JPRS ID: 9254 USSR REPORT ENERGY

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• Content Type: REPORTS

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JPRS L/9254
15 August 1980 ~
- U SS R Re ~rt -
p
- ENERGY
(FOUO 15/80)
~
a ~
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JPRS L/9254
15 August 1980
- USSR REPORT
ENERGY
(FOUO 15/8C)
Moscow NEFTEPROMYSLOVOYE DELO in Russian I~o 4, 1980
CONTENTS
FUELS
Unique Featurea of Water Flooding of Wells in Samotlor Deposit
� (F.No Ma.richev, et al) ..:,,...o.oa 1
Experience ia Regulating Well Exploitation by Changing Filtration
Flows .
(A.U. Aytkuloy, et al) .............o....o................. 7
- Effective Use of G~?clic Method for Flooding Low Porosity Carbonate `
Reservoirs
(Ya. M. Zaydel', et al) .............o ..............a...... 11
Possibility for Ra3sing Oil, Gas Yield from Flooded Beds
(G.V. Klyarovskiy, et al) 16
Laboratory Investigatioas into Uae of Sludge To Raise Oil Output
(M.F. Svishchev, et al) 22
Increasing Fluid Extraction from Wells of Uzen' Oilfield
(N.A. Ma.lyshev, E.L. Leybin) ..........o 26
Asphaltic-Resinous Substances, Paraffin i.n Udmurtneft'
Association
- ~~~F''� L2ZOV~ Et 5~.~ �~~o~~~~~~~~~~~~o~~~~~~~~r~o~~~~e~~~~~� 32
- Removing Reagents of Solid Hydrocarbons Deposits, Asphaltic- -
Resinovs Substances -
(V.V. Sizaya, A.A. Geybovich) 36
_ - a - [III - USSR - 37 FOUO]
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DQVelopment of Productive Beds in the Presence of Bari~ Oxide
Deposits
(V.I. Veshchezerov) 42
Problems of Exploiting Oilfields in Complex Conditions
(V.P. Maksimov) 46 ~
Use of Ultrasonic Me.tnod To Deal With Salt Deposition at Sam~tlax
Oilfield
(V.V. Dryagin, et al) 52
.
Appearance of Iron Sulphides, Free Hydrogen Sulphide in Fluids
from Devonian Wells
(Ye. 0. Nedoboyeva) 57
Methods for Dehydrating, Desalinizing Oil from Georgian SSR
Oilfields
(R.K. Khabibulina) 64
_ Hydroc~y:lamic Characteristics ~f Basic Settlers Using a Radioactive
Isotope
(I.N. Yeremin, et al) 67
Use of Oil-Soluble Demulsifiers in Form of Petrol~um Solutions
(~e. V. Miroshnichenko, et al) 72
Oil Preparation at Southern Oilfields at Permskaya Oblast
(M.G. Isayev, L.M. Shipiguzov) 76
Conditions for Dehyaration of Highly Viscous Oil Using Hydrocarbon
Diluents
~M� Yll� Tarasov) �~~~~~~~~~~~.~~~~~~~o~~~~~~~~~~~~~~~~~~~� $2
- b - -
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FUELS
UDC 622.276.43
UNIQUE FEATURES OF WATER FLOODING OF WELIS IN SAMOTLUR DEPOSIT -
Moscow NEFTEPR~OMYSLOVOYE DELO in Russian No 4, 1980 pp 3-S
[Article by F. N. Marichev, V. G. Safin, and A. A. Gla~kov]
. [Text) Horizon AB4_5 is a layer of fine- and medium-grai.i:ed sandstone and
aleurolite interlayered by clays and clayey aleurolite. The porosity of
constituent rock varies fr~n 19.1 to 33.5 percent. Permeability attains
3,~a0 mD and more. Accor.ling to laboratory core analysis the mean perme-
ability in the horizontal and vertical directions is 1,072 and 670 mD
respectively. The la~ter indicates that the stratum has low anisotropy,
which promotes formation of conical encroachment sites at the oil wQlls.
Geological materials obtained in the course of operation nf. wells :n the
northeast part of horizon A84_5 were analyzed to determine the unique
features of the flooding of wells drilled in the bed's water-oil zone.
A plot consisting entirely of a water-oil deposit in the horizon was marked
out by an arbitrary boundary. This plot contained wells in the north part
of exploitation block IV and in bZocks V and VI, with a minor exception.
Bed pressure was not maintained in the isolated plot by pumping water into
injection wells. Cansequently flooding of the wells was the result of .
causes not associated with ,penetration of pwnped water through the bed.
Out of 159 wells ~hat were operati.ng in the isolated plot on 1 January 1977,
62 wells produced water-containing petrole~na.
1 '
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The table below shows the distribution of wells in terms of water concentra-
tion. ~ ~
Interval of Change Number of Wells
- in Well Product Water p~ 1 Jan 77 On 1 Jan 78
- Concentration, $
0-10 29 14
10-20 13 17
20-30 10 11
30-40 5 10
40-50 3 10 .
50-60 1 5
60-70 1 7
> 70 3 -
As we can see from the table, on 1 January 1977 84 percent of the wells
delivered a product with a water concentration up to 30 percent, and only
_ 3.2 percent of the wells delivered a product with a water concentration
over 50 percent. In 1977, 17 of the wells were flooded, and two were
inactive. Thus on 1 January 1978~ out of 77 flooded wells, 54.5 percent
had a product water concentration of up to 30 percent, and 17 wells (19.5
percent) had a water concentration over 50 percent.
The thicknesses of the beds between the initial level of the oil-water
intexface and the lower perforations of all flooded wells in the water-oil
. part of the horizon are compared below.
F
p-2 - 12-14 11
2-4 1 1 ~-16 7
4-6 1 : 6-18 i
6-8 7 18-20 7
8-10 12 >20 3
~ 10-12 22
A total of only 11.4 percent of the wells in the isolated plot have an
interface from 2 Lo 8 meters thick, that of 63.8 percent of the wells is
from 8 to 16 meters, and that of 24.8 percent of the wells is over 16 meters.
The distribution of the thickr,esses of the interfa~ce bed is similar for the .
flooded wells. Consequently the size of the interface bed between the
initial position of the oil-water interface and the lower well perforations
has no important association with the causes of the flood.ing of wells in the
water-oil part of horizon AB4-5�
. Generalization and analysis of geological material obtained from oil wells
permitted us to reveal, from the entire diversity of the floozling curves
describing several groups of wells with the most typical features, those
distinguished by the growth rate of water concentration:
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Group I: slow, uniform growth of water concentration in well product, up to
a comparatively low value (less than 40 percent as a rule) over a lengthy
period of time (39 wells).
Group ZI: high rate of well product encroachment by water for a short
period of time (within a single ~ear) (10 wells).
Group III: abrupt flooding of well product in a short period of time,
followed by stabilization ~f water concentration (7 wells).
Group IV: slow, uniform growth in water concentration, or presence of a
low water concentration maintained constant over a long period of time,
followed by swift encroachment of the product by water to a level of -
50-70 percent (3 wells).
' Group V: fluctuations in water concentration of well product, sometimes
- repeating themselves over a long period of time. These fluctuations
attain 40-50 percent (8 w~slls).
This division of wells on the basis of types of flooding is soaaewhat
arbitrary.
The largest group of wells (39) experienced the first type of flooding,
the water concentration growth rate befng 0.2-3 percent per month.
In the second and third types of flooding the gr~vth rate of product water
concentration varies within broad limits, from 5 to 25 percent per month
as a rule. The averaqes are 5.9 percent per mc *h for Grosp.II and 15 per- ,
cent per month for Group II?.
The flooding dynamics of wells dri].led izto the water-oil part of the
horizon obviously depend on many factors of both geological and technological
- nature. An analysis of the dependence between type of well flooding anC
the thickness of the interface bed, performed in relation to the different
groups of wells, reveals no dependencies at all. As we can see from Figure 1, "
the limits of the flooding rate for the first group of wells vary from 0.2 to _
3 percent per maath when the interface bed is from 7 to 23 meters thick.
_ The bed pressure in the isolated plot was 160-173 kg/cm2. Bottom hole
pressure was maintained at 128-164 kg/cm2; in this case the depression
created in the bed varies for individual wells within rather broad limits--
from 8-12 to 44 kg/ca~2. Unit depression (depression per meter of thickness
of the interface bed) varies from 1.3 to 6.4 kg/cm2�m.
The foll~wing dependencies were plotted: the tune of waterless petroleum
extraction and well flooding rate on depression and on unit depression, in
relation to the different well groups, and separately in relation to wells
with a monolithic interface bed and with fractionated, dense laminae.
- These dependencies showed that a close mutual correlation is not ob:.=erved
among the parameters studied.
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- u zs
.
2 m m , .
~ If � If
.
b ,o e", ~o � . . �
.
a � . � .
� . z f S
a ~
~ 0 1 4 0 f JO /l Zp
- (1) ~th~ udOod~enuA. %/M~c ( 2 ) -
Q a
Figure 1. Dependence of Well Flooding Rate on Bed Thickness
for Well Groups Experiencing Type I(a) and II, III, -
and V Flooding (b) _
Key:
l. Interface thickness, meters
2. Flooding rate, percent per month
Analysis of the flooded wells in the isolated plot does not permit t;nambigu-
ous establishment of a garticular influence upon the flooding rate by such
factors as relative dissection of the oil-bearing layer of the bed by the
perforation process, the rate of fluid extraction, and presence of clayey
interlayers, and their thickness. But altnost a.ll wells with a high flooding -
_ rate classified as types II, III, and V are located near the outer contour
of the oil-bearing bed.
On the other hand wells distingui5hed hy type I flooding and low growth of
product water concentration are located ix~ the center of the selected plot.
Curves describing change in the proportion of petroleum, fp, depEnding
on total fluid extracted were plotted for flooded wells (figures 2a,b, and 3).
As we car~ see from Figure 2, wells experiencing type I flooding exhibit a
larger petroleum extraction volume during the waterless period in comparison =
with wells experiencing type II, III, and V flooding.
Wells in groups II, III, and V exhibit a higher rate of decline of the pro-
portion of petroleum in the product, and lower fP values for the same volume
of fluid extracted from the wells, in coa~parison with wells in Group I.
The high rate of water encroachment of the well product cannot be explained
by a vertical rise in the water-oil interfacp, since only 10,000-20,000
tons of petroleum were extracted from wells in qroups II, zII, and IV during
the waterless period. This clearly dces not correspond to the amflunt of
petroleum extracted from between the initial position of the oil-water
interface and the perforation interval, assuming a vertical rise in the oil-
water interface. Second, at the existing distances between the oil-water
interface and the lower perforations (7-19 meters), the time of waterless
extraction dces not correspond to the tune of waterless well exploitation
. that would be consistent with a vertical rise in the oil-w~ter interface.
4
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QX. ~0~: M' �
0 ~ ~D 59 99 ;~7 ~10
~ '~~~r~ s ,
O:S _ ~~1
~ : - ~
~ ,
0,9 C
~ 2~,f~ 9x, my: ~.1
0 !00 .'97
,
_ Q9~ ~ ~ ~~~F` ~
u ~ : ?
- D. 9 ~ `'3
_ OIf~ . `
f�
Figure 2. Change in Proportion of Petroleum in Zbtal
VQlume of Liquid Extracted From Wells 3472 (1), -
3382 (2), 353~ (3), 3475 (4), 2927 (5),
- 3470 (6), 3559 (7), 3046 t8), 3465 (9),
3372 (10), 3473 (11), 3381 t12), 3747 (13),
3474 (14), 3358 (15), and 3044 (16) Experiencing
� 2~pe I Flooding
Key:
1. Qf, th~usands of m3
2. fP
r.~bic.e~~ (1) ' -
0 1~ 40 60
~ ~
. ~
1 ~
Q9 ~ 1 3 ~ _
~ ~
~ ~ 4 ~
0.8
1
_ S
Q7 6 .
./n
Fiqure 3. Change in Proportion of Petroleum in Total Fluid
Extracted From Wells 40Q5 (1), 4262 (2), 4061 (3),
3645 (4), 3365 (5), 3997 (6), 3754 (7j, and
4210 (8), Experiencing Type II, III, and V Flooding
Key:
1. Qf, thousands of m3 2.
_ 2� fp
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Flooding of wells located near the contour of the oil-bearing bed can be
explained by mixed penetration of water into wells; a cone of water is
drawn up concurrently with active invasion of surrounding water through _
- individual highly permeable interlayers.
Invasion of water throuqh non-watertight cement casings in wells of horizon
_ ~4-5 also obviously occurs. Wells with a non-watertight cement casing have
a short waterless period of exploitation, equal to 1-3 months, or they
" immediately begin producing water-containing products despite the fact that
_ their interface beds have a thickness of significant magnitude.
As an example there are grounds for suggesting that the cement casings of
wells 3559, 3643, 3645, 3928, 3932, 3997, 4179, 4210, 4262, and 4147 are
non-watertight.
The thickness of the interface bed of wells 3932, 3997, 4179, and 4262 is
within 7-9.5 meters, while that of wells 3559, 3643, 3645, 3928, 4210, and
4147 is 11-19 meters. Despite this, flooding set in after 2-3 months of
exploitation, while well 4147 began producing water from the moment it was
placed into operation. A unique feature can be noted in the dynamics of ~
well flooding: From tha moanent that water arises, its concentration remains
constant for a long period of exploitation, within 10-25 percent as a rule.
As an example the product water concentration of well 4147 remained within
10-14 percent throughout the entire 18 months of operation, while that of
well 3997 stayed at 25 per.cent (18 months).
Flooding dynamics of this nature may be explained by invasion of water f-
through cracks and channels in the cement collar situated beyond the casing.
This analysis of geological operating data and the flooding dynamics of
wells in the water-oil part of horizon AB4_5 shows that flooding of wells
resulting from invasion of water through a non-watertight cement collar is
not the principal cause for horizon AB4_5. Operation of only a few wells
with a non-watertiyht cement collar significantly influences the total
quantity of incidentally extracted water.
Thus if well repair and isolation operations are to be successful in the
development of the water-oil part of horizon AB4_5, effective ways to
control conical flooding of wells located in the central part of the '
- horizon must be employed. A method of selective isolation of flooded '
intercalations must be sought for wells experiencing mixed flooding through :
cones and by the channeling of surrounding water through individual inter- -
layers.
. �
COPYRIGHT: Vsesoyuznyy nauch.*~o-issledovatel'skiy institu~t organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980
- 11C~4
CSO: 8144/1367 -
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FUELS
UDC 622.276.43
EXPERIENCE IN PEGULATING WELL E7~IAITATION BY QiANGING FILTRATION FLOWS
Moscow NEFTEPROMYSLOVOYE DEIA in Russian No 4, 1980 6-7 -
[Article by A. U. Aytkulov, D. A. Goryunov, and Yu. P. Kislyakov]
- [Text] The Uzen' deposit is represented by a platform anticlinal fold of
almost latitudinal orientation. -
Zhe productive section of the oilfield is composed of Jurassic terrigenic
deposits. The revealed horizons are multilayered and heterogeneous. Not
counting the small intercalations, the most unifor~ beds number fram five
to fourteen. A typical feature of the beds is zonal change in thickness
and~permeability. Zones with higher (above-average) parameter values can be
distinguished. Zonality is expressed to the qreatest extent in horizon XIII.
Exploitation of the deposit involves contour flooding by means of raws of -
injection wells transvers~ to the fold's orientation.
The flooding process usually goes on continuously, not counting interruptions
for repairs, preventive maintenance, and analysis.
Contour flooding at the Uzen' deposit has elicited intense water encroachment
about the wells.
- To reveal the influence of flooding upon the resulting water concentration
of the petroleum extracted, on 24 February 1976 injection wells 63, 114,
1409, 1446, 1448, 1452, 1501, 1779, 1781, 1783, and 1782 in the southern
part of injection row VIa were shut down, and the pump~ung volume was in-
creased by more than 22 times in the northern part of injection raw VIa.
- The change in the pumping procedure was made in the most highly flooded
blccks of tkie deposit--5a and 7. _
6ubsequent research and analysis of the operational indicators of injecti~n
and production wells showed that injection i.nfluences not all wells of in-
jection row VIa, but basically only the production wells of the first ex-
ploitation raws. In all, there were 41 production wells within the zone of
= injection's active influence.
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In geological re~pects the zone of injection influence is mainly located
within the bed merging zone of horizon XIII, and insignificantly in the
layer merging zone of horizon 14 and in the bed separation zone of horizon
XIII (at the north side of the blocks).
Horizons 13 and 14 are multilayered. When the horizons are viewed in cross
sectivn~ both individual, relatively thick beds and intercalations from
0.2 to 0.4 meters thick can be distinguished. Th~ number of beds and _
intercalationsnumbers from 10 to 20 and more. The beds and intercalations
are separated by dense, impermeable carbonate argillites not inferior to
sandstone in thickness. For this reason the apparent thickness of sandy .
beds seen on a standard logging diagram, is significantly greater than
the effectivethickness, sometimes by more than a factor of two. For example ~
the apparent thickness of monolithic sandstone at well 1783 is 41 meters,
while the effective thickness is not more than 18 meters.
The effective thickne~s of horizons XIII + XIV in the merging zones is 26-40
meters, while in the separation zones it do~s not exceed 10 meters. Per-
meability in the merging zones attains 500-1,000 mD and more, while in
separation zones it does not exceed 150 mD.
Th~ zone of injection influence is complicated by a tectonic disturbance--
a low amplitude, enclosed fault that passes almost to injection row VIa.
Cessation of water injection for 291 days caused a drop in bed pressure
in the southexn part of blocks 6a and 7, down to th~ gas saturation pressure,
while bottom hole pressure dropped to 5-~0 percent below saturation pressure.
~enty-five we11s in the southern part reacted actively to injection; data
fran these wells were used to plot curves describing changes in mean daily
petroleum and fluid delivery of one well, the water concentration in the
extracted fluid, and reservoir and bot~tom hole pressure. A drop in reservoir
pressure caused an increase in the mean daily delivery of fluid and netroleum
by 42 and 26 percent respectively. The difference in the decrease in delivery
of fluid and petroleum can be explained by a 17 percent reduction in the can-
, centration of water in the extracted fluid. A significant decrease in bottom
hole pressure cause3 petroleum-saturated layers that had not produced pre-
viously and which locally possessed a low reservoir pressure i:o begin pro-
ducing. Reduction of reservoir pressure caused a decrease in the flow ~rom
flooded layers, and even its cessation. This is confirmed not only analytically
but also by data acquired by geophysical analysis meth~ds applied to production
wells 1417, 1441, 1468, 1809, 2293, and 2383.
Estimates made from a prediction of the mean daily de~ivery of fluid and
petroleum by one well and of the water concentration show that because water
injection was stopped, fluid delivery was 311,100 m~ low.
' If we assume that while the injection wells in the southern part of transverse
row VIa were shut down (for 291 da1s) all incidental water was extracted from
the flooded beds that had produced earlier (prior to cessation of injection)
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and whic:~ cc.ntinued to produce, the concentration of water in these beds
Wouid vary in accordance with ~he predicted dynamics, which is ~~tirely
possible. We can also determine the amount of petroleum extracted from
beds which had never groduced before. By dividing the actual amount of
water extracted incidentally in the 291 clays by the predicted propor~i~nate
concentration of water, we would get the estunated delivery of fluid from
pr~~viously producing (prior to cessation of injection) beds that continue
to produce. The difference between the total amount of fluid actually
_ extracted in the 291 days and the estimat~d delivery would equal the amount _
of petroleum extracted from beds which had never pxoduced before but which
began producing now. The computations show that in the case under examination
here, the petroleum yield would be 28,90d m3.
- At the same time that injection was halted in the southern part of transverse
row VIa, water injection was increased by a factor of 2.5 in five injection
wells in its northern part. The increase in injection was accompanied by
a rise in reservoir pressure and in the injection pressure of the wells =
from 90-~00 to 130-160 kg/cm2. Observations were ~taintained on 16 actively
reacting wells located mainly in the first production row. Data from these
wells were used to plot curves describing changes in the mean daily 3is-
charge of petrolewn and fluid by a single well, and the concentration of
water in the extracted fluid.
