 LB
SPEED 16 SPm
STROKE 56 IN.
ZERO
k'1
59
of crank angle.
q00
120) 150 I1&0"
0 300 600
c
0
3600330 3000 2700 2400 e13 1S3
CRANK ANGLE
A
4.5
[
A
V &/
-J0
*.GAJkS.2JCT):
0 3 .0 -~-
I")
o o l 0 19o ro 30
by removing the dynamic effects j', 1he rod string obtain an equivalent
Use beam load monitor (strain gauges) or polished rod load cell.
Usually position information is not monitored, but some systems also include
when unit can be shut down to save power. Also gives indication of
malfunctions:
a) Rod failures
b) Pump wear
c) Friction
d) Pump efficiency
well
The same system is available in portable form allowing fast diagnosis of
the determination relies on tubing collar reflections. Curves are also available
Method I
Two fluid levels are taken with different back pressure in the annulus.
Measurements are taken sufficiently far apart to insure that steady state
5HOT
10
I 'I
12
13
19
14
17
20
21
222
23
24
24
25
26
27
FLUID
LEVEL
JBJECT
G3
el.t
.*'rn~-, '.h .
P Pressure for \
.'cuFlowing bottoi
g s +- -,,--e assure
fl~ y
Method 2
Close casing to depress fluid level to the pump, until well pumps-off.
Then
The production rate is disturbed by the flow of gas into the tubing.
where:
Method 3
R
m
determined from a pressure build-up of the casing which is shut in after taking
the sonolog.
65
R R Prssr
Pressure (psi/min)
time
Time
P
0.68 R(
D + g mcf
A 1000 433 G day-sqin.
Pg = gas pressure at D
G = gas gravity
Pg (.1 D
40000
)P c psia
G = 0.433 x R m x yZ psi/ft
P 2 - P
h -G
\2f
66
PC Pressure
Pq
0 D GL IAhl
I II
E
T Ah
H 2~e
oil 2/ h
gas 3
0
D
C,
0
SUBMERSIBLE PUMPS
INTRODUCTION
on
application is based
two key characteristics of the submersible
pumping system:
amount of horsepower at
the pump of any pumping
in oilfield applications.
rates
than positive displacement pumps in wells
of limited diameters.
the
equipment such
seal section or protector, cable, and surface
submersible installation
transformer aad switchboard. A typical
is shown in 'igure 1.
SWITCNKIGO / /---,
|O DRAINfVALVE
Y[K'l
TUlING
SP"LICE
MO.- ILAT
lTOR
CASING
IUNTAI[
SEAL t[CTION
M OTORI
Figure 1.
---
Over recent years the industry has gained considerable
holes.
COMPONENTS
Motor
3475 rpm in less than fifteen cycles, thus reducing drag on the
-2
to separate a substantial portion of any free gas in the produced
PUMP
Electric Cable
0
wells with temperatures in excess of 275 F. Mechanical protec
tion is provided by an interlocking armor of steel or monel, as
Junction Box
box also provides a vent to the atmosphere for any gas that
Switchboard
-3
Simple units may contain only push-button, magnetic contac
tots and overload protection. More sophisticated switchboards
will use solid state mot,. :nrtrollers for time-delayed underload
protection oD all three phases, time delayed overload protection,
ground.
Check Valve
tubing from unloading through the pump when the unit goes down.
could bre~k the pump shaft, burn out the motor, or burn out the
or to pump treating fluids down the tubing and through the pump.
-4
Wellhead
pack-off which provides for a positive seal around the cable and
Transformer
DESIGN PROCEDURE
In sizing
a submersible unit for a high WOR application
-5
4. For given capacity, select the pump type which
Collecting Data
of the gas, oil viscosity and any other special operating con
ditions such as sand, corrcsion, paraffin, or emulsion problems.
turbulence in
the bore zrea. For this reason it is generally
H = hd + ft + Pd
-6
I
Pump Selection
rates and casing size. The largest diameter pump which the casing
calculated total dynamic head can be made using the pump perfor
mance curve. This may be calculated as follows by reading the
Motor Selection
surface voltage is the sum of the cable IR drop and the rated
-7
Switchboard
Transformers
equation is recommended.