An increase in the volume of water injected and of the injection pressure
caused a 20 percent increase in fluid yield and a 28 percent increase in
petroleum yield. The difference in the i,icrease experienced by the yields
of fluid and petroleum can be explained by a 5 percent drop in the water
concentration (at the end of the period). The decrease in water concentra-
tion can be explained by the fact that a significant rise in injection
pressure caused beds and petroleum-saturated intercalations that had
never produced before to begin produ~ing. This conclusion is also con-
firmed by investigation of injection wells 1453, 1454, 1457, and 1784 with
deep-well flowmeters. A factor describing the extent to which the beds
were affected by injection in these wells rose by 64 percent in response to
a 67 percent increase in injection pressure. The values of these factors,
given in relation to bed thickness, and ~hP injection pressures are pre-
sented below.
Injection Pressure, Factor, Fractions
kg/cm2 of Units
80-100 0. 31
100-120 0.43 -
120-140 0.50
140-160 0.51 '
Computations based on prediction of the mean daily yield of fluid ~ron, a
sing].e well and of the concentration of water in it show that during the
period of ir,creasing injection (291 days) , as a result of grawth in the
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volume of water injected and in the injection pressure the additional
discharge of fluid was 49,100 m3, to include 40,200 m~ of petrol.eum.
If we assume that during the entxr~: injection period all incidental water
was extracted from flooded beds that had produced formerly (before in-
ject_~.~n was increased) and that its concentration in these beds changed
in accordance with the predicted dynamics, then, as in the previous case,
we can similarly compute the amount of petroleum extracted from beds that
previously }iad not been producing, after water injection is halted. The
computations show that it was 26,200 m3.
As we can see from these data, the effectiveness, in terms of ,petroleum, of
causing beds to produce by increasing injection pressure within them is
greater than it is in response to cessation of injection.
Thus to improve development of the reserves, it would be suitable to
periodically halt or significantly limit injection in highly flooded blocks
of the field, and increase it in the least-flooded block. This should raise
the effectiveness of contour flooding.
The same can be done with injection rows VIa and VIII. Injection would need
to be halted in the former, and it should be intensified in the latter--that
is, injection should be increased by not less than a factor of two.
- ~ ~i4, l~c 7-:lU^4 +
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980
11004
CSO: 8144/1367
_ ~
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FUELS
~
UDC 622.276.43
EFFECTIVE USE OF CYCLIC METHOD FOR FLOODING LOW POROSITY CARBONATE RESERVOIRS
Moscow NEFTEPROMYSLOVOYE DELO in Russian No 4, 1980 pp 8-IO
[Article by Ya. M. ~aydel`, B. I. Le~ti, and V. P. Rodionov]
[Textj Kashira-Podol'sk depots in the Arlanskoye oilfield are represented
by beds Pdg and Kshl, which are separated from one anot~er by a layer of
clayey lisnestoruu that extends throughout the entire oil foxmation. Each of
the beds contains twn intercalations that are separated into two or three
laminae. Dense, slightly fractured limestone with a peaaeability of 1 mD
and a porosity of 3 percent serves as bridqes between the intercalations.
Exploitation of the Rashira-Podol�sk deposxts.by displacinq the petrole~
with water demons~r-3ted the effectiveness of a c~clic flooding method.
As water was pumped in, pressure at the heads of the injection wells
changes from 90 to 150 kg/cm2. An analysis of experimental water injection
in the Kashira-Podol'sk deposit establrshed that the optiiaum injection
pressure at the bottom hole of the injection wells is 190 kg/cm~.. A r.ise
_ in well flooding due to opening of cracks in the bed is observed con~urrently
with g~owth in fluid yields i:n response to a further rise in injection pr.essure.
A temporary reduction of in7ection pressure gaing as far as cessation of in-
jection causes a decline in water concentration and ~ield of fTuid, with
petroleum discharge remaining almast conatant. A variable water injection
cycle has a favorable effect upon deve�lopmen~ of carbonate reservoirs.
The Kashira-Podol'sk deposits satisfy most requi:rements imposed on successful
application of cyclic fToodinq. They are typified by presence of natural
block disintegration, which reveals itself to the greatest degree in response
to crea~tion of high pressure gradients; this pemu.ts the assumption that a
hydrodynamic relationship exists between different.laminae of ~h~ bed.
Creat.ion of high iaje~ctiom pressure for a short ~ime creates a sufficient
~eser.ve of resexvoir pressure.
~everal exploitation variants differing from one another by various para-
meter.s cha:racterizing cyclic action were examined in order to reveal the
effectiveness of the cyclic flooding method and to.establish the optimum
conciitions for using this method.
11 -
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- The computations were based on a complete hydrodyna~ic model of the bed
making it possible t~ account for biphasal flow and for the entire complex
of hydrodynamic, capillary, gravitational, and elastic forces governing
" filtration flow. When the appropriate raw data are available, this model
can account for hysteresis of relative phasal permeabilities and functions
of capillary pressure. The finite-difference method was used to solve the
system of equations for biphasal filtration, with a consideration for the _
compressibility of the fluid and rock.
The element of symmetry of a single-row system of wells was chosen as the
element of computation. The distance bewteen rows of r*ells and between
wells in a row was assumed to be 400 meters. The viscosity of the bed's
petroleum was 10 cP, and that of injected water was 1 cP. Bottom hole
pressure in injection and production wells was adopted equal to 190 and
30 kg/cm2 respectively.
The heterogeneity of the beds was modeled by introducing, as given, three
permeable laminae in each intercalation, and bridges separating the inter-
calations. In this case the set of laminar permeabilities corresponded to
M. M. Sattarov's distribution at a/kp = 0.5. Next the indicators for
exploitation of the two beds were sumned.
ChangPs in permeability of the laminae depending on injection pressure were
considered with the formula
x=KO�expa(P-Po), (11
where kp--permeability at initial bed pressure Pp; a--permeabili~y change
factor; P--fluid filtration pressure.
The anisotropy factor, which characterizes the relationship between vertical
permeability and strike permeability, was adopted equal to 0.1.
Each complete cycle of action upon the oil formation consists of two periods.
In the first, the given bottom ho].e pressures are maintained at the bottom
holes of the injection and production wells. In the second period, water
injection ceases, while fluid continues to be extracted from the production
wells at the given bottom hole pressure.
Variants employing cyclic action were compared with the case of continuous
~ water injection. In this case i.t was assumed, as a condition, that maximum
injection pressure with cyclic flooding matches the corresponding pressure
accompanying continuous water injection, and that it is 190 kg/cm2. This
is associated with the existing upper limit upon injection pressure, and it
does not elicit additional difficulty when this method is applied in the
field.
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We first studied the cyclic flooding variants characterized by equal half-
cycles of falling and rising bed pressure. In this case fi,he cycle duration
varied from 30 to 60 days. Computations showed that change in the period
of sy~netrical cycles within the indicated range has practically no eftect
on the increment of petroleum yi~ld (this is true in relation to a 95 per-
- cent water concentration), which is about 4 percen~t. Therefore we devoted
our principal attention to studying the influence of nonsymmetrical cycles
upon the effectiveness of pulsed action. We studied several variants of
cyclic flooding, in which the ratio between the fall time and the rise
time of bed pressure varied from 0.5 to 4. The complete period of the
cycle in these variants is 60 days.
The rate of petroleum extraction was found to be lower in these variants
than with continuous water injection, and the development time was greater.
As a decreasES, the extraction rates increase. This can obviously be
explained by the fact that the average filtration rate in the bed decreases
due to temporary cessation of injection. Because of this, the resulting
effect may be associated with two factors. The first is concerned with
- change in the relationship between gravitational and hydrodynamic forces -
due to a decrease in filtration rate relative to the basal variant, and the
second is associated with intensification of fluid flow between laminae due
to the action of elastic forces in the cyclic action situation. However,
computations based on the same av~rage filtration rate used in the variant
- with a= 2 but with a constant pressure gradient showed that the first factor
is insignificant in these conditions. The change in petroleum yield re-
sulting from the rate decline was about 0.6 percent, which is about seven
times less than the effect ok~served with cyclic water injection (Figure 1,
~ = 2? ~n = 4 percent) .
r d~~ t
rro .
9s 6
/
M
6S
?
- JS D
' J ? 3 y ,Z
Figure 1. Influence of the Ratio Between the Injection
Pressure Rise Time and the Time of Decreasing
~ on the Increment in Petroleuu~ Yield, An '
(as of the Moment of 95 Percent Water Saturation
~d Development Time)
The nature of the dependence of the petroleum yield increment ~n on the
ratio between the fall time and rise time of bed pressure Jl is not
monotonic, and it indicates that both half-cycles of the cycles have an
13
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influence upon the effectiveness of cyclic action (see Figure 1, curves 1,2).
When ~ is close to zero--that is, when the halr-cycle of falling pressure, _
tf, is much smaller than the half�-cycle of rising pressure, tr, in this case
the indicators of the process are found to be clo~e to the corresponding
indicators obtained in the continuous flooding situation. We also observe
a decrease in the effectiveness of cyclic action at high J1 values. This
can be explained by the fact that when the rise time of bed pressure is
much shorter than the fall time, during the rising half-cycle the bed `
pressure does not have a chance to recover completely, which exhausts the
bed's elastic energy reserve and reduces the intensity of fluid flow between
laminae in subsequent cycles as well.
As we can see from Figure 1, the dependence of development time upon a is close
to linear, while the petroleum yield is nonlinear ~n nature. In this case
maximum change in the petroleum yield factor is observed at less than
a= 0.5. As a increases further, from 1 to 3, the petroleum yield increases -
by only 0.5 percent, while the developmenttime becom~s 30 years longer. Thus
the optimum value of a lies in the interval from 0 to 0.5.
Because the rate of petroleum extraction declines in the initial period of
cyclic flooding in comparison with the rate seen with continuous injection,
variants in which this method is applied not at the beginning of the develop-
ment time were examined. It was found in this case that the longer the
method's application is postponed, the lower is the increment in petroleum
yield. In this case the nature of the dependence exi$ting between An and
a persists.
8~ � ;
;
y P.V
1 i-
7' -
s ~ i
I
p qT i
~
~ q~ ~ ;
~
r
0 0
0,
~ 0,10 QIf 0~0 2 ~
Figure 2. Dependence of the Proportion of Petroleum, fn, ~
in Well Discharge and ~he Cumulative Water-Oil ~
Factor on Petroleum Yield: 1,2--continuous I
water injection; 1',2',--cyclic water injection
with 80 percent water concentration ;
Cczmputations showed that for the conditions exatnined here, it would be most
suitahle to use the cyclic flooding method, attaining ari 80 percent water
concentration in the petroleum bed, and 0.5 for the ratio between the fall
time of bed pressure and the rise time. In this variant the petroleum yield _
- 14
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was 0.327 in relation to 95 percent water concentration, and the developmen~t
time is 42 years. In the case of continous injection, the petroleum yield `
is 0.3 in relation to 95 percent water concentration, and the development time
is 35 years. We can see from Figure 2 that when cyclic flooding is involved,
" not only does the petroleum yield increase, rut also the water-oil factor
decreases, while the proportion of petroleum in the well discharge rises.
Introduction of the cyclic method is usually made difficult due to the
need for halting production for a long period of time at existing facilities;
hence the low use factor for the ~ower output capacities. Moreover when
water i�njection is halted in winter, the water lines and injection well -
manifolds freeze.
Cambining the method of separate injection of water into two productive
beds (in the upper bed through the intertubular space, and in the lower
bed through the pump and compressor pipes -based on cyclic flooding is
suqgested as a way to exclude these phenomena. At a ~ 1, separate injection -
of water into the beds makes it possible to achieve a continuous flow of
water in the inlets, while selection of the appropriate flow regulators at
the heads of the injection wells would pennit establistunent of the appro-
priate water delivery rate.
i. ,'_GG t I
COPYRIC~iT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980
11004 l�
CSO: 8144/1367
15
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UDC 622.276.43+622.276.6
POSSIBILITY FOR RAISING OIL, GAS YIEI~D FROM FLOODED BEDS
Nbscow NEFTEPROMYS7AVOYE D~ELO in Russian No 4, 1980 pp ~0-13
[Article by G. V. Klyarovskiy, R. V. Mysevich, and B. G. Parakhin]
[Text] Many oil formations have a complex geological structure, a variable
lithologic and facial composition, and rock with poor reservoir properties.
_ In a number of cases, bec:ause of the absence of active perimeter water and
the equality of the initial saturation pressure and the bed pressure, use
of dissolved gas is a natural way to work such formations. ~
The initially high yields of petroleum (up to 250 tons per day) fram low
porosity rock strata have been the product of exploitation of the wells at
high bed pressure and low viscosity of petroleum in the bed, which does not
exceed 1 cP at a gas saturation ratio qreater than 200 m3/m3.
Hydrodynami.c computations and results of the first years of development of
the examined formations showed that under natural conditions, the oil ex-
traction factor would attai.n 0.12 in the best case. In such formations,
therefore, following their initial development with the use of dissolved
- qas, various systems have been introduced to maintain bed pressure by means
of water injection.
However, an analysis of the state of such developments would show that when
petroleum delivery decreases to an amount that would make the injection _
system of operation unprofitable, the petroleum output would be relatively
low even if additional flooding sites are introduced, the network of in-
jection wells is made more dense, and if various technical geological
measures are implemented. Therefore it becomes important to seek ways to
i.ncrease the petroleum output. One such way might be to continue to exploit
almost completely flooded formations with dissolved gas after cessation of
- water injection, since they would maintain a high bed pressure.
= In each case, the effectiven�~ss of converting from a pressure system to a
depletion system would depend on the geological-operational factors, the ~
_ bedding properties of the fluids saturating the reservoir, the residual oil i
and gas saturation of the beds, and the development conditions. In order
i
16 ~
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to compute indicators for development of formations with dissolved gas, we
will derive, for the conditions examined here, the dependence between bed
pressure declir,e and fluid discharge (and cY.ange in the bed's oil and w�aeer -
- saturation). In this case the balance equations for the yields of oil
qH, gas qr, and water qB would take the foxin
9$=-S3� - r P" l (1~
dt L ~(p) J :
Q~=-~' dt P� P'~ ~p~
-S2� d L ~(P) ~S~p~ J' 4 ~2~
9i~-SZ ~ps~
dt (3j.
_ where S2--fortnation's pore space voZt2me; pH, pB--oil and water saturation of
the bed respectively; S(P) and S(P)--volumetric coefficient and qas con-
centratio!: of bed oil depending on pressure (P); t~-formation exploitation
time. -
Separating the left and right parts of equations (2) and (3) correspondingly
into the left and right parts oF equation (1) and equating the factors on
the right to the value of the gas and water factors (4), (5), following
simple transformations we get differeMtial equations (6) and (7):
r'r=p Fr . ��~p~ �~~P)-t-S~P): ~4)
Fa �r(P1
i
F' � ~ (P) � �`~p~ . (5)
r~ Fs �s~p)
where Fr, FH, FB--phasal permeability for qas, oil, and water respectively
in a triphasal system; uH(P), ur(P)r ~ig(P)--viscosity of bed oil, gas, and
water depend~.ng on pressure.
Fr F~"(p) F~ 1+~(p) .
dP8 ~(f') ~ p~~~~p~ ~ Fa ~ Nr(p) + Fs ~ �a(p) ~ +S ~p~ PB P'
dP - P, r Fr , F~~~P) +Fs , �s~p) 1 ~ ' ~6)
L FH �r(p) fa �~~p) +1 ~ .
dP' = F' , �8 ~p~ ~ P~~_ PY� ~ ~p) .
- dP F~ �,~p~ ' [dp p~
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As a result of joint solution of differential equations (6) and (7) we can
determine change in the oil and water satura~ion of the beds dependinq on
_ bed pressure decline, This system of equations is solved by one of the
methods of numerical integration.
Let us make the hydrodynamfc computations for a uniform formation possesaing
the properties typical of bed fluids. Let us assume that in the initial
period the formation was worked with dissolved gas. Owing to this, bed
pressure dropped to 0.65 of the initial pressure. Subsequent d~evelopment
involved flooding at a constant bed pressure equal to 210 kg/cm2.
- When the gasified fluid is displaced by water, part of the free gas remains
immobile and causes residual gas saturation. In the formation under
examination here, after water injection was started, movement of the gas
phase ceased very quickly. In this case residual g~s saturation was close
to the initial saturation level resulting from development of the formation
with dissolved gas. The mean residual gas saturation for the formation was
- 0.109,
To determine the dependence of developcnent indicators upon residual petro-
leum reserves, we subjected the first and second variants to hydrodynamic
computations, using initial oil-water and gas saturation levels equal
respectively to 0.215, 0.616, 0.109, and 0.385, 0.506, 0.109. ~
The influence of residual gas saturation upon ~he effectiveness with which
the formation was developed was evaluated on the basis of the co~nputations
for the third and fourth variants, for which it was hypothesized that as
gasified petroleum was displaced by water, all free gas that had foxmed in
the initial period of development was displaced from the bed. The initial
oil and water saturation levels are equal to 0.324 and 0.676 for the third
variant and 0.494 and 0.506 for the fourth variant respectively.
In order to assess the influence of preliminary depletion of the formation
upon the total petroleum output, we perform computations for a fifth
variant, in which displacement beqins at an initial bed pressure of 315
kg/cm2, without initial working of the formation with dissolved gas. The
fannation is subsequently depleted with a free gas phase absent from the
bed. For this variant the initial oil and water gas safiuration levels are
0.494 and 0.506 respectively. The raw data used in the computations are
presented below.
Volume, millions m3 '
- Pore space, St 118 _
Bound water, p w 0.19
Bed water viscosity, uH, cP 1
Figure 1 shows the physical characteristics of the bed's petroleum. The
phasal permeabilities for gas Fr, oil FH, and water FB were determined using
the formulas for a triphasal system.
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The ntunerical metkiod was used to integrate differential equation system (6)
- and (7). ThP program was wri~ten and debugged in Fortran IV algorithmic
language. The comput:.tions were made with a computer, and the results are
_ presented in Figure 2.
, 1.f a00 Jb 3
:
Q ~
a -
E ~
g = ~ ~
~ 1 L1 1
~ '
- ~`r ~ S
v ~ J~M
.a~.s~~~~~ ~ s.
~�n
� 2
t
v /
p ~ ~////r/
(i~ ~0 (2l~(3~(~~ ~ ~m n~ nn ~a ~ x
Asatmod~r daOwrnu~ o. Rac/t++ ( 5)
Fiqure 1. Dependence of Oil Voltunetric Coefficient SH,
- Gas Concentration of Oil S, Ratio of Oil and Gas
Viscosities uH/�r? ~d Oil Viscosity uH on Bed
Pressure P
Key:
1. Oil voltunetric coefficient 4. Oil viscosity
2. Oil gas concentration 5. Bed pressure
3. Ratio of oil and gas viscosities
The developmental indicators for the formation were determined dam to the
mini.mum bed pressure, equal to 50 kg/cm2, at which exploitation of the we11s
is still possible; a comparison of the computation results for the 3ifferent
variants is presented in the table below.
The hydrodynamic studies confirm the possibility for increasing the final
oil ouput for flooded formations by switching them to a depletion system ~
of development after the pressure method of development becomes unprofitable.
As we can see from the table, the increment in oil output resulting from
development of the formation with dissolved qas f'ollowing cessation of
flooding is 0.9-13.4 percent in the examined variants, and that it increases
as the residual petroleum reserves increase.
~ Presence of free gas in the bed at the beginning of the period of secondary
depletion causes a decrease in the amount of oil extracted additionally
_ (variants I, II and III, IV). The suitability of preliminary depletion of .
the formation may be judged from a comparison of the oil output for varxants ~
II and V. The data presented here show that the payoff represented by an
increase in the additional oil yield with depletion occurring toward the end
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I
a~ nam n .
v .
0.4 l~II ~M
q
_
E L OI ~
0 0
= 0.J K8!
~ ~
- z ~ Ar
F ; �
= o ~ a
~1~02 NI _
~r
0.1
~ 15B ~7 !!9 4A7 1D 0
(3 ~ /Inacmo0cr daQarnur P, ar%nt
Figure 2. Dependence of Bed Pressure P, Oil Saturation
pH, and Gas Factor I'~ in a Triphasal System
Subjected to Depletion: I, II, III, IV, V--
variants of development
Key:
1. Oil saturation level 3. Bed pressure
2. Gas factor
1
in the fifth variant is smaller than the payoff enjoyed due to reduction
of bed pressure in the principal period--the final oil output in the
_ fifth variant is 1.7 percent lower than in the second.
The maximum additional oil yield due to depletion developznent of the
formation follawing cessation of water injection was enjoy~d in the fourth :
variant, but in comparison with the other variants the oil output remained
the lowest. It follows from this that for the development method examined;
here, the greatest volume of oil extraction.should occur in the principal
period of the formation's exploitation. .
As we can see from the table, the final gas output is practically the same
for all variants (81-85.6 percent). Differences in the conditions offered .
~ by the variants for dev~elopment have a significant effect upon changes
occurring in the gas factor (see Figure 2), which results in equal gas
yield ratios.
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~i~ t~L
BapNaxr~
IIoKa3atenx I ( II ~ III I IV I V
~ 3 ~ He~reot,�aaa e o:-
xaeHaA nepeon paspa-
borxx. ?0,5 47,1 53,5 32.2 39,1
~ 4 ~ ~A a~rKe H~
eaia
we acrotneHxs, Mae. x' 0,6 :,9 3,3 8,I 6,8
( 5 ) Hcnoltsaoaax~e oc-
razoax~x 3aaaco'
~tx, �b . 3,2 9,0 12.1 19,8 18,5
~~Koxevxas He~reot-
- AaqA, . . 71.4 51,9 61,0 4~,6 502
~~~flpeporr xe~s~araa-
� � � � - 0,9 4,8 3.5 13,4 1 I ,1
~g ~ Ha~onbsosaxee aa-
nscos ra3a a xaos-
aoA nepqoA pa3pa6or-
�b . 59.0 43, I 69.7 53.8 39.0
( ~,~o6bcaa ra3a npe
pa3pa6orxe ea pexta- -
eee xrro~ueaxA, u.1H. x� 3446 4912 2027 3571 5436
(10) Ncnon~oaaHae oc- _
Tarovx~x aartaco4 ra-
3a, 64,9 66,7 51,6 59,6 68.8
(11) Hcnon~oHaese aa-
nacoe raaa, 85,6 81.0 35,3 81.3 S1.0
(12 ) IIpRpoc'r ra3oor~a.
ais. . 26.6 37,9 15,6 27,5 42,0 ~
~Y =
1. Indicators
2. Variants
3. Oil output for principal period of development, ~
4. Oil yield with depletion development, millions m3
5. Utilization of residual oil reserves, $
6. Finil oil output,$
7. Increment in oil output, ~
8. Utilization of gas reserves in principal period of development, $
9. Gas yield with depletion development, millions m3
10. Utilization of residual qas reserves, $
11. Utilization of gas reserves, $
12. Increment in gas output, $
Thus development of the flooded beds first with dissolved gas and then by
water flooding promotes a relatively high oil output even when such beds are
exploited by a secondary depletion method.
The time a bed is exploited using water injection must be relatively long,
- so that a large quantity of petroleum could be extracted i.n the principal -
period, and free gas could be displaced from the bed, thus increasing the
effectiveness of exploitation at the time of secondary depletion.
COPYRIGHT: Vsesoyuznyy nauchno-is~ledovatel'skiy institut organizatsii, -
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980 21
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~
FUELS
UDC 622.276.6 ~
LABORATORY INVESTIGATIONS INTO USE OF SLUDGE TO RAISE OIL OUTPUT
Moscow NEFTEPROMYSLOVOYE DEIA in Russian No 4,.1980 pp 13-15
[Article by M. F. Svishchev, G. B. Turbina, M. I. Pyat;'cov, A. S. Kasov, and
Ye. A. Mikhaylova]
[Text] The wastes of industrial enterprises have been used successfully in
_ petroleum industry. Thus, sludqe has been used to raise the intake
capacity of injection wells at the Tverskoye and Yakushkinskoye oilfields
in Kuybyshevskaya Oblast. The Volgograd Scientific Research and Planning
Institute of Petroleum Industry conducted res~arch on the possibility of
using sludge from the synthetic fatty acid shop of an oil refining combine
as an oil displacing agent. The results of the experiment showed that under
certain physicogeological conditions, injection of s~udge into a bed may
significantly raise the oil output and reduce ths formation development time.
Sludge obtained as a waste product from oil additive production at the
Omsk oil refinery was also subjected to research by the Siberian Scientific
Research Institute of Petroletun Industry in order to broaden the r~aw material
base for using physicochemical methods to raise the oil output of oilfields
in West Siberia. When MSCr8 distillate oil is sulfonated by sulfur anhydride,
we get oil-soluble sulfonic acid, which forms the additive. Part of the pro-
ducts resulting from sulfonation of condensed aromatic hydrocarbons and the
_ resinification and oxidation products settle as sludge.
Under normal conditinns sludge is a thick asphalt-like mass of d~rk color with
the sharp odor of suifur anhydride. It contains about 10 percent free
sulfuric acid, 50-60 percent organic sulfonic acids, resinification and oxi-
dation products (30-40 percent), and water.
Aqueous sludge solutions possess surfactant properties, a product of the
high concentration of sulfonic acids.
Sludge dissolves well in fresh water to form transparent solutions at a ~
concentration not exceeding 0.5 percent. In mineraliz~d water, all sludge
solutions are turbid; in this case when the sludqe concentration is greater
than 0.5 percent, and especially when the mixture is heated, the water and
hydrocarbon fractions separate into layers. Formation of a precipitate is
also pos~ible. 22
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Various reagents usually employed to stabilize colloidal and mycellar systems
were test~d as a means for preventing stratification and precipitation in
response to interaction with mineralized water: low molecular weight alco-
hols, nonionogenic surfactants, and caustic soda. Low molecular weiqht
fatty alcohols did not produce a positive impaet. When a nonionogenic
surfactant such as OKM (oxyethylated tallow oil) is added, stabilization of
a 0.05 percent sludge solution was observed at a sludge:OKM ratio of 1:3.
The best results were achieved with caustic soda. Clarification af solutions
occurs at sludge:NaOH ratios as low as 5:1. Use of caustic soda or OKM
surfactant together with sludge produces a synergetic effect. The surface
tension of different solutions bounded by purified kerosene at 20�C is
presented below.
Surface ~'ension at
Solution Boundary of Purified
Kerosene, mN/m
0.05$ sludge in distilled water 16
0.01 NaOH in distilled water 18 -
0.15$ OKM in distilled water 12
0.05$ sludge + 0.01~ NaOH in Cenomanian water 13
0.05~ sludge + 0.15$ OKM in Cenomanian wat~r 10
Causti.c soda interacts to neutralize sludge, forming sodium sulfonate out
. of the sulfonic acids. In this case the medium's pH increases from 3.03 -
(for a 0.05 percent sludge solutio~.) to 8.2 (0.05 percent sludge + 0.01 per-
cent NaOH)--that i.s, neutralized sludge having a weakly alkaline reaction
forms.
From the standpoint of solubility, surfactant properties, and process
economy, it would be best to neutralize sludge with caustic soda at a
sludge:NaOH ratio of 5:1. When sludge solutions are stabilized by OKM,
15 times more of it is required than caustic soda.
Therefore 0.06 percent neutralized sladge (0.05 percent sludge + 0.01 ~er-
- cent NaOH) was used to study oil displacing capability. This solution's
dynamic adsorption was determined beforehand.
The neutralized sludge solution was filtered through a core sample from bed
P of the Trekhozernoye oilfield; in this case the reagent's adsorption was
- 8.C15�10-4 kg/kg. According to the results, adsorption was 1.1�10'4 and
3.9�10-4 kg/kg for 1 and 5 percent sludge solutions respectively. Published
data offer the following values for adsorption af anionic surfactants: for
_ sodium sulfonate--2.33�10'4-2.48�10'4 kg/kg, for sodium alkylsulfate--
4.77�10"'~ kgjxg--that is, it is comparable to the adsorption value given
for sludge from the Omsk petroleum refining combine.
Sludge displacement experiments were also performed with oil samples from
the Vatinskoye, Ust'-Balykskoye, Zapadno-Surgutskoye, and Mamontovskoye
' oilfields.
23
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. Ko~ nut?-
~ eHT earccHe-
(1) (2~ (3) (4) ~5~ H1fA np~i ~a-
Merropo~c� o, ~ xa4tce _
neaxe fIaacr ~ IlA6 a
d x~ (7) S.~ ~(8)
~
C 1~+ ~ F~- C'~ m
F o `1a C �m aC
()~BBTNHqLO! SB~ 88 HKI' (19 0,06 0,686 0,732
~ As~-~ 70 0,06 0,646 0,659
. AB,_~ ~p ~ 0,06 0,633 0,655
- Ycrs�5andx-
- (lO~Kce I6C~_~I 67 I HK!' I 0,06 I0,673 I0,738
- (11~anaAxo� ~_zl gp HKC I 0,06 I0,656I0,692
Cy~ryrcKOe 6C1_a 60 0,06 0,610 O,f:34
6C~o 6? 0,06 0,645 0,690
nz$xo~TOH� ~s Hxr o,os ,o,s~s o,sr
(12kKce I&Cio ~ 76 I I 0,06 I0,693 (0,742
(13 )Tpexo3epxce I Il 30 I OII � I 0 I I I
( p) 0,05 0 480 0 507
Terepeso-
(14~'loprbr~b� I
~~x~ 17 I 78 OfI�10 I 0,05 I0,640 10,660
(15~PaH,�qx�
ce I BCe ~ 8.3 IOTt�10 I 0,05 IG,659 (0.678
SC~ 60 OI7�10 0,05 0,487 0,531 ~
3anaAxo� EC~o 30 OTI�10 0,05 0,490 0,540
(ll~Yp~'~'T~oe sC, 70 OKM 0,05 0,550 0,620
SC~ 60 OIU1 0,05 0,487 0,550
SC~-a 60 OKM~- 0,10 0,620 0.661
~-TH~
rtb-&anbttt� &Cio ~0 OKM 0,05 0,416 0,48t
(10 xce ~ SC~o 30 IOfI�10 I 0,03 0,416 I0,~48
1 BC~~ 30 OI7� 10 0,05 0,525 l~,6UC
Cesepo�IIo� _
(16 cxoe SBc I 30 IOTi�10 I 0,05 I0.573 I0,579
~17,CtMOT110P� A~_3 30 OTI�10 0,05 0,575 0,592
cxoe ABs_y 30 Oii�IO 0,05 0,622 0,637
SBs 30 OfI� 10 0,05 0,424 0,427
SBe 3d OR� 10 0,05 0,669 0,669
SBa 30 OT1�10 0,05 0,538 Q,346
6$s ~ 73 ;~~icont2 0,05 0,617 0,651
BaH44tT ~
~l~~oerrcxoe I AB 50 ~INCOn- 0,05 0,702 0,720
?
sae 4411
so on-io I o,os Io,7� ~0,814 .
Key ;
1. Deposit 7. Water
2. Bed 8. Surfactan~. solutions after water
3. Experiment temperature, �C 9. Vatinskoye
- 4. Surfactant 10. Ust'-Balykskoye
5, Surfactant concentration, ~ 11. Zapadno-Surgutskoye
6. Displacement factor with 12. Mamontovskoye
- injection of: 13. Trekhozernoye
(Key continued on following page] _
24 -
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14. Teterevo-Mortym'inskoye 19. Neutralized sludge _
15. Pravdinskoye 20. OP-10
16. Severo-Pokurskoye 21. Trisodium phosphate
17. Samotlorskoye 22. Disolvan
18. Sovetskoye
= Instead of oil from the beds, the research was formied on degasified oil
_ mixed with kerosene in a proportion resulting in viscosity identical to that
- of bed oil at a temperature close to that of the bed. After cessation of
the oil's displacement by water (Cenomanian, from the Vakh River, or a
model of bed water), sludge solutian was injected, which subsequently o
filtered through until the maximum water concentration of the extracted
product was reached. From 2.04 to 11.02 pore volume equivalents of sludqe ~
were injected through porous mediums.
An analysis of the experimental results (see table) showed that in all `
experiments, continuation of sludge injection after water resulted in
additional displacement of from 1.3 to 6.5 percent oil.
The best effec~ was achieved for beds BS1_3 of the Ust'-Balykskoye (6.5
percent) and BSlp of the Mamontovskoye (4 and 4.9 percent) oilfields, and
the least was observed for bed AV1-2 of the Vatinskoye oilfield (1.3 and
2.2~percent). The reason for the difference in the effectiveness of dis-
placement of oil by sludge solution in these experiments is apparently
associated with individual properties of the oils and of the reservoir rock
in the studied nilfields. The oil displacing capability of neutralized
sludye solu~ion is not inferior to that of aqueous solutions of surfactants
such as OP-10, OKM, disolvan 4411, and trisodium phosghate.
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980
- 11004
CSO: 8144/1367
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FUELS
UDC 622.276
INCREASING FLUID EXTRACTION FROM WELLS OF UZEN~ OILFIEI.D
Nbscow NEFTEPROMYSLOVOYE DELO in Russian No 4, ],980 pp 15-18
[Article by N. A. Malyshev and E. L. Leybin]
[Text] Exploitation data from 190 wells falling within the following groups
were examined to determine the results of introducing forced fluid extraction
for a 9-month period of e~ploitation: 1) 103 deep shaft wells converted from
56- to 68-mm pumps; 2) 20 deep shaft wells converted from 68- to 93-mm ptunps;
3) 67 gas lift wells converted fram 63.5- to 76.2-IIUn pump and compressor
pipes. �
In order to reveal the optimum conditions for increasing fluid extraction
from the wells, the influence of geological and technological factors upon
the magnitude and duration of the effect, as related to oil recovery, was
analyzed. -
An investigation was made of the influence exerted by intensification of
fluid extraction, Rf (ratio between the mean fluid yield for the forced ~
extraction period under analysis, qf, and the initial fluid yield, qfp,
prior to implementation of the geological and the technologica? measures), '
and the initial values of fluid water concentration, Bp, and fluid yield,
gfp. The geological factors studied included the influence of variations ,
in the cross-sectional permeability of the well (the ratio of the maximum
permeability of the i-th bed, Xm~2, to the average permeability of the
' cross section, Ifave), variations in bed thickness (the ratio of the maxi-
mum effective thickness of the 2-th bed, h~ef2, to the total effective ~
thickness, Ehef, of the exploited oilfield), in relation to the absolute
value of maximum effective thickness of the i-th bed in the exploi~ed oil- ~
field and the specific degree of depletion ~f the reserves, a. ;
The obtained dependencies of relative growth in oil output Ifo and the ~
duration of the effect to on the degree of fluid extraction intensification
~f showed that these indicators do reveal distinct dependencies approaching :
linear. This attests to presence of a reserve for increasing flui.d ex-
traction from the wells.
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Investigation of the dependence of parameter Kf on the initial fluid yield
showed that for the 113 deep shaft wells (92 percent), the fluid yield of
10-50 tons per day was increased in the period of forced extraction by more
than 1.4 times. This is what cau~ed stable growth in petroleum output by
an average of 4.6-4.9 tons per day per wel].. At the same time the short-term
effect upon petroleum output for 51 gas lift wells (76.1 percent) with fluid
- yields of more than 100 tons per day can be explained by attainment of a
sufficient degree of fluid extraction intensification (for this group of
wells, Kf averaged 1.18).
_ The main cause of the low effectiveness o� attempts at forcing fluid ex-
traction lies in that the possibilities for reducing bottom hole pressure
for a particulax category of wells down to a projected level is limited due -
to the insufficient lift of deep-well pumps, and the low gas pressure
employed in gas lift recovery. In order to insure stable fluid extraction
at a volume greater than 150-200 tons per day fran highly flooded wells
(Bp> 5a~�percent), we would have to solve the problem of using highly pro-
ductive underground equipment, and raise gas pressure in the gas lift system.
Otherwise forcing fluid extraction from this category of wells would not
lead to positive results.
Analysis of the dependencies presented in Figure 1 would show that while the
degree of forcing, K, is identical for wells with different initial water
concentrations, Bp, ~he increase in oii output, Ko, differs. In this case
the lower relative increments in oil yield are typical of wells s-~bjected
to greater flooding--that is, when wells with a hiqh water concentration
are subjected to forcing, more-intense fluid extraction should be planned.
Using the obtained dependencies, it would seam possi.hle to establish the
lower limiting values of K*f, producing an increment in oil yield of KQ > 1,
for wells exhibiting different degrees of flooding. As we could see from
- Figure 1, for wells with Bp 1.2-1.3, and for wells with
Bp > 50 percent, Kf> 1.6.
We can see from Figure 1 that the origin of the curves falls within the
domain Ko 1, ttien farcing fluid~ i;n this weTl would increase the oiT yield; hawever,
if 1~ < 1, it would not.be sensi.ble to take steps to raise fluid extraction
- fran this we1T.
_ 7. Using the empirical dependencies (see Figur.e.2) for the corresponding
values of geologica~l ana technologica~l pa~ameters. and the predicted K~,
we evaluate~the anticipated:duratioa of the e.'cfect upon oil yields, tp.
Thus considering the. reco~�mendations presentEed above, based on the results
of ~generalizing. faets for 19.0 well.s, we can ~caise~ the effectiveness of
measures aimed at forcinq f],uid extraction..
COPYRIGHT: Vsesoyuznyy nau~hno-issledouatel"skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNITOENG),
1980
1T00'4
CSO: 8T44/1367
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FUELS
i-
i
I
UDC 622.276.72 ~
I
ASPHALTIC-RESTNOUS SUBSTANCES, PARAFFIN TN UDMITRTNEFT~ ASSOCIATION
Moscow NEFTEPROMYSLOVOYE DELO in Russian No 4, 1980 pp 18-20
[Article by O. F. irezov (deceased), Ya. L. Smirnov, F. A. Kamenshchikov,
and I. N. Golovin]
[Text] Oil of the Udmurt oilfields can be characterized in terms of its
physicochemical properties as heavy, having a density of 0.89-0.92 gm/cm3;
it has a high sulfur content (2.5-3.5 percent) and a high paraffin content
(3.6-9.5 percent), and at ground level its viscosity is substantial, up to
160 cP. The total concentration of asphaltic-resinous substances and
paraffin attains 75 percent. The gas concentration is insignificant-~-
10-25 m3/ton, and the concentration of nitrogen in oil gas is high--up to -
80-90 percent. The saturation pressure of gas in oil is high, close to the
initial bed pressur~e (96-112 kg/cm2). The pour point of the oil varies
from -4 to -17�C. The melting point of the paraffin is 48-57�C.
Wells are operated mainly on the basis of a mechanized method. Almost all
production wells of the Udmurt oilfields were found to be subjected to
intense deposition of resinous-paraffin fornnations since the beginning of
their development.
Current repairs are associated to a significant extent with deparaffination
of the wells. Moreover the wells also suffer significantperiods of idleness
due to clogging of pumping equipment by paraffin. Wells awaiting current
repairs stand idle for about 20 days.
Various methods for dealing with deposits of paraffin and with asphaltic-
- resinous substances are being used and tested concurrently with operation
of the oil wells: m~chanical (scrapers, weights, sweeps, balls), thermal
(processing wells with hot eil usi.ng an ADP-4-150 unit, and steam using a
PPU-3M unit), chemical (use of various reagents with solvent properties),
and preventive (use of pump.and comnressar pipes with glass-enamel coatings
on their inner surfaces).
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The effectiveness with which various methods of deparaffination are used,
as determined from the time i~etween cleanings, is shown below.
Form of Deparaffination Period Between
Cleaning3, Days
Hot treatment of pump and compressor pipes
coated with enamel 48-50
Hot rinsing of uncoated pump and compressor
pipes 36-40
Processing with solvents 35-40
Processing with PAA solution 32-36
Glass-coated pump and compressor pipes About 1 year
_ Because of the absence of a more-effective method, the thermal deparaffination
- method--that is, processing of the wells with hot oil or steam--has enjoyed
the greatest acceptance at Udmurt oilfields. However, the interval between
thermal treatments is relatively short. The reason for this obviously lies
- in the fact that the temperature and the depth to which heating occurs are
insufficient. Research established that paraffin deposition occurs down to
a depth of 500-600 meters; consequently the heating temperature at this
depth must be close or equal to the melting point of paraffin (48-55�C).
In heat treatment, unfortunately, the heating temperature (wrhich starts at
100-110�C) drops to 60�C at a depth of just 50-80 meters, while at 150 meters
it drops to 45�C. Consequently it is only within this interval that the
_ resin-paraffin deposits could be melted ttr?d carried away with the current
of fluid. Below this level, paraffin does not melt; it only softens and
- drains downward on the surface of p~ap and compressor pipes and hoses, thus
increasing the thickness of paraffin deposits in the 250-400 meter interval,
as can be deduced fran deposit curves plotted for a number of wells. The
more-viscous asphaltic-resinous compounds soften to a viscoelastic state;
then they undergo aging, and it becomes even more difficult to remove them.