1.73 x Vs x Am
KVA =
1,000
bank initially.
EXAMPLE PROBLEM
step by step:
Well Data
l. Physical Description
b. Tubing
6300 ft of 3-1/2"OD UE 8rd
-8
c. Total Depth 7500 ft
d. Perforations 6400 ft - 6900 ft
e. Pump tetting Depth 6300 ft (100 ft above
top perforations)
f. Other Corrosive Environment
2. Production Data
Level
(Pwf ) 4000 ft from surface
d. BH Temperature 180 0 F
e. Gas-Fluid Ratio 50
f. Water-Oil Ratio 60
g. Surface Discharge
4. Power Supply
fluid level (Pwf) and the static fluid level (Pi). Using the
equation:
-9
FIGURE 2
-&co ,-vo
vi
4 PRu L 4000
. .. . . .. . "I'R"
+" 0 +5D.BFD
- i0
After the weli data has been collected and plotted, the
TDH = hd + ft + Pd
hd = 6,000 ft
REDA or CENTRILIFT.
Pd =
1.02
= 226.ft
Pump Selection
After calculating the TDH and knowing the casing size, the
REDA Pump for illustration, (see Table 1 and Figure 3), the
correct pump would be "G" type, 540 series (5.13 in. OD) pump.
due to unbalance can shorten the pump life and the pro
tector thrust bearing load will be significantly increased.
-11
TABE1E 1
T WREDA TABLES
PUMP
RATING FOR _rr___r___ I_'_iTS
OIAMETER
SERIES JI NCHES) TYPE PUMP'SKAFT (BPD) (mniD)
A-10 7S 280.J50 45 1?
A-14E '4800 76-10
338 3.3
-ZSE 5 100-060 1l2.16
A- 9OO-500 11-7c
1400-000 71] .
50 -Sl00 =0
Io0-55' 100 1 1400-24:00 2]-]
e oa 20o 2 -0 ee 6
334ort
FIGURE 3
, Fe -,er: .--- ot . . . ! . . .t od L.
4000
3500
2500
500 5
SoI i 10
;i: ,l i-13
2. From Table 2, read the desired pump output at 4500 BFPD
and find:
33 volts
6,400 ft (Cable) x 000 ft = 211 volt loss
6,400 ft x 33 volts
= 2101 Volts
-14
-1 711/
/OX, SIZA-11
11/W
IIX
AL . ALUMINUM
FIG.- , VOTAGE DROP PER 1.000 FET OF CABLE-CABL SZES FROM wITO v10
tubing collars and well casing and select the type of cable whici
us flat cable.
Switchboard Selection
future use.
Transformer Selection
CONVERSION FORMULAS
ALTEKNATING CURXENT
DIRECT CURRENT A
TO F1ND
Sinle Ph&". t Three Phase
Amoer c H.P. X 746 H.P. X 746 H.P. X 746
When Horse Powur (Input)
Is Known Volts X Effiicocr Volt, x Efficirocy X P.F. Volt, X 1.73 X Eflfcicncy X P.F.
Amps KW X 1000 KW X 1000 KV X> 1000
Vhen Kiowatt
isKnown Volu Volts X P.F. Voltsx 1.73 x P.F.
Amperes ky, X 1000 kvi X 1000
Wheni ka
is Known Volul Volts X 13
Armpe.s X Volts Amps. X Volts X P.F. Amps. X Volta X 1.7.3 X P.F.
mlosatts
1OO 1000 1000
Amps. X Volu Amps. X Volu X 1.73
kva
1000 1000
Flo-atts X 1000 K\V X 1000
k"t kvk
Pa-er Factor and Efficinoy -hen used in sbove formulas should be exprrised as dctirmals.
I For !.pha.4. A.wtrvsubstitute 2 instead of 1.73.
f For -pksc. 3.-wire substitute 1.41 iisteJ of 1.73.
TABLE 2
taps.
-16
Computer Design Approach
based on this production data. The program has three main design
phases:
3. Pump Selection
FAILURE ANALYSIS
stream.