Moreover they create more-favorable conditions for subsequent deposition of
resinous substances and paraffin. The effectiveness of heat treatment depends
in many ways on the volume of hot oil injected. Temperature measurements
dawn to the lifting depth showed that injection of oil having a temperature
at the well head of 98�C drops in temperature to 20�C at a depth of 300
meters when a 2 m3 volume is used, to 30� with a volume of 10 m3, anc~ to
35�C with a volume of 25 m~. This confirms the low effectiveness of pro-
- cessinq wells with hot oil.
- The wells are subjected to a significant amount of different ty,pes of treat-
ment each year with the purposes of removing deposits of resinous substances
- and paraffin, or preventing their deposition (see below).
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Number of Treatments
Treatment Type in 1978
- Heat treatments with hot oil using an
ADP-4-150 unit 3,971
Steaming wells with a PPU 3,300
Chemical reagents 1,037
- Dropping rubber balls into delivery lines 5,449
Thus each operating well undergoes an annual average of seven rinsings and
steamings, five deparaffinations of delivery lines, and one treatment with
chemical reagents. In addition to these operations to remove paraffin from
oil extraction equipment, pipes and hoses are steamed during current re-
pairs of the wells. In 1978 current repairs were performed 3,096 tunes on _
wells of the "Udmurtneft Association.
As we can see from the data presented here, heat treatments are the
principal method of deparaffination of oil extraction equipment. Because
of the gravth in the number of wells, the ADP-4-150 and PPU-3M units are
unable to fully satisfy the growing demand for well deparaffination. When
all wells must be treated in a single month, only 70 percent are actually
subjected to treatment, as a result of which most of the remote wells are
" processed at an interval of 2-3 months, which leads to excessive unjustified
periods of idleness between current repairs of the wells. The cli.matic condi-
tions as well as the marshiness and roughness of the terrain significantly
hinder ti.mely thermal deparaffination of the wells and delivery lines.
It should be noted that the machine unit presently produced for well de- =
paraffination, the lADP-4-150, is more effective than th~ PPU-3M. Moreover r.
the Tatar ASSR Scientific Research and Institute of Petroleum ~
Machine Building has developed a new modification of the machine unit, ~
the 2ADP-2-150, which permits treatment of the wells in a unit-well-unit
cycle. The new production cycle pernutted by the 2ADP-2-150 unit reduces
the need for conveying oil to the machine unit, raises the quality of well
treatment, and decreases operating expenses.
Pump and compressor pipes with coated inner surfaces are used to control
deposition of resinous substances and paraffin. Despite the fact that
90 p~rcent of the wells are outfitted with pump and compressor types with
an enamel coating, their effectiveness against tar, asphaltene, and
paraffin deposits is low. Owing to them, the interval between cleanings
increased by only 8-10 days. Moreover use of enamel-coated pinnp and com- -
pressor pipes complicates operation of the wells because such pipes do not
permit acid treatment, required in the exploitation of carbonate reservoirs.
Since May 1976 tests have been conducted on ptunp and compressor types with
a glazed inner surface. Forty-six wells were outfitted with glazed pipe _
on 1 January 1979; of these, six are operated with sucker rod pumps, and
40 are operated with submersible centrifugal pumps.
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The interval between repairs is an important indicator of well operation.
While for wells outfitted with pump and compressor pipes with and without
an enamel coating it is 130-135 days (for sucker rod pumps), for wells
- with glazed pipes it is twice longer. The need for heat treatment has
been eliminated with introduction of glazed pump and co~npressor pipes.
If we consider current repairs performed on wells not associated with
~ deparaffination, the average period between cleanings and between r~pairs
is about 305 days. The wells can operate without the use of any other
deparaffination methods. Control inspections of pump and canpressor pipes,
perfoxmed by lowering a paraffin meter into the well, and inspections of
the pipes during current repairs indicated absence of paraffin deposits
on their surfaces; thus they were lowered back into the well without
treatment and steaming~
A method for preventing deposition of asphaltic-resinous substances in
pump and compressor pipes has enjoyed use at the Mishkinskoye oilfield:
An aqueous polyacrylamide solution is periodically injected into spaces
around the pipes of the wells. However, the methods currently employed for
dealing with deposits of asphaltic-resinous substances and paraffin do not -
fully solve this problem.
, -1.U':4
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980
~
11004
CSO: 8144/1367
35
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- FUELS
UDC 622.276.72
- REMOVING REAGENTS OF SOLID HYDROCARBONS DEPOSITS, ASPHALTIC-RESINOUS
SUBSTANCES
Moscow NEFTEPROMYSLOVOYE DELO in Russian No 4, 1980 pp 20-22
[Article by V. V. Sizaya and A. A. Geybovich]
(Text] One of the promising ways for dealing with deposits of solid hydro-
carbons and asphaltic-resinous substances formed on the walls of oilfield
equipment when extracting, collecting, and transporting oil is to use _
- various sorts of removing reagents. The action of such removers is based
on partial dissalution or dispersion of deposits and their subsequent
loosening, owing to which the deposits become mobile and are carried away
with the Elow of oil. Therefore when selecting the remover and the optimum
conditions of its use, it would be important to study its solvent and dis-
persing capability in relation to the deposit.
Solid deposits are a rather complex mixture including oil, paraffin, tars,
asphaltenes, petroleum, watex, and mechanical impurities. Such deposits are
dissolved as a rule by hydrocarbons of the methane and benzene series and
their derivatives, which react with the deposits to form colored, opaque
solutions. Therefore the cammonly accepted method for determi.ning solubility
on the basis of solution saturation temperature cannot be used. Instead,
solubility is determined by a"rod" method and a weight method. Ways for
determining the effectiveness of reagent action upon paraffin deposits
created in the laboratory a~e also known. However, these methods can be
used only to arrive at a comparative description of the reagents.
Thus the "rod" method provides an evaluation of the action of reagents upon
. natural deposits of paraffin in static conditions. Structural changes ,
occur in the deposits in this case, inasmuch as they settle on the metallic
- rod in melted form. The "cold plate" method provides an evaluation of the -
- action of reagents in dynamic conditions upon paraffin deposits obtained in
a laboratory from a model fluid or from petroleum. In this connection the
need has arisen for developing a device permitting laboratory investigation
of the effectiveness of removing reagents upon natural deposits of solid -
hydrocarbons and asphaltic-resinous substances in dynamic conditions.
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Figure 1 shows a diagram of the clevice. It consists of walking beam head 4,
~link gear levers and an electric motor and reduction gear 6. Container
2, which is a metallic net suspended from a collar, is suspended freely
from the head of the walking beam by flexible thread 3. The device is
supplied with a set of nets with hole diameters of 0.1-0.5 mm.
I
r `-opv
4 ~ L J
_ ~ , ii
- ~ 6U
. ~
J ! s
~
~
1 ~
1
Figure l. Device Used to Determine Effectiveness of Removing
Reagents Upon ~Deposits of Solid Hydrocarbons
, and Alphaltic-Resinous Substancss
During the device's operati~n, the container moves back and forth in the
vertical plane, periodic ally submerging in the reager~t solution, containen
in vessel 1. The speed of the container's movement is set with autotrans-
former 7.
O~e gram of naturally deposited material is placed in the container, on the
_ metallic net. The heat-resistant vessel is filled with 25 ml reagent. The -
ratio of the quantities of deposited material and reagent may be varied
from 1:5 to 1:lOG depending on the dimensions of the containers and the
, vessels. Experiment time is 30-120 minutes. To maintain the required
temperature, the vessel and reag-:~nt are set up in a thermostatically
controlled bath. After the experiment the residue on the metallic net and
- the dispersed fraction of the deposited material filtzred out of the reagent
are stored in a thermostat at 30-50�C until complete removal of volatile _
hydrocarbons, and then they are weighed with a precision of 0.01 gtn. The
- solubility of thE deposits in the reagent is computed with the formula
(ml-mZ-m3) � 100
z=
ms
37
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_ where z--solubility of deposits in reagent, percent; ml--mass of deposit
sam~le prior to contact with reagent, gm; m2--mass of undissolved deposit
- residue in container following contact with reagent, gm; mg--mass of
= deposit fraction dispersed in reagent, gm.
The research was conducted on paraffin deposit samples from oilfields of
the "Nizhnevolzhskneft Association differing in their melting points and
their concentrations of paraffin and asphaltic-resinous substances (Table 1).
Clear commercial petroleum products were used as reagents: gasoline, ~
clarified kerosene, and petroleum solvent. The results of the experiments
- are shown in Table 2 and Figure 2.
Table 1
Deposit Concentration, $
Deposit, Horizon, Solidi- Asphaltic-
Well Number fication Paraffin Resinous
Point,�C Substances ~
Zhirnovskoye, Tula, 86 64 46.5 6.6 -
Zhirnovskoye, Yevlano-
Livenskiy, 604 76 64.6 3.6 ~
Kamyshinskoye, Staro-
Oskol'skiy, 96 75 65.4 1.6
Oleynikovskoye, 156 75 76* 5.9
*Concentration af paraffin-oil traction
Comparative data were obtained on the~effectiveness of reagent ac~ion upon -
different deposits (Table 2).
Thus petroleum solvent, which is a mixture of hydrocarbons in the benzene
series, had the most effective action. As we can see from Table 2, paraffin
deposits in well 86 are almost completely disintegrated in this reagent after
30 minutes. The solubility of deposits in petroleum solvent is 78 percent.
It should be noted that deposits containing more than 60 percent paraffin "
and an insignificant quantity of asphaltic-resinous substances have lower
solubili.ty not only in gasoline and kerosene but also in petroleum solvent.
Paraffin deposits from well 156 were used as an example with which to deter-
mine the effectiveness of petroleum solvent depending on time of contact. .
It was established that to remove deposits similar to those obtained fran
well 156, the time the reagent is left in the oilfield equipment must not
e:~ceed 60-90 minutes (see Figure 2).
38 -
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~ Table 2
KarNyecreo vrno-
. ~1) C2) HcexH~, ~ ~4)
~ ~3~ _
~ PearertT- 3 ~ ~o ~ ~
o Y~~~Tb PeMCH~ onbrra = ~ d;
~o
~ o~raokce~sxA o a n. ~ a
~ -
C~ F~ dCI ~ 01
; ~ t C~ .p Q1 ,p
a ~ ~
~
z = oo a ~ a~
- 86 Sexaxx (8) (11) 15 41 44
Kepoc.stx Ig~ CKOpoc;b ? 58 35
He~raHOA ~ 3 c~/c;
conbers~r s~rreparypa O'rcY'r. 22 7g
20'C; npoAOn-
bdi3HN $ JI[A?tJ[bHOCTb ~ ~Q ~ Z
~ R@pOCHH g~ xOHTBICTHpOH2- _
_ He~rx~o I ax 30 .kuH; 27 ~ 8
coabeexr coorxoweHae
arnokcexxa 33 45 22
� x peartKra
156 BtH3RH ~8~ ~.25 22 40 38
Kepocxp ~g~
He�rRxo tl ~ )8 48 34
co~beeRT 27 3a 38 -
96 He~T~txo~il0
conbeeat 47 15 38
Key: �
1. Well number 7. Fraction dissolved in reagent
2. Deposit removing reaqent 8. Gasoline
3. Experimental conditions 9. Paraffin
4. Deposit quantity, $ 10. Petroleum solvent
5. Insoluble residue (on 0.5 11. Rate--2.3 cm/sec; temperature--20�C;
mesh seive) time of contact--30 minutes; ratio
6. Fraction dispersed in of deposits and reagents---1:25
reagent
Parallel determinations of the e~fectiveness of petroleum solvent and gasoline
upon paraffin deposits from well 156 were made in order to evaluate the
comparability of experiment results. Ti.me of contact was 60 minutes, and
rocking rate was 2.3 cm/s~c (Table 3).
It follows from the data in Table 3 that the relative error in determina-
tion of the dispersing and dissolving properties of the reagent does not
exceed 3 per~cent for three parallel measurements.
39
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~1~ ~
y ~ ~/o
~
~ o
E~~~
i ; ; $ ~ ,~r~ 3 ti
~ ~ A ~0 60 90 /
i ~ npodo~~ru~teneNacmo oaa~~ra, NUN ( 2)
Figure 2. Effectiveness of Reagents Depending on Time of
Contact. With Deposits of Solid Hydrocarbons and
Asphaltic-Resinous Substances: 1--deposit
- ' soluble fraction (reagent's dissolvinq action);
2--deposit dispersed fraction (reagent dispersi.ng
action); 3--deposit insoluble fraction on metallic
net -
Key:
1. Deposit quantity, gm
2. Experiment ti.me, minutes
Table 3
� G (6)
f(UJI114CCTB0 ~ F c F
PCB~eHT- X8P8KTCP OTJIO7K!- OTJION(E`HNFI, ~
~'ABJIN� HN{I (IOCJIe KOHT8K� ~0 ~ = _
TE.16 Ot- T8 C pCBf eH70?t 4~ ? c~i
1107KtHHIf 1- F cv I f~"~ ~ a F�~
0'4 o y'~ o~ 4�e O ~ 3Q -
( T~-1C~TA- HE~8CT80pNMdH ~
eoA ocraTOx (xa cF~re~9 20 20 21 0,44 2,18
conbsexr ANCneprHpyeMaR ;
vacrb e peareHTe~g 38 40 38 0,89 2,30
PacTeopaMaa
qacTb e peareH~p 42 40 41 1,0 2,43
HeapacreopNMdti ~
(11'~lH3HIt orrato~ (H2 CilT~g 22 23 24 0,67 2,91 ,
llxcneprxpyeMaA
qacTb s pcareare( 9 27 28 27 0,44 1,60
_ PacreopxMaA '
vacrb e peareHr~10 51 99 49 0,8~J 1,79 ~
Key:
1. Deposit removing reagent 7, Petroleum solvent
2. Nature of deposits following g, Insoluble residue (on seive)
contact with reagent 9. Dispersed fraction in reagent
3. Deposit quantity, $ 10. Soluble fraction in reagent
4. Experiment number 11. Gasoline
5� Absolute error
6. Relative error, $
40
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Thus the method proposed here can be used to select an effective reagent
with which to remove deposits of solid hydrocarbons and asphaltic-resinous
substances in the concrete conditions of the particular oilfield, and to
arrive at the optimum conditions of its use in dynamic conditions (tempera-
ture, time of contact, rocking rate).
I '1
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i skonomiki neftegazovoy promyshlennosti (VNIIOENG),
_ 1980 -
11004
CSO: 8144/1367
~
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FUELS
UDC 622.276(430.43):539.98:556.314
DEVELOPMENT OF PRODUCTIVE BEDS IN THE PRESENCE OF BARIUM OXIDE DEPOSITS
Mo~cow NEFTEPROMYSLOVOYE DELO in Russian No 4, 1980 pp 22-24
[Article by V. I. Veshchezerov]
(Text] Beds CIV, CIII, and C II of the Radayevskiy horizon are confined to
the Nizhnevezeyskiy terriger_ic camplex of the Mukhanovskoye oilfield in
Kuybyshevskaya Oblast. In this case bed CI~ is subdivided by dense rock
into intercalations Clpa and CI~. The beds are composed of quartz sand-
stone nonuriiformly interbedded by clayey ~leurolites. The sandstone cement
is basically clayey.
The beds are being developed all together by a single filtration system of -
wells, and they are the second object of exploitation. Since 1957 their
exploitation involved perimeter and contour flooding with fresh water, and
waste water has been used since 1972. productive beds are being injected
with waste water having a mineral content of 120-130 gm/liter and primary
salinity of 66-68 $�equiv.
In the last 10 years of exploitation of the second object, we observed cases -
of precipitation of inorganic salts in production wells, pumping facilities,
pump and compressor piping, delivery lines, and grouped measuring and
separation devices.
Research established that sulfateless brine in the productive beds of the
Radayevskiy horizon in the Mukhanovskoye oilfield contain barium:. The
concentration of barium in brine from bed CII, undiluted by industrial
waste wrater, is usually 150-250 mg/iiter, while in brine from bed CIp it
reaches 400 mg/liter. ,
Barium-coritaining sulfateless brine is chemically incompati.ble with all -
other brine or by-product water containing heightened sulfate quantities.
, When they are mixed togett:er, inorganic salts, represented mainly by barium
oxide or barytocelestine, settle out as a precipitate. Under thermobaric -
conditions, barium and barytocelestine precipitate out at any point in the ,
beds, wells, and production equipment where barium cantaining brine mixes
with sulfate-containing water. In this case when the quantity of sulfates
42
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is sufficient, barium precipitates out completely, for example in a coaan~n
flow of barium-containinq bp-product brine and sulfate wat~r following
' their mixing at an SU-3.
Owing to the camplex geological stxucture of productive beds in the Radayevskiy
horizon and injection of fresh water into these beds, by-product water
having diverse chemical composition formed within them. By-product water
- in certain sections of the central ~(domed) part of the structure, in the -
vicinity of wells 209, 210, 238, 239, 509, 368, and 261, is represented l~y
deposit water or by weakly diluted deposit brine. Most of the production
wells in the western and eastern periclinal garts of the structure are
flooded by by-product water having lower mineral content. In this case the
concentration of sulfates in by-product ~rater increases to 500 mg/liter, and
in some cases even up to 870 mg/liter (as deposit brine is diluted by fresh
= injected water). This process is associated with leaching out of cement sulfate
minerals and their removal from the sandstone reservoirs.
Gxadual displacement of water having lower mineral content and brine by
waste water containinq up to 490 mg/liter sulfates is observed in connection
~ith a transition to pumging waste water into the central part of the
, structure from the northern and southern wings. Moreover owinq to non~
uniformity in floodinq and in extracting the oil reserves with a single filtr�a-
tion system, the chemical composition of by-product water in different beds
is not identical. Water of varyi.nq chemical composition occasionally enters
the bottom holes of the production wells, which is why barium sulfate and
barytocelestine precipitates form. Thc basic characteristics of the chemical
composition of by-praduct brine and water in productive beds of the
Radaye:vskiy horizon of the Mukhanovskoye oilfield are shown in the table below.
_ ~~}---'k1~-, ~ ' F3~ ~
� ' COd2~17U,HH~, L~A .
~ o
- ; ~ M + + 0 4 ~ + ~
c~ C C~ ~ v' = vi ca ~E ~ 5)
828 C ly~ 241,3 21,1 4,5 0,01 p,03 66,46 401
210 C 1V6 244,4 21,0 4,43 0,01 p,03 67.1 212
_ 245 ~rvaa 62,0 5,2 0,85 0,16 0,31 69,54
285 Ct~-t~~ 145,7 12,8 2.13 0,24 0.07 68.12 8,0
834 C~t 75,4 4,0 1,46 0,52 0,40 75,72 -
- Key: _
1. Well number 3. Concentration, gm/liter ~
2. Bed 4. ~�equiv
5, mg/liter
43
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~vo cases of complications may be exanu.ned as examples with which to both
clarify the causes of salinity and monitor the status of the development ~
and tlooding of individual productive beds. For example, prior to July I970
well 210 jointly exploited beds~ClI, CIII, and CIV~. Tt was shut down after ~
almost complete flooding by mixed waters of low mine~al content. Selective
isolation of the incoming cvater currents revealed barium oxide deposits of
significant thickness on the walls of the casing--in the interval from the
filter to the pump intake (2,225-1,150 meters)--and, further up, in the
UETsN [noL- further identified] and the pump and compressor pipes. Following
~ shut-off of the upper highly flooded beds by two packers, well 210 was con-
verted for exploitation of just intercalation CI~. At a~luid yield of
510 m3/day, well 210 is flooded exclusively by the influx of weakly diluted ~
barium-containing sulfateless brine from intercalation CI~. Salt formation
was not observed.
Exploitation of bed CIV~ by well 828 was also accompanied by intense forma-
~ tion of barium oxide and barytocelestine deposits in UETsN, pump and com-
pressor pipes, and the delivery line. Due to formation of dense and hard
barium oxide deposits on the intake screen, the working wheels, and the
guides of the ETsN [electric centrifugal pump], the device jammed 5-15
working days follo~ving start-up. During this period, water of mixed composi-
tion entered well 828.
Due to a significant cor.centration of calcium in the water, an attempt to
pump a compound inhibiting deposition of solid adhering salt deposits was
unsuccessful. -
The lower intercalation CI~, which is flooded by diluted by-product water
having a high sulfate concentration,was shut off after the resear,ch. Well
828 began operating with a fluid yield of 145 m3/day having a water concen-
tration of 36 percent, and it began producing weakly diluted by-product brine.
Moreover the barium concentration in the brine increased to 401 mg/liter,
while the sulfate concentration drtipped to 12 mg/liter. Complications in
the work of the UETsN were not observed.
In addition, the operations carried out with wells 210 and 828 also indicate
differences in the nature of flooding of the bed in the same section of the
structure. Examining, in general, the flooding of productive beds in ex-
ploitation object II, flooding of production wells, and the causes of
complications created in the extraction and collection of oil associated
with precipitation of hard sticky barium oxide deposits, we would have to
make a differentiated evaluation of the barium oxide formation phenomenon.
Precipitation of barium oxide in production wells, pump equipment, delivery
line~, GZU [not further identified] , and in the oil co.~lection and initial
preparation systems is a negative phenomenon causing a great deal of economic
loss in oil extraction. This phenomenon must be fought, and mainly by
separating the currents of chemically incompatible barium -containing and
sulfate-containing water and brine. Considering the conditions resulting
from differences in the chemical composition of by-p~oduct brine and water,
we must immediately test and begin industrial use of chemical reagents pre-
venting formation of sticky~deposits of inorganic salts and barium oxide.
, 4~+
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Precipitation of barium oxide deposits out of true solutions in flooded
- laminae and in flushed zones of the productive bed must be interpreted as
a positive phenomenon, raising the effectiveness of artificial flooding,
and the final oil output. What thi~ easentially means ia that when the
chemical composition of by-product water take~ shape and intermixing occurs
between barium-containing brine and artificially formed sulfate water,
barium precipitates out in thp form of barium oxide or barytocelestine,
partially or completely, right within the re~ervoirs of the productive
beds.
Data describing the chemical composition of by-product water and the results
of monitoring the technical condition of wells and oil extraction equipment
confirm the presence of this process. Absence of barium in by-product
water and, additionally, formation of salt in the tested wells are direct
evidence of the existence of these processes. -
Articifical salt deposition in the beds is proceeding spontaneously, sinee
problems associated with the chemical campatibil.ity of the water and possible
complications in exploitation were not examined in the planning stage or in
previous years of exploitation of the productive beds of tYie Radayevakiy
horizon.
Use of fresh hydrocarbonated water to maintain reservoir pressure in the
first stages of development should be noted as a positive point. Under the
geoiogical and hydrogeological conditions of the productive beds in the
Radayevskiy horizon of Mukhanovskoye oilfield, saturation of artificially
formed by-product water by sulfates depends on the concentration of sulfate
minerals in the rock of the reservoir, and it proceeds irregularly and
relatively slowly. Therefore precipitation of barium ~xide in large,
highly tanqible quantities occurs in remote zones of the bed, over rela-
tively large areas of the artificially flooded zone. This is confirmed by
the slow injectivity of the injection wells. On the otner hand when pro-
- duction wells flooded with barium containing by-product brine--sulfate-
containing water--are plugged, barium ~ precipitates out right within the
critical znne of the bed. A similar effect can also be achieved with the
reverse combination of the chemical composition of by-product water and
plugging water. In such cases well productivity significantly drops after
plugging, and development often must proceed over a lonq time interval.
Thus the phenomenon of chemical incompati.bility of brine and water of
different compositions, which is accompanied by deposition of b3rium oxide
and barytocelestine, yields to monitoring and control, and it may be
capitalized upon as a technically performable process by which to raise the
effectiveness of artificial flooding and the final oil output. Moreover �
deposition of salts in wells and production equipment is almost completely
excluded, which mi.nimizes the need for special operations with various
chemical reagents.
~
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii, up-
rav:leniya i ekonomiki neftegazovoy pramyshlennosti (VNIIOENG), 1980
45 _
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UDC 622.276
PROBLEMS OF EXPIAITING OILFIELDS IN COMPLEX CONDITIONS
Moscow NEFTEPROMYSIAVOYE DELO in Russian No 4, 1980 pp 25-28
[Article by V. P. Maksimov]
[Text] The experience of organizing oxl extraction in W~est Siberia and `
westerr~ Kazakh SSR has produced a number of important, complex scientific-
technical problems, and it has persuaded us of the need and the economi~
feasibility of finding fundamentally new concepts upon which to base all
operations. These problems are unique, and they are associated to a signi-
ficant extent with the unusual conditions under whieh the oilfields must be
developed, ones hindering attainment of the end goal--fuller extraction of
oil from the bed.
Complex conditions may be an objectively existing natural factor, or they -
may arise as a result of man's interference. The former include unfavorable
geological and climatic conditions, inaccessibility to transportation, the
temperature of the reservoir system (up to 80�C), the broad range of
- petroleum properties (0.6-150 cP within tl~e beds), presence of carbon dioxide
in the reservoir system, and so on. I'he second group includes complications
stPmming from crookedness of the wells, high rates of oil extraction and
growth in water concentration of well discharge, disturbance of the carbonate
equilibrium in the reservoir system resulting fran injection of incoanpatible
water and, as a consequence, deposition of salt in production equipment, -
and so on. These complications are fully or partially typi~al of oilfields
in West Siberia, the western Kazakh SSR, and other oil extraction regions.
This aggregate of coznpli~c~ting factors has not been studied sufficiently ;
i.n relation to oil ec+craction. Determination of the basic problems of ex-
ploiting Siberian c~ilfields, which is the most general and complex case,
has imp~r.tant significance, since it would permit us to concentrate the -
resources and ef~crts of specialists at finding the most effective concept
for developing the region and the sect~r. In this case it would be im- ~
portant to emphasize that in looking for long-range alternative so~utions
to problems, the crit~ria we use include not only the conventionalZy employed ~
~ economic indica~ors but also minimum labor outlays.
46 _
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Information of particular accuracy and completeness lies at the basis of
any evaluations made of different processes and decisions arrived at in re- -
lation to all elements of the oil extraction system. Growth in the accuracy
and dependabilicy of infozmation is a general trend typical of all sectors
of science.
The noted peculiarities of the oilfields ~lo not permit us to effectively
acquire the raw information we need by traditional methods. Great complexi-
ties arise in the transition to mechanized exploitation of wells, which
dramatically complicates comnunication between the wellhead and the bottom
hole. A need arises for seeking new ways to acquire information.
One of the basic parameters of current control over oilfield development is
reservoir pressure. Its measurement in the field is associated with certain
methodological and organizational difficulties, and this is why we are
interested in finding quick methods for determining reservoir pressure,
. g3rticularly when the pressure recovery curve is incomplete.
The VNII [Al1 Union Scientific Research Institute of Petroleum and Gas] has
developed ame~chod based on using an identification model of the reservoir- -
well system. It boils down to measuring changes in bottom hole pressure
particular time intervals after shut-down of the well, and determination of
corYelations.
The results from treating data acquired in research on wells of the
Salymskoye oilfield indicated a possibility for predicting reservoir pressure
~ with an error of 1-2 percent ot the true value. The identification method
is also useable in determining the productivity factor. This method also
essentially involves creatian of a model of the reservoir and detern~ination
of its parameters. The determination error does not exceed 5-10 percent.
- A group of colleagues of the VNII have developed a method for determining
current reservoir pressure without shutting down a well to take the measure-
ments, based on statistical differentiation of the dependencies of yields _
and bottom hole pressure as a function of time. The possible error does
not exceed 3-4 percent in this case.
Significant complexities arise in detennination of hydrodynamic parameters
~ahen oilfields are placed into production. Arisal of perturbations within =
.:he bed owing to the start-up and shut-down of wells hinders acquisition
of good results by conventional methods. This problem can be solved by _
using the analytical method developed by the Si.berian Scientific Research
institute of Petroleum Industry.
Current production information serves as the raw data for determining the
hyriro- and piezoconductivity of the reservoir and the productivity factor
of the wells: the schedule of well operation, the initial and current
rec;ervoir pressure, and the time of well shut-down for measurement of
s current reservoir pressure. Using the method of successive approximations,
47
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we can determine accurate values for the sought parameters; in this case the
- difference in values in comparison with the results of standard analyses is
about 10 percent. This method can also be used to determine 'r,he scope of
the reservoirs, and to reveal the hydrodynamic relationships existing
between different beds.
There are extensive possibilities for fuller analysis of the peculiarities
of production processes in the use of simulation models. As we know, most -
- analysis methods produce information on parameters only in relation to a con-
crete point of a formation, but ~ if we are to control these processes,
we would have to know integral values characterizing the object--a bed for
_ example--as a whole. The usual way of obtaining such information--
analyzing data from the largest possible number of wells--is associated with
significant outlays. Another way is to build a simulation model that adequately
reflects the real object. It has been established that the Monte Carlo
- sampling method is an effective modeling tool, since it permits us to
integrally determine parameters using a rather small sample.
This problem is also associated with another important task--early diagnosis.
If we can achieve it, we would be able to evaluate the possible consequences
of the particular technological concept employed, or of errors made in
detexmining parameters when the quantity of information is insufficient.
This task may be ce:.~~pleted with operational diagnosis methods developed by
the VNII, based on mutual correlation analysis of the degree of interaction
occurring, using data from normal well e~cploitation as the basis. These _
methods were developed in apPlication to influences exerted upon the bottom
hole zone of the reservoir, combustion within the reservoir, and so on.
This task requires comparison of two samples, one of which corresponds to
use of a conventional system (flooding for ~xample), and the other of which
corresponds to application of some particular method (for example raising the
oil output) and establishing the actual influence of the latter.
Change in well water content, in the gas factor, and so on .is used as the
diagnostic indicator for different processes.
The second group of problems involves peculiarities in the physicochemical
properties of reservoir systems.
We know that the completeness with which oil is extracted from a porous -
medium depends on many factors--the viscosity and composition of the petroleum,
the viscosity of the displncing agent, interphasal tension, the properties
of the surface of the porous medium, and so on. These factors influence
the choice and effectiveness of inethods for raising the oil output of the
beds.
A mutual relationship exists between the reservoir oil output and the use -
coefficient of the oil-saturated stratum. An analysis would show that this
48
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coefficient is significantly greater than unity. Filtration of the clrilling
solution worsens the collecting properties of the reservoir's critical zone
and reduces the coefficient of hydrodynamic efficiency to 0.5-0.8. This
reduce s the energy indicators of the exploitation processes of production
and injection wells.
The VNII evaluated the collecting properties of the bottom hole and remote
zones of beds worked by production wells in the Samotlor and Ust'-Balyk
oilfie lds. It was established that due to imperfections in the well finishing
- techniques and penetration of ~iltrate into the bed, the permeability of a
signif icant part of the critical zone (with a radius of up to 6-14 meters)
is mor e than twice lower than in the bed's remote area. The productivity
of the wells may be increased by 25 percent and more, on the condition tnat
permeability is restored to its initial value.
The physicochemical aspects of the problem of raising reservoir oil output
are associated with capitalization upon the properties of the surface of
pore channe ls. It has been established for example that in the Salymskoye
oilfield, which has a hydrophobic reservoir, liberation of gas within the
reservoir creates an additional pressure gradient that prevents flow of oil
to the well. Under these conditions hydrophilization of the surface would
- promote elimination of this effect and an increase in oil output.
Petroleum from sane oilfields, Russkoye for example, is typified by non-
Newton ian properties, with relaxation time attaining several hours. The
presence of relaxation effects must be accounted for not only when evaluatinc~
filtration processes but also when determining the conditions under which
deep-well pumping equipment must operate. It has been established that this _
penaits us to determine the optimum pump delivery rate depending on the
produc t of the number of oscillations and piston stroke.
Also of special significance are processes associated with conventional
flooding of beds. We knaw that underground water is being used to increase -
pressure in productive beds for the first time in domestic practice in the
oilfie lds of Siberia. The volume of water inje~ted annually attains more
than 6.0 million m3. The operational experience of using Aptian-Cenomanian
water Yias special value, and iic must be laid at the basis of the analysis
in support of subsequent solutions. This watez has the best oil flushing
and f i ltration properties .
The main advantage of underground water lies ir: the fact that its use pre-
cludes or significantly reduces thP danger of arisal of two complex
scient ific-�technical problems--deposition of salt in production wells and
_ in the oil collection and preparation system, and sulfate reduction in oil
beds. In a number of cases these problems are the main causes of a short
- interval of well operation between repairs, and they make additional opera-
~ tiona 1 expenditures necessary.
- 49
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Meanwhile the experience acquired in development of the Zapadno-Surgutskoye
oilfield and individual sections of the Ust'-Balyk and Megionskoye oilfields,
where water from underground sources was injected, shows that problems
associated with deposition of salts and arisal of sulfate-reducing bacteria
are absent here, or their importance is significantly reduced. A highly
effective, simple procedure has been developed for the use of underground
water; it produces a significant economic impact.
If we are to broaden the scale of its industrial application, we would have
to once again return to the problem of using under~round water. We must
concentrate the efforts of scientists and specialists upon solving priority
problems, such as increasing the unit output of water i.ntake wells to 10,000
m3/day and higher without sand removal, and at creating dependable technical
resources for collecting and injecting underground water possessing better
operational parameters.
The next group of problems is associated with the production aspect of
creating and operat~.ng the basic operational systems (wells, and systems for
collecting and preparing oil, gas, and water).
- One of the important problems is development of oilfields with the help of
inclined and horizontal wells, which makes it possible to significantly in-
crease the drainage zone and raise the effectiveness of reservoir flooding.
The experience of their operation and the computationsshow that the yield
increases in this case, isolated sections of the bed begin producing, and
the oil output rises. Research has also shown that when ailfields are
tapped by horizontal wells of considerable length, oil extraction rises in
the waterless period.
An analysis of inclined wells exploiting bed AV4_5 of the Samotlor
oilfield and bed BV6 of the Pravdinskoye oilfield showed that in these cases
the productivity factor rises, this growth beir.g proportional to the angle
of incline of the shaft, within a range of up to 30�. It would not be
difficult to evaluate the accompanying advantages: higher bottom hole
pressure and, consequently, a longer period of natural flow, reduction of
unit gas consumption in gas lift extraction, reduction of the depth to which
the pump needs to be lowered, and so on.
Implementation of this method is associated with solution of a number of
technical and organizational problems associated with drilling the wells,
casing formation, development, and control and adjustment of the operations.
_ The fourth group of problems is associated with well exploitation.
_ The central problem that must be solved in well exploitation is that of
reducing the number of personnei required. This would be possible only -
if we employ more-reliable methods and resources for raising fluids, ones
significantly reducing the volume of repair operations that must be performed
at the site of the well.
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Experience has confirmed the high eifectit;eness of using the gas lift method,
and it will doubtlessly by introduc~d on an increasing scale. In particular,
evidence of this can be seen in the experience of gas lift exploitation of
~ine Pravdinskoye oilfield.
Extensive use of the gas lift oil extraction method does not preclude the
- need for developing pump e~:ploitation of wells. Application of deep-well
- pumps produces a number of complex scientific-technical problema assxia~:ed
with raising the effectiveness of oil extra~ction by pwnps. These prob7.~ms
must be solved for the Si.berian oilfields, mainly because of the relatively
short time of operation ot deep wells between repairs,
resulting in higher losses ~n oil extraction and significant consumption of
materials and manpower. As the number of inechanized wells increases, the
problem of increasing the period of operation of pump wells between repairs
becomes increasingly more acute.
The main causes of the large ntunt~er of repairs required by the wells include
deposition of salts, removal of sand from the critical zone of the bed,
significant curvature of the beds, high fluid temperature, and so on.
The main tasks that must be completed through the efforts of oil specialists
include, first of all, organization of control over the ~peration of equipment,
, and creation of a quality control service. Only a detailed, factual analysis
of the causes behind equipment breaknowns will pennit us to plan ways to
eli.minate them.
- The experience of the "Bashneft'" Association shows that implementation of
such measures can produce a significant impact.
It appears possible to increase the time of operation of pump wells between
repairs by about 1.5 times in the next few years in response to just these
measures alone. Specialists, mainly of the Central Scientific Research
Institute of Petroleum Industry, will have to assume technical leadership
over the control and selection of equipment to be provided to each well,
over the operation of the equipment in accordance with the operating in-
structions, and over the collection and an~lysis o� equipment dependability
statistics.
Another important direction is to create and use more-effective pumping
equipment. The sector is presently doing work in this direction. New
_ types of pumps are undergoing tests in the laboratory and in the field.
The task in this case is to create devices that could operate in a we11 for
2-3 years without the need for raising the pipe. One of them--a long-stroke
deep-well pump--is undergoing testing in the "Orenburgneft Association.
Its specifications are significantly different fro~n those of the nornial
series of rocki.ng pumps. The estimat~d time of current repairs is decreased
from 17 to 1-2 hours, and the need for an underground repair team and lifting -
apparatus is excluded. The ar,nual economic impact enjoyed from its use is
estimated at 3,OOQ-5,000 rubles per well per year.
~ .:~(?q~
_ COPYRIGHT: Vsesayuznyy nauchno-issledovatel'skiy institute organizatsii., up-
ravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG) , 1980
_ 11004 51
C50: 8144/1367 FOR OFFICIAL USE ONLY
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FUELS ~
UDC 622.276:552.578.082.4
USE OF ULTRASONIC METHOD TO DEAI. WITH SALT DEPOSITION AT SAMOTLOR OILFIELD
[~toscow NEFTEPRtJMYSLOVOYE DELO in Russian No 4, 1980 pp 28-30 ~
[Article by V. V. Dryagin, S. A. Yefimova, V. N. Makarov, L. N. Makarova,
and G. N. Yagodov]
[Text] Development and exploitation of the Samotlor oilfield is complicated -
by deposition of salt in production equipment and at the well bo~tocn hole.
~
Chemic~~l methods, which require large amounts of chemicals and which are not
_ always effective, are extensively employed today to control salt deposition.
- Creation of inethods to suppress salt deposition by me~~ns of powerful physical
fields, acoustic in particular, is a pranising direction. Physicochemical
analysis of salt deposition products will be an aid in evaluating the possi-
. bilities and features of the method. It was with this goal that about 20
, samples of salt deposits were analy~ed. Phasal X-ray analysis (the Debye-
Sherrer method) demonstrates that salt deposits in the oilfields of West
Si.beria are represented mainly by calcite (trigonal syngony) or barite
- (rhombic syngony).
A complete chemical analysis of the samples would show presence of small
quantities of Na, K, Mg, Mn, and Fe salts.
- Spectrometric analysis reveals boron, titanium, and other elements, the con-
centrations of which in the salt deposits are shown below, percent:
~ . . . 0.0008 Si . . . 0,23 -
Ti . . . 0.036 Al . . 0,15
. . . 0~0016 Fe . . 1,2
Mn . . . 0,086 Ca . .24,0
Co . . . 0,005 Na . . 4,0
Cu . . . O,OU03 K . . . 2,0
Ba . . . 0,3 ~ Mn . 1,0
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- The multiple composition of samples correlates well with the chemical compo-
sition of injected reservoir fluid and with the composition of rock leaching
products.
Microscopic analysis of salt slides indicates a dependence between salt
deposition and the state and properties of pipe surfaces.
Vaxious factors eliciting salt deposition (change in temperature, pressure,
and the concentration of dissolved sub~tances and carbon dioxide, the complex
chemical composition of the deposits, and the state of pipe surfaces) indi-
cates that salt deposition could be controlled suitably with the use of
physical fields affecting the conditions of pipe-fluid conta.:t. The results
of testing the influence of sound in the laboratory and in the field demon-
strated its effectiveness in controlling salt deposition. However, the
series-produced ultrasonic apparatus employed is not well suited to the
conditions offered by the oil-bearing regions of West Siberia. _
In this connection it became necessary to develop a complex of apparatus
intended for ope~ation at low temperatures and in the presenae of vibrations,
_ and which would insure dependable work within a bro~d ranqe of variable
frequencies and output capacities. Such a complex was created for the first
time as a result of joint work by the Siberian Scientific Research Institute
of Petroleum Industry, the VNIIYaGT [not further identified], and the Ural
= Polytechnical Institute.
The acoustic apparatus includes a ground ultrasonic oscillator and a broad-
band well acoustic emitter.
The figure below shows a block diagram of the acoustic apparatus. Ult..sonic
oscillator 1 consists of a TPRCh-10-10-30 adjustable-frequency thyristor -
oscillator, 3, having an efficiency of 0.7. The specifications of the
ultrasonic operator are presented below:
Adjustable power, kw
- Consumed up to 19
Output up to 12
Adjustable frequency (in c~ntinuous mode) kHz 10-30 _
Pulse duration (a.n pulsed mode), sec 0.1-2
Overall dimensions, meters 1.7x0.7X1.5
Weight, kg 600
, A GAZ-66 truck carries the gro~nd apparatus. The~ oscillator's operation is
monitored by apparatus represented by 4,~5,6, and 7. A special device, 2,
is foreseen to match the oscillator with the well acoustic emitter 11 and
cable 10.