5. Switchboard troubles
6. Faulty Equipment
8. Lightning
-17
submersible electrical motor. Proper, timely and rigorous analysis
FIGURE 5
too
* /9
DARco -I,
_ _ F
%off
The start up on t'is chart indicates a normal drag. down and con
t'inuing good production rate. Very little, or nc gas or rood gas
separation, is inc..cated by the smooth steady current holding at
74 amperes.
CHAJU I 381
-18
FIGURE 6
V.-_ zz 6A.M . ?~
I! j t.o.. 4N
E PU C M NCART NO.381t
Z- .
te unercrren
oil n reay.e n7 gasn,bublot sow t
CI.NOFTWIC A
The amperage on this chart indicates that after a normal start.
very gassy: the unit pumped off or gas locked at 8 a.,m. and went
D. TYPICAL AMMETLP.
CH.,.RTS
h 6 AM
. . M
N-9.
7/ / /R , S AT I O
A R C IA-UIT
CtAT NO.,al
.;~
0L 0E' - .
______________ .
(71
From a static lc-el this well pumped off in 5 hours 10 minutes. After
a llowing 35 minutes build up time, the pump started again and ran about
45 minutes, then Dumped off again. Indication: The well is not prolific
enough for this Large a pump. Possible remedie : Well work-over (frac,
acid. re-perforating. clean out, etc.) in attempt to bring more fluid into
well. If work over f-i.ls to produce more fluid, the need for a smalier
pump is clearly indicated. This could result in continual running time,
higher efficiency, lower pumping unit cost, better overall economy.
-20
RECENT INNOVATIONS
in use are:
service.
-21
Pressure Traverse Charts
.
...... .
.. . ...
_ F_ .
,...
" '. . I
i:.DEPTH
.i:....i.:
,i :I -PRESSURE TRAVERSES
!: . : !: E i ,
. ::i~
t:'!:x'' ".i ~
TUBING DIAMETER (S) - 1.995 INCHES
.:. .L 10 U:::lD RATE
LUI - 100 B/D
.... ....
W
...
".- ATER CUT - 0
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'CRESSURE, Psit.
0 500 1000 15(-10 2000 2 5000 3000 3500
0.
FIGURE 3
DEPTH -PRESSURE TRAVERSES
. TUBING DIAMETER (S) - 1.995 INCHES
L IUI
: 1D RATE -100 B/D
ATER CUT - 0.650
Q, _:..
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PrRESSURE , PS,A
0 500 1000 11500 ?000 21.00 "3000 3 t00
L ":LL~iZ; , ,FIGURE 4 .]
, I I:,:I DEPTH,- PRESSURE TRAVERSES
I t_:_..___:... __.
" Li TUBING DIAMETER (S) - 1.995 INCHES
: IQ:U :[
D R T E- 2 00 B/ D
, I:.i,"WATER CUT - 0
'7...
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: :..' 'FIGURE
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25L
.
PRESSURE ,PSIA
00500 1000 1500 20 00 21500 '" 3000 3500
. .~..
".,-, . ~~ . ~.; _.~
...:F~ .. ~
... .. ~~ F GU R E 6
, : :: :: : : DEPTH -PRESSURE TRAVERSES
:: . ....... TUBING DIAMETER (S) - 1.99.5 INCHES
, : '::!.:i:ii-:LIQUID RATE - 400 B/D
.......... ....
777,
~
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PRESSURE, PSIA
0 500 1000 500 000 )OO 3000
0 ------
FI SURE 7
DEPTH -PRESSURE TRAVERSES
....... TUBING DIAMETER (S) - 1.995 INCHES
........... . ..
. ......
...
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.
FI GURE 9
DEPTH - PF'ESSLJRE TRAVERSES
TUBING DIAMETER (S) -- 1.995 INCHES
LIDUID RATE - 600 B/D
" iW
ATER CUT -0.650
..
..
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i i:! i,:: \'! :i:: li i
DI j
. .5 .... .... .
Resume"
For more than thirty years, Dr. R. Eugene Collins has been
second printing. His book has been translated into both Russian and
Japanese.
University of Houston and both his M.S. and Ph.D. in physics from
two years he also has been president of his own consulting firm,
Engineer in Rexas.