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- -
~21 ~-1 ~?2~ o ~
I LJ ~ r-1
~ ?0 I ~ 2 ! ~
i
~ I /8 ; i
r s s s ~
j 19 ~/7 16 ~ i
_ ~ r e
- - ~ ~
9
~s 10
- w~
, '
~
13
~
f? _
~
' .
Diagram of Field Experiment With Test Well No 4643:
_ 1--ground ultrasonic oscillator; 2--matching device;
3--TPR4-10-10-30 thyristor converter; 4--input filter
block; 5--measuring amplifier; 6--acoustic parameter
recorder; 7--broad-band amplifier; r3--frequency spectrum ~
analyzer; 9--GAZ-66 truck; 10--ICRBK cable; 11--well
acoustic emitter; 12--NKT [pump and compressor pipes]
intake filter; 13--metallic monitoring c~linder; 14--NKT;
15--test well; 16--slide valve; 17--reflux valve; 18--model
fluid preparation block; 19,20--dosing pumps; 21,22--con-
centrated NaHCOg and CaC12 solution containers, respectively -
- Magnetostriction converters are used as the acoustic emitters. The emitters
are made from magnetostriction strips, and they consist of a set of cylinders
coiled alonq the generatrix. The metal housing containing the emitters has
an exchangeable stem by which the emitters are lowered by NKT or a cable.
The well emitter is powered by a KRBK-3X16 cable attached to the NKT by belts.
On the ground, the apparatus produces cavitational emissions in the entire
range of operating frequencies, 10-30 kHz. The average acoustic pressure
generated by the acoustic converter at a ranc of 1 meter is 40 kPa.
This apparatus was tested in test well 4643 at the Samotlor oilfield (see
figure). The test well includes well 15, model fluid preparation block 18,
and acoustic emitter block 1. Acoustic emitters 11 are built into NKT 14
200 meters from intake filter 12. This test well can be used to model
54
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fluids with different concentrations of salts, and to create different
thermodynamic conditions at the bottan hole.
The model fluid preparation block includes two containers 21,22 with a -
volume of 5 m~ each, containing concentrated NaHCOg and CaC12 respectively.
Preparations to iu:ject the model fluid into the well proceed according to
the scheme presented below: The needed doses of NaHCOg and CaC12 solutions
are fed by dosi.ng pumps 19,20 into the injection pipeline, where they are
mixed with water. Passing out of the pip~line through reflux valve 17 and
slide valve 16, the model fluid is ~fed to NKT filter 12 through the space
around the pipes. In this zone, the fluid mix2s with reservoir oil, and
it rises up the NKT due to natural gas lift. The resulting water-oil
emulsion passes through acoustic emitter 11, where it is subjected to the
action of the acoustic field.
Reagent dosing is monitored periodically by briefly closing the movable
valves of the dosing pumps and measuring pump delivery. Mineralization of
the model fluid is monitored during its injection on the basis of samples
taken froan the injection line.
- The following procedure was used in the well experi.ment. Metal monitoring -
cyli.nders 13 were situated in the well, above and below the emitters. For
15 days the fluid in the well was subjected to acoustic energy of a particu-
lar frequency. Then the monitoring cylinders were raised to the surface,
and the thickness of salt deposits was measured. Next the frequency of
_ acoustic emission was measured, and the experitnent was repeated.
The research was conducted at three different frequencies with the same
_ emission intensity. As a control, cylinders were stored for 15 days under
the same conditions but in the absence of the acoustic field. The experimental
research was conducted for 4 months of trouble-free operation of the appartus.
The results are compared in the table b~low.
Acoustic Field Acoustic Field ~tio of Deposit Thickness Well Yield
Frequency, kHz Intensity, kPa Before/After Acoustic Deposit Tons/Day
Influence, mm/man
8 4U 0. 6/0 50
- 16 42 0.8/0 Calcite 40
22 42 0.7/0.1 30
These data show that the acoustic field reduces the thickness of salt deposxts
and increases well yield. The optunum effect occurs in a frequency range of -
8-16 kHz, and at a significant acoustic field intensity. The nature of the
deposits (calcite) is not a limiting factor of the acoustic influence.
55
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Change in salt structure should also be noted: Following acoustic influence, _
the crystals have smaller dimensions, and they are bonded to the surface
of the cylinder much more weakly than when the influence is absent.
These data cai~ be explained in the following way: The acoustic field
creates acoustic currents at hard surfaces, which break up centers of
crystallization, and thus small crystals are removed from surfaces and
carried away by the fluid.
The research results att-.est to the good efficiency of the apparatus, and
the high effectiveness of using an acoustic field to deal with salt deposi-
tion.
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institute organizatsii,
upravleniya i ekonaniki neftegazovoy promyshlennosti (VNIIOENG),
1980
11004
CSO: 8144/1367
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FUELS
UDC 622.276.43:620.193.23:558.98.55:546.221
A.PPEARANCE OF IRON SULPHIllES, FREE HYDROGEN SULPHIDE IN FLUIDS FROM~
DEVONIAN WELLS
Moscow NEFTEPR(JA~SYSLOVOYE DELO in Russian No 4~ 1980 31-33
(Article by Ye. O. Nedoboyeva]
[Text] In the initial period of perimeter flooding (1948-1949), underground
water of the river Ik was subjected to extensive chemical processing-- _
chlorination, decarbonization, deoxygenation, and so on.
Beginning in 1950, the water was injected into the bed without chemical
processing, adding up to 25 percent surface water of the river Ik. -
According to data of the Tatar ASSR Scientific Research and Planning Institute
of Petroleum Industry (1960), sulfate-reducinq bacteria (SRB) were discovered
in surface water of the river Ik, but they were not detected ir. underqround
water. A mixture of surface and underground water from the river Ik was
_ pumped out by IQJS [coanpressor and pumping station] No 1, 2, 4, 5, 6, and 13.
Fraiai June 1959 to September 1960 water from the river Ik was not used for
this purpose. Injection wells 1301, 1299, 717, 1466, 551, and 553 of
the logging series are fed by KNS No 5. Injection of mixed fresh water
was started with well 717 in March 1958, well 1301 in April, and well 1299
in June. Duri.ng the time that underground water to which surface water
frost? the river Ik was not added was being injected, wells 1466, 551, and
553 were placed into operation.
Water pumped out of swabbing injection wells was analyzed in 1960. Iron
sulfides and free hydrogen sulfide wells detected in water saiaples from~ wells
4, 357, 379, 717, 936, 1299, and 1301.
Middle and lower Devonian water does not contain hydrogen sulfide, but it
does aontain ionized ferrous iron at a concentration of up to 200 mq/liter.
Hydrogen sulfide was formed in the bed due to the vital activity of 5128
pumped in from the �river Ik's surface water; entering into reaction with
iron contained in the water and the pipes, the SRB produced iron sulfide.
57
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Table 1 contains data on the work of the injection wells, and the water
analysis results.
Similar analyses were conducted for inj~ction wells 334, 815, 1034, 1274,
1334, 1401, and 1456; neither free hydrogen sulfide nor sulfur bound in the -
form of iron sulfide~ detected in discharged water.
We can see from Table 1 that presence o~ iron sulfide and hydrogen sulfide
in withdrawn water is observed only a year and more after injection of fresh
water containing SRII.
_ Free hydrogen sulfide was discovered for the first time in oil emulsion from
production well 683 (TsDN-4) i,n 1966 (at an 85 percent concentration of
water having a density of 1.01 gm/cm3),
In 1971, free hydrogen sulfide was detected in oil emulsion samples from
the wells shown in Table 2. _
Table 1
~1~ ~~2) ~3) ~4) Te(65~1HUa(6~)
Bpea~R
- m ~ pa6ard 3axaaxa d ~a
~ 1IaTa ecrynae- cxaaMCx- eoA~ lto ~ o,
AHA D 9KCDJf}~- Y H5~ 1~O ~~~e- ~ et
~ a STat1N10 a=i a, NCC11E,q0- tLHB ~8- ~ p
o 's 4�~~ saHxs, ;panteA- a
~ C~E ~MtC ~~TN U v aE
4 20/II 1958 r. 80 20 197840 14 -
717 16/III 1959 r. 400 13 132970 -
936 20/XII .1955 r. 80 60 - -
1025 30/IX 1958 r. 190 31 - 20
- 1299 2NI 1959 r. 880 18 9500pp -
- 1301 18/IV 1939 r. 330 12 80000 8
Key : 1466 5f X I.1959 r. 400 11 - -
1. Well number 4. Time of well o,peration prior to
2. Date placed i.nto operation analysis, months
- 3. Injectivity, m3/day 5. Amount of water injected prior to
SRB detection
_ 6. Hydrogen sulfide concentration,
mg/liter
In 1970, periodic interruptions in oil preparation processes were observed
- at oil preparation facilities No 1, 3, and 5. Analysis of oil samples from
the faciliti~s, of fluid from the reservoirs and settling tanks, and of drain water
from stage I and IIsettling tanks est~blished that the samples of water and
oil contain a large quantity of inechanical impurities consisting of small
- crystals of iron sulfide deposits together with oil adsorbed to their
surfaces. A laboratory procedure was used to separate the precipitate
out of the oil emulsion and to deternnine the quantitative composition of
iron sulfide in it. The results are shown in Table 3.
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Table 2
Well Number Water L~ensity, Free Hydrogen Sulfide
gm/cm3 Concentration, mg/liter
684 1.005 17 ~
536 1.003 g
864 1. Ol g
1136 1.005 15
, ~
Table 3
1 ~~1..
Co~epHCa~xe, ~a/~
Mecto or6opa npo6 cynbc~x- ~exaxx- xecpre-
ApexaxtxoH eolt~t Ros Mce� ~yeoxxx(~npoAyx-
nesa (3 pxNecei~ Tos (5)
~ ~ 6 N3 OTC70ANHYOH I C?yJl~-
~ xN 402 10736 6551
' 78 976 3492
4~0 2356 8871
Hs orcto~iaaxoa II cry- 1868 - -
nee~a 64 788 l?Sl
740 5928 12320
Key: 13 140 587 -
1. Place of drain water sampli.ng 5. Petroleum products
2. Concentration, mg/liter 6. Froan stage I:settling tanks
3. Iron sulfides 7. From stage II settling tanks
4. Mechanical impurities
We can see from Table 3 that as the concentration of iron sulfides in drain
water increases, the concentration of petroleum products rises. Iron sulfides
- in settling tanks are contained in an intermediate layer--at the oil-water
interface. Iron sulfides are stable emulsifying agents, and they actively
corrode oil extraction equipment.
During 1971 the laboratory of physicochemi.cal analysis of the TsNIPR [not
further identified] analyzed the chemical coanposition of water from fluid
samples taken from oil wells, and it additionally determined the concentra-
tion of iron sulfide in the samples. ~
Iron sulfides in samples of oil emulsions fram Devonian wells exploiting
beds not containing hydrogen sulfide had a concentration from 0.1 to 0.82
mg%liter fluid, and from 1 to 5.6 mg/liter oil emulsion. The quantity of
59
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sulfide in fluid from carboniferous wells exploiting beds containing hydrogen
- sulfide varied from 24 to 63 mg/liter, while their concentration in oil
emulsion was from 122 to 220 mg~liter. The concentration of iron sulfide
in extracted fluid was determined on the basis of data from 959 Devonian
oil wells, and presence. of iron sulfides was detected in 161 of these wells.
- Fluids from Devonian wells belonging to oil extraction shops No 3 and 4 were
analyzed in 1977. Bed D1 was exploi~ed by 343 wells that delivered a product
containing water.
Iron sulfides were detected in 54 wells operating with injected fresh water. _
Iron sulfides were detected in fluids from 17 wells operating with injected
waste water.
Water samples from every flooded oil well of the "Tuymazaneft NGDU [not
further identified] are subjected to chemical analysis each year. Tables 4
and 5 shows chan5e in water mineral content and the concentration of water
in oil from wells in which free hydrogen sulfide was detected.
- Table 4
. ~1) (2) t3) t4) - �
~ , ' ~ Co/1ep~caxs~e
F
Z(ara o~t6opa A~ $ ~6~ c nb u-
npo6~t - o," ~ ~ cepoeo� Y ~
~ a e Aos me-
~ ~ o ~ v ` ` Aopona aesa
C�m 'Jo�x cf~
22/X 1963 r. ( ,06 38 - - -
8/X 1964 r. 1,04 65 - - -
13/1V 1965 r. 1,02 83 - - -
14/1X 1966 r. 1,01 84 - OGxapy -
~cexo(
28/II1 i967 r. 1,01 8? - ~ -
I S/I I I 1968 r. t.01 83 22,6 - -
16/VIII �1969 r. 1,02 83 21.6 - -
_ 18/Ia 1970 r. 1,026 77 3~.3 - - -
5/IV 1971 r. 1,031 81 24,7 He o6xa- 06xapy- -
26/XII 19T2 r. 1,046 87 19,5 py,~~d ~ DeHo
19/VI 1973 r. 1,056 92 14,7 > > _
4/V 1974 r. 1.Q4 92 7,0 s , -
4/VIII 197~ r. 1,025 94 10,5 ~ s
19/XII 1976 r. 1,038 96 7,6 ~ s -
27/XII 1978 r. 1.048 97 4,1 He o6Na-
pyHCeHo
Key:
1. Sampling date 6. Hydrogen sulfides
2. Water density, gm/cm3 7. Iron sulfides
3. Water concentration in December, $ g, ~tected
4.~ Oil yield, tons/day 9. None detected
5. Concentration
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Table 5
(1) (2)~ E3) (4) _
$ q : ~ Co.uepncaxHe
_ ~ ~ e,
I[ara oT6op~ ~ y Y~~
npo6~ ~ a m a r cepoeo- c n ~ J
o~ a~` Aopo,�a noe xce-
~ nesa
r'�3 pa~ -
C~ Uoa
8/III 1962 r. 1.15 83 1-`
26/XII 1963 r. 1,07 81 ~ I - -
29/III 19G5 r. 1,OG B hoxcepeaux~~(10)
13/IX 1971 r. 1,01 98 2,5 O~Hap~~ OGHapy g
� HceKa ~eeo f )
17/V1 1972 r. 1,02 99 O,OI I f , -
8/VIIt .1973 r. 1,03 O~cp,~aHne TeKyntero pee~oHr~11)
2~/I 19T4 r. 1,04 98 3,8 He oGHa- 06napy-
PYxceso xceH
_ 19/I V 1975 r. I.OG 97 9.1 s( 9) s~8 )
2/ViI 1976 r. 1,04 98 5,5 s ~
2/I 1978 r. 1,05 99 2,3 s He oGna-
PYmex~g~
~Y =
1. Sampling date 6. Hydroqen sulfides
2. Water density, gm/cm3 7. Iron sulfides
3. WatPr concentration in December S. Detected -
of i-th year 9. None detected
4. Oil yield, tons/day lu. Undergoiiig corrosion-proofing ~
5. Concentration 11. Awaiting current repairs
Well 683 went into operation in 1955, producing waterless petroleum. After
8 years of operation well 683 began to be flooded quickly by a mi.xture of
reservoir water and injected fresh water. Change in mineral content of the
water over the years of operation, the concentration of water in December
of each year, the oil output, and the presence of iron sulfides and hydroqen
sulfide are shown in Table 4.
Well 864 went into operation on 5 July 1953, producing waterless petroleum.
Beginning in 1962 it was flooded by a mixture of Devonian water and inject~d
fresh water. Change in mineral concentration of the water over the years of
_ operation is shown in Table 5.
The density of Devonian reservoir water is 1.19 gm/cm3. As injected fresh
water encroaches, water mineral content decreases in the oi~ wells, while
encroachment of injected petroleum refining waste water (density 1.1 gm/c�cn3)
causes ~vater mineralization to increase once again.
The example of wells 683, 864, and others shows that as waste water approaches
freshened water at the oil wells, free hydrogen sulfide and iron sulfide are
not detected for some ti.me in the water, after which iron sulfides once again
appear in oil emulsion samples.
61
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Table 6
(1') (2) r~t (4) c~~ _ -
r� = Cosep;icaH~ie
_ ~ d.. ~ - ~
(6) (7)
11ara orGopa ~ ti ~ ~ ~
npo6~ - a~ o ^ c}�n~i~-
~ o o`~ ~ ~ u ~`O~Aa Anesa e
m c.) a�o ~ ~
2/!II 1967 r. 1,165 26� - -
- 26/[:K 1967 r. 1,12 7~ - _
12/V ,1968 r. 1,06 87 4g - -
29/! V,1969 r. 1.015 98 10 - -
SN ~ 97o r. 1.b02 95 10
13/IX 1971 r. 1,003 97 8 15,0 06HapyEB)
20/1X 1972 r. 1,004 95 IK 06Hapy~ )~eHo
2l/~'III 1973 r. I,OOC g8 F,h ,
28/I I I 1974 r. 1,005 94 4.2 ~ ,
17/I 1975 r. 1,00~ 92 5.7 a b
19/ti 1976 r. 1.OOS 96 4.4 L s
! 0/XII 1977 r. 1,002 98 3,8 a ,
*Water detected in March.
Key:
1. Sampling date 5. Concentration
_ 2. Water density, gm/cm3 6. Hydrogen sulfides
3. Water concentration in December 7. Iron sulfides ~
of i-th year 8. Detected
4. Oil yield, tons/day
_ Well 1163 went into operation on 30 April 1954, producing waterless
petroleum. In 1967 it began to be flooded by a mixture of Devonian water
and injected fresh water. Change in water mineral content is shown in
Table 6. _
Free hydrogen sulfide and iron sulfides were detected in fluid extracted by _
vrell 1163. The concentration of sulfite ions in the water decreases rapidly
- from 575 mg/liter (1972) to 159 mg/lit~r (1976), G~hich indicates occurrence
of oxidation-reduction processes in the bed due to the vital activities of
sulfate-reducing bacteria.
During 1978 free hydrogen sulfide was subjected to quantitative analysis in
gases at the outlet of the KSSU-1.3, in which Devonian oil is subjected to
separation, and in compressor stations (KS) No 5 and 10, where gas is sorbed
from Devonian oil by oil extraction shops No 3 and 4: -
Hydrogen sulfide was detected at quantities of 9.4 gm/l00 m3 gas at the
KSSU-3 (oil extraction shop No 3) ,~:0. 7; gm~i00.�m3 gas at KSSU-1, 6. 5 gm/
/100 m3 at KS-10, an3 3 gm/100 m3 gas at KS-5. T'hirteen grouped devices
of oil extraction shop No 3 were analyzed. Free hydrogen sulfide was de-
tected in gas from Devonian wells 1163, 1165, 1216, 857, 855, 776, and 1555.
62
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Heightened corrosiveness of petroleum refining waste water and frequent
ruptures of water pipelines have been noted in recent years; this is
_ apparently associated with presence of SRB in the water, and of sulfurous
compounds--products of bacterial contamination of the oilfield.
~i, .r ,
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),
1980
11004 ~
~ CSO: 8144/1367
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FUELS
UDC 622.276.8
METHODS FOR DEHYDRA.TING, DESALINIZING OIZ FROM GEORGTAN SSR OILFIELDS
- Moscow NEFTEPROMYSLOVOYE DEIA in Russian No 4, 1980 pp 34-35
[Article by R. K. Kl:abi.bulina]
[Text] Oil from the Samgori and Teleti oilfields forms poorly stable,
readily decomposable emulsions; this is why demulsification studies were
conducted with 9:1 mixtures of such oil. Dehydration and desalinization
were performed therm~chemically in one stage in a laboratory demulsifying
- device. F~nulsion models were prepared from waterless oil and reservoir water.
In all experiments, the initial oil mixture contains 10 percent water and
798 mg/liter salts.
Oil mixtures from the Samgori and Teleti oilfields can be completely dehy-
_ drated and desalinized by the laboratory device down to trace quantities of -
salts (2-4 mg/liter) in a single thernachemical step at a temperature of
40-50�C; settling time is 2 hours, and demulsifier consumpfiion is 10 gm/ton
(Table 1).
- At the oilfield, demulsification can be performed in a field reservoir
without heating, since the oil temperature at the well mouth is 70-fi0�C.
The oil mixture passes thraugh mother liquor beneath a layer of reservoir
water, and then it is settled for 2-4 hours. The demulsifier (10 gm/ton)
should be fed into the oil line closer to the wells. Oil prepared in this _
fashion can be sent for refining without additional processing.
Thermochemical and electric processing methods involving one and two stages
at a temperature of 80�C and a demulsifier consumption rate of 100-200 gm/ton
were used to del-~ydrate and desalinize oil from the Supsa oilfield, which is
distinguished by high emulsion stability. The experiments were conducted in
the laboratory with a natural emulsion containinq 20 percent water and
12,540 mg/liter salts (Table 2).
- When the oil was processed in a single stage by the thermochemical method,
where the demulsifier consumption rate was 200 gm/t~n and settling time was
_ 2 hours, the water concentration of the oil was 0.29 percent and salt concen-
tration was 286 mg/liter. Two-stage nrocessing by the same method (demulsifier
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Table 1
- ~1) (2a (3) ~
- 1oGaeha TeMneparypa,�C I(avecTeo o6pa-
p nc3yynb- d4 (5)~, (6) 6m~aHNOH -
a raTOpa c~. ~ }~e~TH'
o (1HC0:1- ~K a a x T~ _
a Hax r c� oe ~8~ " ~ j9)
e 44~~~, K~$ ~~=r_ t~- O~ ~ t= *a.cCi~
p o T: O$O u u u a
^ z~r m l~~! m C V V I- l: G O e( CJ ~
O O - ~ O =
U ~
I 0 30 30 30 0,4 122
2 !0 30 30 30 - 1(
- 3 20 30 30 30 - 2
4 0 40 40 40 0,3G Fs8
5 10 40 40 40 - 3
6 20 40 40 40 - 2
_ 7 0 50 50 50 0,2 26
R ] 0 50 50 50 - 2
9 20 50 50 50 - 1,5
* Quality of oil after 2 and 4 hours o~ settling was the same.
Key:
1. Experiment number 6. Of settling
2. Amount demulsif?er (Disolvan 4411), 7. Quality of processed oil*
_ added, gm/ton 8. Water concentration, $
3. Temperature, �C 9. Salt concentration, mg/liter
4. At which demulsifier was added
to oi.l
- 5. At which oil as washed through
water layer
consumption--200 gm/ton) decreased the salt concentration in the oil by
approximately a factor of 2(122 mg/liter); however, the water concentration
- of the oil increased to 1.08 percent due to emulsification of the rinsing
water.
With combined processing (where the first stage was thermochemical and the
second was electric), the oil contained C 26 percent water and100 mg/liter
' saltis (see Table 2, experim~nt No 3). ;
More-extensive preparation of the oil (resulting ir_ a salt concentration of
5- 7 mg/liter) can be achieved by the electric method, which involves two
. stages and a demulsifier consumption rate oz 20-30 mg/liter (see Table 2,
experiments No 6, 7). Oil with an initial salt concentration of about
100 mg/liter can be prepared in this way in electric desalinizing NPZ (ELOU)
devices.
Thus oil from the Samgori and Teleti oilfields may be brought to the re-
quired condition in a single thermochemical stage at a temperature of
= 40-50�C with a demulsifier consumption rate of 10 gm/ton. Oil from the
Supsa oilfield can be prepared and delivered to petroleum refineries in the
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Table 2
~1) (2) (5) (8) (9) (10)
Ka4ecrso Ficxo,~eot~ Ilo6aexa I(avecrso o6pa6o-
He~'T" o ~6~ ~7 ' TBHHOA Nl~TN
BptxA
( 3 ) N ( ) ~ ~ Crynexb, MeTO1t (1~ ) (1,2J
a~ o6eo~- ,-o ~E N ~ o6pa6orxx ~T K OA, o6~eott� coAep~ca�
u HCHHOC7b, ~ ~c C
Q a % I ~ G m ~ HORROCTb, HNG CO-
- T. o o�u a ~a~ o ~p 71R1~, ~ttt/d
~ a~ m
- 1 20 12540 100 - I, TOPNOXNHH9l~>13 2 - _
cxxi~
2 - 10 li, ~nexTpxuecxx~i( 4) 1 0,36 236
, 150 - 1, TepxoxxMxae� Z _ _
cxx~t
3 - 10 lI, B~IGTpHqECKHA 1 0,32 198
J 200 - I, repesoxxxxqe- 2 _ _
cxH~
~ 4 - 10 II, 3AEKTpNRCCKH~ 1 0,26 1pp
O,~h i00 20 5~~pMOxxdxqe- 2 0,30 72 _
5 - ]G !I, 3nexTpx4ecxNA 1 - 18 ~
3~ $ I, TCpMOXNM114C� Z ~~24 r,~
_ CK{1{t
g - 10 lI, 3ncy:Tpnycci;ni~ 1 - 12
- 20 5 I, 3nexTpxyecxHf+ 1 0,12 48
~ 10 II, 9netirpNqecx~~~ 1 - 7
30 5 I, anexrp~ecxxA~ 1 0,12 36
- 10 II, ~neKrpt~qecxzt~ 1 - ~
Key:
1. Experiment number 9. Settling time, hr
2. Crude oil quality 10. Processed oil quality
3. Water concentration, ~ il. Water concentration, ~
4. Salt concentration, mg/liter 12. Salt concentxation, mg/liter
5. Additives 13. Thermochemical
6, Demulsifier (Disolvan 4411), 14. Electric
gm/ton
7. Water, ~
8. Processing stage, method
group 1 quality category (water concentration--0.5 percent, salt concenta~a-
tion--100 mg/liter) after its processing by the combined method in two
stages (the first stage being thermochemical and the second electric).
More-extensive preparation of the oil, resulting in a salt concentration of
5-7 mg/liter, can be achieved with an ELOU and at a refinery in two electric _
stages under the following optimum conditions: temperature--80�C, electric
field gradient--2.5 kv/cm, demulsifier consumption--20-30 gm/ton, consumption
of rinsing water in stages I and IT--5 and 10 percent respectively.
' COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti (VNIIOENG),1980
11004
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UDC 622.276.8:665.62
HYDRODYNAMIC CHARACTERISTICS OF BASIC SETTLERS USING A RADIQACFI'VE ISOTOPE
Moscow NEFTEPROMYSLOVOYE DELO in Russian No 4, 1980 pp 35-37 -
[Article by Z. N. Yeremin, R. I. Mansurov, L. A. Pelevin (deceased),
G. K. Alpatov, and A. Ye. Pripisnov]
(Text] A modeling device was used to develop the most sensible desiqn of
horizontal- and vertical-flow settlers. Industrial models of OGD-200 and
OVD-200 apparatus were installed at the UPN-8 of the "Yuganskneft NGDU
[not further identified]. Flow structure in settling ta,~zks was studieci in
- the first stage using the radioactive isotope Br82. Figures 1, 2, and 3
- are diagrams of the apparatus, the location of Y-emission sensors, and the
_ distribution of oil flows at a productivity of 200 m3/hr.
The quantity of labeled oil (which was proportional to the area of the
response curves), recorded by the appropriate sensors, is arbitrarily ex-
_ pressed in figures 1, 2, and 3 by the length of the segments extending fran
the corresponding sensors. The peaks of the segments are connected to each
other by a line conditionally representing the front of flaw in the apparatus. .
Despite the great area of the longitudinal section of an OVD--200 settling
tank, oil moves relatively uniformly along the apparatus (see the curves
above points 8-16 in Figure 1).
A certain degree of irregularity may be elicited by inexact apparatus pro-
ductivity (the distributors are intended for a productivity of 300 m3/hr),
by insufficient density of the ascending flow (sparse positioni.ng of
openinqs and distributing pipes), the proximity of the phase separation
boundary, and the perturbations it experiences in response to ascending
_ emulsion flows. As the oil moves upward, the flows equalize and the front _
~f oil movement approaches a straight line (see the curves above points 5-8
in Figure 1}. In general the distributing devices support sufficiently
uniform distribution of flows in relation to the longitudinal section of the
apparatus. (The sensors at poi.nts 1-4 were the least sensitive, and they
failed to record passage of labeled oil due to the low triggering activity -
of the isotope.)
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9301700 17p0 ?1YI0 . 1700 ~i!XI p70C,~700 9f0
11 ~ ~ ' I ~ , ,
~ ~ ~ l ' J ~ 4 ~ ,~.~+y~~ --r~8
~9 =~11' ~Ti - ~1l �11 ~/4
i'ij-
Figure 1. OV~200 Settling Tank
~ l400 S100 SI00 5100 , J700
~a~., n
I ~ 4 3 ?
'B 7 ' 6 ;~S
li b 1 n i~~0 '~9
~~~es ~ D ' I~l4 i~~3
i / .
Figure 2. OGD-200 Settling Tank
- . . ~ -
4 3 1
� wB ~ ~i7 . ~~6 % l~f
/ i~!? ~ I JJ i R7 9
- I ~ ~ /3 ~ !4 ~ I/J
~Bao I s~ao s~oo s~ao I ~~a^ ,
. ~
Figure 3. SibNIINP Settling Tank
An analysis of curves obtained for the OGD-200 settling tank (see Figure 2) �
would show that the highest rate of flow persists in the central and lower
parts of the settling tank. In one experiment it was greater in the middle
part of the settling tank in the first 10 meters of the apparatus' length, :
while in another experiment it was higher in the lower part--that is, at the
water-oil interface. fIowever, these differences are insignificant. As the -
~ flow moves further--that is, in the second half of the tank, the flow rates
even out. Sensors in the upper part of the settling tank did not record
Y-emissions due to the low triggering activity of the isotope and the
lower sensitivity of the sensors. This does not mean that no movement
occurred there; it is simply somewhat slower thar. in the middle part of
the apparatus. In general the front of the flow in the OGD-200 is relatively
flat throughout the entire length of the settling tank. It may be assumed
~ that the intake device "quenches" the energy of the flow well and distributes
it with sufficient uniformness throughout the cross section of the settling tank.
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The nature of oil movement in the SibNIINP settling tank is about the same
as in the OGD-200 settling tank (see Figure 3), but the front of the flow
is much steeper. The contents are observed to flow through by the shortest
path--fro�n the top of the dividing wall to the outlet.
Weak moveqnent of oil is observed in the lower part of the settling tank at
the water-oil interface in the vicinity of sensors No 15 and 16. In 18 hours,
an intermediate layer 200-250 mm thick and 2-3 ma~ long that accumulated there
moved only 5 meters (from sensor No 15 to sensor No 16), though the flow ~
rate in the front part of the settling tank at the water-oil interface was
a good deal greater. This layer was detected by a portable SRP-2 radiameter,
and it apparently consisted of an unbroken emulsion and mechanical impurities
that adsorbed the isotope, since it exhibited high activity throughout this
time.
Figure 4 shows response curves obtained at the outlets of the three settling
tanks analyzed. For convenience in comparing the work of the settling tanks, _
relative values of T, which represent the ratio between the actually measured
time t and the theoretical time oil is present in the apparatus T, obtained
with a consideration for the position of the interface,are plotted on the
abscissa. Table 1 shows the results of analyzing the response curves.
~ ~
~ p n~3
(1) ~ A i'
~ ~ ~
S
.
p s _
la !s -.--ZQ. ti ( 2 )
Figure 4. Response Curves at the Outlets of OGD-200 (1), _
SibNIINP (2), and OV~-200 (3) Settling Tanks
Key:
1. T, Pulses/sec
2. Hours
Analysis of the obtained data (see Figure 4 and Table 1) established that
the SibNZINP settling tank has s anewhat worse hydrodynamic characteristics,
especially tn for the leading front. Isotope is first detected after 7
minutes, which is 15 percent of the theoretical time of the oil's pres2nce
in the apparatu.s T, while in the OG~-200 the isotope appears after 15
minutes (30 percent of the theoretical time).
The maximum flow rate vn in the SibNIINP settling tank is 2.28 times greater
than in the OGD-200. In this case the area of the "live" cross section of
the oil current in this settling tank is only 1.14 times smaller than in
the OGD-200. This great discrepancy may be explained mainly by the difference
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. Table 1
~1) (2) (3) (4) ~(5) ~6~ -
~8KTH42CKH2 3H9- r(pHD2,3CHHNC ~H8- ~
TIpON380� 9EHHA HptM2NN, CKOpOCT6, CJN~C
QTCTO~HNKN 'A~e7b- YPOBCHb ,q~ yeHliA ~=1j
HOCTb, 802H, dC -
Jt~~K
tn rY I tC T� I'y ~'C I vn ~ vr Vr
(7)C?z6~FiNNHlI 200 1,0 7 30 34,8 0,15 0,66 0,76 4,75 1,11 0,79 . -
( 8~I'II-200 200 0,6 16 ~36 36,8 0,30 0,68 0,70 2,08 0,92 0,69 '
~g~'0B.~1-20U 200 1,3 6 33 33,4 0,15 0,8~ 0,86 0,58 0,11 0,08 -
Note: vn--moment at which isotope first appears at apparatus
outlet; t~-time of maximum isotope concentration at apparatus
t~
E C~ tt
- outlet; f--- --mean time oil is present in apparatus;
E Ci
t~
T--theoretical time of fluid present; v~-maximum flow rate;
vr,t--mean rate of direct flowf vT---mean theoretical flow rate.
Key :
1. Settling tanks 6. Rate, cm/sec
2. Discharge, m3/hr 7. SibNIINP
. 3. Water level, meters 8. OGD-200 ~
4. Actual time values, min 9. OVD-200
5. Reduced T = t2/T -
Table 2
(1) (2) (3~'a6nxua 2
OceosHae rx~po-
RF~N3B0- 11NH8MH4ECKHE II8�
I~1cc~eAyeM~e annapaTd ~srreab' paMrrpgt
HOCTb,
.I~~~K I ~T ~ ~c
3ne~crponcrxA,parop
13I'-160 200 0,05 0,40 0,70
~ 5 ~ O~rcroAxfiti OI'-200 xox-
crpyxw+H KS o6~e,ux-
xexNS ~Caparoese~re� "
ra3s 230 0,14 0,4:i 0,78
~ ( ~ OTC70~iHiiK KOHCTpYRI1NN
Key: OB,q-200 200 0,15 0,85 0,86
1. Apparatus analyzed 4. lEG-160 electrodehydrator -
2. Discharge, m3/hr 5. OG-200 settling tank designed "
_ 3. Basic hydrodynamic parameters by "Saratovneftegaz" Association
- Design Office
6. OVD-200 settling tank _
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in the effectiveness with which the input devices operate--that is, their
capability for absorbing the kinetic energy of the incoming flow and dis-
tributing it uniformly over the cross section of the apparatus. The
difference in the times of appearance of maximiun isotope concentrations is
insignificant--2 percent. The average rate of movement of oil flowing
straight through the SibNIINP settling tank is 40 percent higher than the
calculated rate, while in the OGD-200 it is 33 percent higher. It should
be noted that the volume use coefficient vc for the SibNIINP settling tank
is 6 percent higher than for the OG~-200, mainly because of the lower volume
of oil present in the apparatus (owing to a high water level), and con- .
sequently smaller circulating eddy currents.
An almost symmetrical curve was obtained at the outlet of the OVD-200
settling tank, typified by vertical current mavement (see Figure 4), which
indicates good distribution of the emulsion along the length of the settlinq
tank. The time of arisal of m.aximum isotope concentration at the outlet of
the OVD-200 is 85 percent of the theoretical time. The settling tank con-
tains few d~ad zones, abaut 7 percent of the volume. T'he volume use co-
efficient for the apparatus is 86 percent, which is 10-16 percent higher
than for settling tanks in which the current moves horizontally.
To permi.t coqnparison of the work of the OVD-200 with that of other apparatus
of similar construction, Table 2 shows the basic hydrodynami.c parameters
of the lEG-160 electrodehydrator and the OCr200 settling tank, designed by
the "Saratovneftegaz" Association Design Office, analyzed earlier.
We can see from Table 2 that the OVD-200 settling tank doubtlessly holds
the advantage: For it, the time of arisal o� maximum concentration is
almost twice greater, which is close to the theoretical time of presence.
- The volume use coefficient is also higher.
Thus in comparison with other apparatus of simi.lar design and settling tanks
in which the current moves horizontally, the OVD-200 settling tank, in which
the flow is vertical, is hydrodynamically superior. Of the two horizontal-
flaw settling tanks studied, the OGD-200 holds a certain a3vantage in its -
hydrodynamic characteristics.
. -r
COPYRIC~iT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
upravleniya i ekonomiki neftegazovoy promyshlennosti
(VNIIOENG), 1980
11004
CSO: 8144/1367
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UDC 622.276.8
USE OF OIL-SOLUBLE DEMULSIFIERS IN FORM OF PETROLEUM SOLUTIONS
Moscow NEFTEPROMYSLOVOYE DELO i.n Russian No 4, 1980 pp 38-39
[Article by Ye. V. Miroshnichenko, T. I. Fedorishchev, A. S. Feliksov, and
S. F. Chernavskikh]
[Text] A procedure for using oil-soluble demulsifiers in the form of
petroleiun solutions has been introduced at the Zapadno-Surgutskiy and
Ust'-Balykskiy consumer centers. The~oil is prepared in two stages, using
an identical procedure. Figure 1 illustrates the process employed by the
TKhU-2 and TKhU-3 systems of the Zapadno-Surgutskiy consumer center.
Hydrated oil from the oilfield is degassed in the final separation stage.
Before the �inal separation stage, first a minimum quantity of demulsifier
and then hot drain water is introduced into the oil flow. The partially -
broken down emulsion is piped into crude storage reservoirs, where it is
separated into petroleum and water. Partially dehydrated oil is fed by
crude pumps into heaters (the bulk of the demulsifier is added before the
ptunps). The heated oil then passes into an emulsion breakdown unit. Before
- reaching the emulsion breakdown unit, a certain quantity of water from the
first dehydration stage is added to the flow of oil. After undergoing
final breakdown, the emulsion is placed into settling tanks, in which it -
is separated into commercial oil and water.
Devices created by the "Surgutneft"' and "Yuganskneft NGDU rPetroleum -
and Gas Extraction Administration~ to prepare and dose the working reagent
solution (UPR) are similar, and they consist of a centrifugal mixing pump
- with a low delivery volume, a piston dosing pump for the undiluted reagent,
an oil pipeline, a water pigeline, and reagent pipelines with flow meters
installed (see Figure l, 8). The characteristics of UPR apparatus are
presented in Table 1.
The working oil solution of demulsifiers is prepared in the following
fashion. Dehydrated oil flows by gravity from the settling tanks to the
intake of the centrifugal mixing pump, and undiluted reagent is fea in fro~m
the reagent receiving tank by the dosing piston pim?p. T'he ratio between
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~
v `
~ B ~ ~ 4 S 6
~ ~ D 1 1
~ ~ a
- / p ~ 4 f 6
Figure 1. Process Diagram for the TI~U-2 and TKhU-3 Systems
of the Zapadno-Surgutskiy constuner center: 1--the
final separation unit; 2--crude reservoir; 3--crude
pump; 4--heater; 5--emulsion breakdawn unit;
6--settling tank; 7--commercial reservoir; B--UpR;
I--hydrated oil from the Zapadno-Surqutskoye, _
Solkinskoye, and Bystrinskoye oilfields; II--reflux
water introduced before the final separation unit;
III--reagent working solution; IV--pure r_eagent;
V--oil after settling; Vl--gas; VII--industri~l
water; VIII-reflux water in the emulsion breakdown
unit; IX--drain water at treatment plants; X--oil
from commercial reservoir
Table 1
Equipment, Apparatus, "Surgutneft "Yuganskneft
Fittin s NGDU's iZChU-2,3 NGDU's UPN-S
Centrifugal mixing pump 3K-6 4MS-10-2x4
Delivery volume, m3/hr 45 60
Dosing piston pump ND-100/10 ND-40/25
Delivery volume, liters/hr 100 40
Receiving tank, m3 0.5 1.5
Flow meters on reagent pipeline
Primary DN~K-100 DN~K-160
Secondazy PV 10-1E PV 10-1E
Measurement limits, m3 4-10 4-10
- , reagent and oil is adjusted such that the reagent concentration in the working
solution would be not greater than 0.5 percent.
- The working solution is fed by the same pump to the first and second dehydra-
tion stages in a particular ratio. ~
To prevent possible settling of undissolved reagents out of solution, the
working solution must be subjected to turbulent movement at a rate v= 1-2
m/sec, which is achieved by selecting a pipeline of the appropriate diameter.
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Table 2
Parameter Magnitude
Inda.cators
UPN-8 TKhU-2
Unit's productivity in relation to
commercial oil, tons/hr 1300-1700 600-700 -
Water concentration of well product, $ 6C~?~ 30-40
Temperature, �C, of: -
Hydrated oil 35-38 18-20
Initial dehydration 38-40 27-30
Final dehydration 48-50 48-54
Drain water consumption by emulsion
- breakdown unit, m3/hr 160-310 100-170
Pressure at final separ~tion stage,
kg/cm?2 0.5 0.5
Pressure in settling tanks, kg/cm2 3.5-4 3-4
, � ,
W ~ .
. ' r
- 03 ~-y l~
.
` ; ~ r----~
0.4 ~v~ ~ ~v~.4
QJ n
0.1 ~ ,~,.--d ,~V , I~ J
.f i ~v1~~^~yt
D.! ~ r . /
- o z a s a ~v n a,~ ~a m tr z~
Time, days; 12-hr shifts
Figure 2. Extent of Oil Dehydration, W~, by the "Yuganskneft
NGDU's UPN-8 Unit (1,2) and the "Surgutneft NGDU's
TKhU-2 Unit (3,4): reagents are dosed in the form of
oil solutions, and in undiluted form: 1--first type
of reagent, oil solution, consumption 15-20 gm/tons;
2--first type of reagent, undiluted reagent, consumption
30-35 gm/ton; 3--second type of reagent, oil solution,
consumption 27-31 gm/ton; 4--second type of reagent,
undiluted reagent, consumption 45-55 gm/ton;1,4--daily
averages; 2,3--shift averagps (12 hours)
Research results established that working oil solutions of oil-soluble
demulsifiers are easily prepared at a concentration of 0.2-0.5 percent with
such a unit. In view of the limited solubility of demulsifiers in oil,
a certain fraction of them remains in pure form in the system, while
another fraction exists as a finely dispersed and rather stable emulsion.
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The unit can also be used to prepare water solutions of water-soluble
deznulsif iers .
Oil solutions of oil-soluble demulsifiers were aubjected to industrial
tests in preparation of oil by the "Yuganskneft NGDU's UPN-8 system and
the "Surgutneft NGDU's TKhU-2 system in order to evaluate the effectiveness
of their action. For comparison purposes, the reagents were also tested =
when dosed in undiluted form. The basic parameters of the oil preparation ~
process for the testing period are shown in Table 2.
The oil subjected to preparation is highly emulsified, and it is character-
ized by relatively high density (0.87-0.89 gm/cm3) and viscosity (30-40
centistokes at 20�C), and a high concentration of tar (9-10 percent) and
asphaltenes (3-4 percent). -
Figure 2 shows the results of testsrun with the demulsifiers. For the
UPN-8, unit consumption of the first type of reagent, dosed in the foxm of _
an oil solution, is twice lower than when the solution is dosed in undiluted
form (15-20 gm/ton as opposed to 30-35 gm/ton respectively), while for the
TIQzU-2, consumption of the second type of reagent is an average of 1.7 times
lower (27-31 as opposed to 45-55 gm/ton), given simultaneous preparation of
higher-quality oil. .
This procedure for dosing oil-soluble demulsifiers in the fonn of oil
solutions has been recommended for extensive introduction at West Siberian
oilfields.
' . i-1; .'r.4~
_ COPYRIGHT: Vsesoyuznyy nauchno-issledo~atel'skiy institut orqanizatsii, ~
upravleniya i ekonomiki neftegazovoy promyshlennosti =
(VNZIOENG), 1980 -
11004
CSO: 8144/1367
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FUFLS
' UDC 622.276.8
OIL PREPARATION AT SCUTHERN OILFIELDS OF PERMSKAYA OBLAST
Moscow NEFTEPROMYSLOVOYE DELO i.n Russian No 4,.~.984 pp 39-40 _
[Article by M. G. Isayev and L. M. Shipiguzov]
[Text] Oil in the fields of southern Permskaya Oblast is heavy~ highly
viscous, and it has a high concentration of resins and asphaltenes.
- Moreover the structural complexity of these oilfields is compounded by a
number of isolated uplifts and structures. As a result the oil collecting
systems are drenched, and it takPS 2-20 hours and more for emulsion to
reach the central collection points.
- The stability of water-oil emulsions depends on the~.presence and state of
natural stabilizers i.n the oil. "Aging" of the emulsion proceeds with
time, and it is practically completed after 20-24 hours. In this case
emulsion "aging" proceeds slowly as asphaltic-resinous components dominate
in the stabilizer composition, and the reverse is truE when the isopropanol
fraction--that is, the "paraffin" component--dmninates.
The "paraffin" component dominates in oil stabilizers of Permskaya Oblast,
having a concentration from 45 percent (Osinskoye oilfield) to 79.5 percent
(Kamennolozhskoye oilfield); consequently emulsion i.n Permskaya Oblast
exhibits a tendency for fast "aging"--that is, stably formed emulsion
reaches the central collecting points. High temperatures (up to 60-80�C)
- and high demulsifier consumption (up to 150-200 gm/ton) are required for
breakdown of this emulsion by the thermochemical method. Under these condi-
tions a combined process of oil collection and preparation plays a great
role in preventinq "aging" of the emulsion; also important are early intro-
ducticn of the reagent and utilization of the qas-hydrodynamic effect.
~ It was established in laboratory research that when the time of contact
between the demulsifier and emulsion is increased, a positive impact is
achieved; in winter, however, this impact is not enough to insure preparatory
removal of water. The temperature of the process plays a significant role
in this case (Figure 1) .
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IS %
~
10
i
j
U .
_ ~ 1'~~
�
1 '
J
if! CU QO !#Y /1!l IXIy..'.'r
~--~1 n-d~l -----~u~l')
Fiqure 1. Concentration of Residual Water in Oil From the
Osinskoye (I), Mayachnoye (II), and Nozhovskoye
Oilfields (III) After One Hour Settling Time,
Depending on Surfactant Dose, at Temperatures
of 5 (1) , l0 (2) , 17 (3) , and 20�C (4) -
Key: -
1. gm/ton
G W, %
100 3
80
60
40
?0 ~
~0 ZO 40 6 80 -
o.__.o , -
~ ~ 4, t/(Z )
Figure 2. Dependence of the Dynamics of Water Reatoval From
30 Percent (I) and 6G Percent Emulsion (II) on
_ Initial Water Concentration at Temperatures of
5 (1) , 10 (2) , and 20�C (3) -
Key:
1. gm/ton
Thus for oil from the Osinskoye and Mayachnoye oilfields, a reagent dose of
up to 150 gm/ton must be used to separate emulsion at 5�C; this dose does
not produce a result with Pavlovskoye oil, and even a dose of up to 300 gm/ton
is not enough for Gozhanskoye oil. Oil from the Nozhovskoye oilfield
separates at as low a dose as 6U gm/ton, but the quantity of water that -
separates out is insignificant.
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Raising the tamperature has a positive influence. At a temperature of 10�C,
emulsion from the Mayachnoye oilfield begins to separate at a surfactant
dose of 60 gm/ton; in order to achieve separation of Osinskoye oil at this
dose, the temperature must be raised to 17�C. Raising the temperature to -
'l~�C reduces the dose required for Nozhovskoye oil to 40 gm/ton.
The initial water concentration also has a great influence (Figure 2). When
a reagent dose of 20 gm/ton is added, emulsion fran the Gondyrevskoye oilfield
separates; when the water concentration is 30 percent, a third of u,r
emulsified water separates out of the emulsion, while at 60 percent more than
half of the water separates out. As the surfactant dose increases, this
difference first rises and then declin~s, while the concentration of
_ residual water in settled oii levels out.
Prolonged contact between the .reagent and the emulsion reduces the amount
of reagent needed; hawever, to acquire quality standardized oil at tempera-
tures up to 20�C--that is, by means of in-pipeline demulsification, the
settling time must be 6-10 hours, since the oil is highly viscous and the
difference between the density of water and the oil is insignificant.
At the same time up to 80-90 percent of the water settles in the first
- 15-30 minutes (Figure 3). Consequently the settling time is governed by
the rema.ining finely dispersed fraction of emulsified water, which is of
signifi-:antly lower volume.
c~
/
d0 ' Z
~
yo ~
r
o ~ -
O.IS O,S /0 ,1S 1,0 "
~ C, hours
= Figure 3. Dynamics of Water Settling Following Early
_ Reagent Introduction (t = 20�C) for Oil Fran the
Osinskoye and Kuyedinskoye Oilfields (2)
When the emulsion is allowed to settle at high temperatures (4~-60�C) and
reagent is introduced early, settling time could be decreased to 1.5-2 hours
while decre asing reagent consumption by 3Q-40 percent. Thus when thermo- -
chemical dehydration is i.nvolved, oil of the Kuyedinskoye group requires a
surfactant dose of 120 and 150 gm/ton (at 60 and 40�C respectively). By
introducing the reagent into the eollection system and dumping the water
beforehand, we can reduce the reagent dose to 70-30 gm/ton (at the same -
~ 78
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temperatures). F'ield tests conducted at the Kuyedinskaya TKhU [not fL~rther _
_ identified] in 1976-1978 confircned the lak~oratory re~ults indicating that
the most sensible T:ethod for prepa~ing heavy oil in Permskaya Oblast is
an integrate~j method combining early reagent introduction, preliminary
water dumping, and subsequent settling at high temperatures.
IZ the first tests, the reagent was introduced at the intake of the crude
F~ump. Samples taken from reservoirs of different deposits and their mixtures
shawed thatstably formed emulsion having an aggregate stability equal to
93 percent was reaching the TKhU. Separation of water was not observed in -
the crude reservoir. When reagent was introdu~ed and the emu].sion was _
passed throuch the pump, the aggregate stability dropped by a factor of 20.
- With this method, quality certified oil (with a water concentxation less -
. than 1 percent) was obtained at reagent doses of 120 gm/ton and higher,
whi;:h corresponds to the dose determined in the laboratory. However, in
all cases the oil leaving the settling tanks contained aggregate-stable
water--that is, water in indestructible protective globu.tes. Recirculation
_ of hot drain ~~ater did not produce any results in this case.
Af~er the point at which reagent was introduced was moved to the clistribution
' manifold, the degree of emulsion breakdown increased dramatically, but the
reagent dosage remained at the 100 gm/ton level. Once again water was ob-
served to pass out of the settling tanks in protective globules. Water
separation proceeded weakly in the initial discharging reservoir, and re-
circulation of hot drain water improved the results insignificantly.
_ Early r�eagent introduction was initiated in 1978 in the Kuyedinskoye group
' of oilfields, Dosing was performed at the Gozhano-Shagirtskc~ye (DNS-1) -
and Gondyrevskoye (DD?S-4) oilfields, such that the two main wings of the
collection sy:tem were aff ected. Oil from th~ Kuyedinskaya area remained
untreated; it passes to the TsPPS [not further identified] directly from
- the GZU (not further identified], and it collects together only at the
swit~hing unit.
y An analysis was l~erformed on samples taken from the collection system and
tne TKhU (see table).
As we can see from the tab le, introduction of the reagent at DNS-1 is in-
sufficient.; the two BR-2.5 blocks could not provide a large enough dose
to break down the emulsior_ (55-00 gm/ton). When oil was added at the
Byrkinskoye and A1'nyashskoye deposits, the dose dropped to 45 gm/ton, ~
while the acgreqate stabilitl was 20 percent--that is, complete emulsion
br.eakdown was not achievad. Addition af oi1 in the Krasnoyarskaya area -
decreased the dose and the degree of emulsion breakdown even more. Thus
em~~l:-inn tha.t was less than one-th~rd broken down entered the distribution
maniFold. A reager_'~ dose ef 47 gm/ton at the Gondyrevskoye oilfield almost -
completely broke down the emulsion, which is also close to the result of
the laboratory studies (35 gm/ton).
79
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~
Sampling Point (in Reagent Reagent- Emulsion Aggregate
Cnllection System Consumption ~ulsion Water Stability,
and TKhU) gm;~ton Contact Concen- $
Time Hr tration $
DNS-1 at reagent intro- '
duction point* 55 23 74
From the Gozhan TsPPS
reservoir to junction of
DNS-3** 45 1408 36.5 20
From Gozhan-TsPPS reservoir
to TsPPS manifold 23.5 16.5 40.2 73
From Gondyr'-TsPPS reser-
voir to TsPPS manifold 47 6.3 40 7
From Kuyedinskaya area
reservoir to TsPPS manifold Net 21 gg
Crude fro~m manifold, after
mixing of flaws 21 35 58
Crude after introduction of
_ reagent (without and to-
gether with reflux
- water) 117 0.2 55 1.4
_ * Gozhano-Shagirtskoye oilfield.
Krasnayarskaya area.
Mixing of the reagent-treated flows with untreated oil from the Kuyedinskaya
area produced an emulsion having an agyregate stability of 58 percent--that
is, almost h.~lf of the emulsion was broken down with a total reaqent dose
of only 21 gm/ton. Additioz~al. reagent resulted in almost complete break-
down of emulsion, both wit,hout circulating hot drain water, and with
circulating water. Consequently extensive emulsion breakdown was achieved
by partial introduction of reagent into the collection system and additional _
introduction at the manifold. While introduction of reagent o~::ly at the
manifold resulted in a three-time decrease in the aggregate stability in
10-12 minutes of contact, additional introduction of reagent into pretreated
emulsion reduced the aggregate stability by 40 times. However, significant
stratification of the emulsion was not observed at 13�C (without circulation
~ of hot water). Returniny water raised the temperature of the flow by 5�
and resulted in intensive separation of water. Further passage of the
emulsion through the TKhU system was accompanied by its breakdown in
approximately the same proportions as seen with introduction of reagent at
the TKhU, except that oil not containing aggregate-bound c~~ater and satisfying _
the appropriate commercial quality requirements left the settling tanks.
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Thus use of an integrated method significantly raised oil quality, and
further research on the production process revealed a way to reduce reagent
consumption to 85 gm/t and limit its introduction tojust the collection
system alone. In this case almoat 70 percent of the emulsified water ie
separated at the initial dumping stage.
. .r
COPYRIGHT: Vsesoyuznyy nauchno-i~sledovatel'skiy institut organizatsii,
upravYeniya i ekonomiki neftegazovoy proanyshlennosti
(VNIIOENG), 1980
11004
CSO: 8144/1367
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FUELS
UDC 622.276.8
COBIDITIONS FOR DEHYDRATION OF HIGHLY VIS COUS OIL USING HYDROCARBON DILUENTS -
Moscow NEFTEPROMYSLOVOYE DELO in Russian No 4, 1980 pp 42-43
[Article by M. Yu. Tarasov] ~
~ (Text] The highly viscous, heavy oil from the Russkoye oilfield forn~s
stable water-oil emulsion which can be extensively dehydrated at high
demulsification temperatures with the use of a significant dose of de-
mulsifier. One of the ways for improving demulsification of Russkoye oil
is to mix it with light hydrocarbon diluents that reduce the viscosity ar:-~
density of the well product.
A rational experiment planning method* was used to reduce the duration of
experiments involving the broad range of parameters influencing dehydration
(concentration of the diluent in the mixture, temperature, the water concen-
tration in the oil, the dose of the di.mulsifier, and so on). An experimental
schedule was compiled foreseeing 25 experiments involving different combi-
nations of quantitative values of six independently varying parameters:
oil water concentration (W = 10, 20, 30, 40, 50 percent); emulsion dehydra-
tion temperature (t = 20, 35, 50, 65, 80�C); concentration of hydrocarbon
diluent in oil phase (C = 0, 5, 10, 15, 20 percent) ; demulsifier dose
(Cp = 20, 40, 60, 80, 100 gm/ton of oil) ; emulsion mixing intensity during
preparation (n=500, 1,000, 1,500, 2,000, 2,500 min'1) ; time of contact
between emulsion and demulsifier (T = 10, 20, 30, 40, 50 min).
Oil sampled from the mouth of well 44 of the Russkoye oilfield was analyzed.
The water concentration of the initial oil was 1.9 percent. Water-oil
emulsions were prepared for 10 minutes in a 0.15�10"3 m3 propeller mixer
- at 20�C. The aqueous phase consisted of 2 percent sodium chloride solution
in distilled water. The emulsion was kept at dehydration temperature
thermostatically in the mixture for 30 minutes. Mixing intensity was
* Protod'yakonov, M. M., and Teder, R. I., "Metodika ratsional'nogo
- planirovaniya eksperimentov" [The MethQd of Rational Experiment Planning], ~
Moscow, Izd-vo Nauka, 1970, p 75.
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500 min-1. Then hydrocarbon diluent (brand 70-100 petroleum ether) was
added to the emulsion, and the demulsifier (Separol 5084) was dosed with a
microsyringe in concentrated form. The diluted emulsion was processed by
the demulsifier for a particular amount of time, after which it was
drained into a glass calibrated settling tank. After being allowed to -
settle for 60 min, samples were taken from the upper part of the settling
tank; these samples were used to determine the residual water concentration,
W~, by the Dean-Stark method.
Treatment of the experimental data produced the dependence of the concentra-
tion of residual water in the oil on factors of influence; the data were
successively grouped on the basis of the parameter with the strongest
action, after which the raw data were average3 and correc~ted to the mean
value of the parameter with the strongest action. The following dependence
was obtained:
WUCT- ~
0,033-~-2,34 � 10-~ I +2'5 � 10-3X
X( CP-30) 2-~-8,94 e~cp (-2,9 � 10-3 ~ n-1500
-0,59 C-{-14,9 exP (-0,144 ~ t-42 ~ ) - 4,85:
e
~
- 6
~
' S
~ 4
~
> 1
~
?
/
~ S A7 !S
.K
Dependence of the residual concentration of water by
wcight, Wp~, in emulsion from the Russkoye oilfiela
(water concentration--30 percent, temperature--50�C,
demulsifier dose--40 gm/t)on concentration of hydro-
c~rbon diluent by volume, C.
The formula can be used to quantitatively evaluate the domain within which
dehydratioi~ o� the analyzed oil i.s the most extensive. This domain is
bounded by a temperature range of 40-60�C, demulsifier doses of 20-40 gm/ton
- oil, and 15-20 percent concentrations of diluent in the oil phase. We can
see frc~m the fonnula that the initial water concentration within ~he
emuls~ion does n~t have a significant influence on the residual concentra-
tion of water in oil. The most stable emulsions, for which the mean water
globule diameter is 1.5-3 u, are obtained at a mixing intensity of 1,500
min'1. As the mixing intensity is increased (above 1,500 min-1), globule
83
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� ~ocT ~ �m' . npR Cp, z/r Hetprt(l~
q0 10 I 20 I 30 I 40 I 60 I 70 I 80
15 I 0.57 I 0,34 I 0,53 I 0.26 ICn
a~l 0,31 I 0.19
- 20 0,12 0,39 0 0
Note : At Cp = 50 gm/m, W~ = 0. ~
Key:
1. Wp~, at C~ , gm/ton oil
2. Trace
diameter grows, which is probably associated with crowding of the globules
against the wall of the mixer. Consequently it would be difficult to
achieve extensive dehydration of the analyzed oil without adding hydrocarbon
diluent.
A number of additional experir,lents were conducted, using the method de-
scribed above, in order to clarify the quantitative values for the
demulsifier doses and the concentrations of the i~ydrocarbon diluent at ~
which dehydration is most effective. The dehydration temperature was
50�C, mixing intensity during emulsion preparation was 2,500 min'1, the
time of contact between emulsion and demulsifier was 20 min, and the con-
centration of water in the emulsion was 30 percent.
The results of the experiments are shown in the figure and table.
Thc an,ily:;.is results demonstrate the possibility for extensive dehydration
of the analyzed oil when the concentration of hydrocarb~n diluent in the
oil ~~hase is 20 gercent and higher. In this case the optimum demulsifier
dose is 30-50 gm/ton, ai~d the optimum dehydration temperature is 40-60�C.
,
Thus the rational planning nethod makes it possible to significantly reduce
the number of experiments in the effort to find the domain within which
the most effective dehydration of oil occurs.
Use of light hydrocarbon diluents significantly improves demulsification of
oil from the Russkoye oilfield.
~f~!n, ~r -llooal
COPYRIGHT: Vsesoyuznyy nauchno-issledovatel'skiy institut organizatsii,
- upravleniya i ekonomiki neftegazovoy promyshlennosti
(VNIIOENG), 1980
1
1
11004
CSO: 8144/1367 END
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