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8/15/2019 Production Operations (16pages)
1/1662 MARCH 1999 •
Most oil wells producing from the
Glauconite YY pool of the Lake Newell fieldin southern Alberta, Canada, have very
high flow capacities. Wellbore operations
are complicated by the slant-well configu-
rations, with surface angles of 45° increas-
ing up to 75° bottomhole and horizontaldisplacements in excess of 6,600 ft. After
discovery of the Countess upper MannvilleYY pool in 1989, a marine three-dimen-
sional-seismic program, shot in 1991,showed that the reservoir extended 1.25
miles underneath the manmade Lake
Newell. The reservoir was developed with
14 producers and one injector. Eleven of
the 15 wells were slant drilled from a padlocation where drilling begins at an angle of
up to 45° at surface (Fig. 1). The original
oil in place was estimated to be 15 mil-
lion bbl, with ultimate recovery estimated
at 8.8 million bbl. Primary production
began in January 1990, and water injectionwas implemented in July 1993.
Because of the reservoir’s high permeabil-
ity, most wells in the reservoir have high
productivity indices. Any pressure drop
within the system has a significant impacton productivity. All wells flowed initially,
but shortly after the initiation of water
injection, water cuts increased and artificial
lift was installed. Gas lift was selected
because of the availability of compressioncapacity, infrequent workovers, low operat-
ing costs, exceptional well inflow capabili-
ty, lack of wellbore restrictions for produc-
tion logging and pressure surveys, and lowrisk of a potential oil spill in an environ-mentally sensitive area.
OPTIMIZATION OPPORTUNITY
To evaluate waterflood performance, thereservoir was divided into three areas on the
basis of structure and net oil pay. Pressure
was maintained in Areas 1 and 2, but
increasing water cuts of 70 to 90% resulted
in steeply declining oil-production rates.The reserves-life indices (remaining reserves
divided by current production rate) of thesetwo areas were in excess of 15 years com-
pared with the desired 4 to 7 years. Cement-squeeze operations were performed on the
wells without success. A review of the pro-
ducing wells in Areas 1 and 2 indicated that
gas-lift optimization was necessary to
increase drawdown and oil production andto improve the oil-recovery rate. The Area 3
reserves-life index was estimated at less than
2 years. Therefore, optimization efforts were
focused on wells in Areas 1 and 2.
A study of the pressure drops in the sur-face system determined that increasing the
size of pipeline at the pad site would
reduce pressure drops and increase pro-
duction. However, the most effective meas-
ure would be to improve the downhole
artificial-lift system. The system review
also determined that adequate capacity
existed at the testing and battery facilities
to handle increased well production from
wellbore optimization.
OPTIMIZATION ATTEMPTS
A flowing-pressure-gradient survey was
performed on the most prolific well in thefield in September 1996. Subsequent tub-
ing-flow-performance analysis could not
match actual data with theoretical calcula-tions, indicating that the production-string
design and gas-lift performance were
not optimized.
Theoretically, for an efficient gas-lift
installation with 2.875-in. tubing, fluid pro-duction should have increased from 717 to
1,500 B/D of liquid (BLPD). This increase
could be accomplished by replacing several
gas-lift valves with valves that had differentoperating pressures. A coiled-tubing-de-
ployed system replaced the three existing
valves successfully in November 1996. The
well was placed back on production with a
minimal increase in fluid production to 850
PRODUCTION ENHANCEMENT OF
PROLIFIC, EXTENDED-REACHGAS-LIFT OIL WELLS
This article is a synopsis of paper SPE
48935, “Significant Production En-
hancement of Extended-Reach, Prolific
Gas-Lift Oil Wells—Case History of
Systematic Problem Resolution,” by
D. Hahn, SPE, D. Yu, SPE, M. Tiss, SPE,
R. Dunn, SPE, and D. Murphy,
PanCanadian Resources, prepared for
the 1998 SPE Annual Technical Con-
ference and Exhibition, New Orleans, 27–30 September.
P R O D U C T I O N O P E R A T I O N S
Fig. 1—Slant-well schematic: true vertical depth (TVD) is 3,380 ft, and measured depth(MD) is 7,200 ft.
8/15/2019 Production Operations (16pages)
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P R O D U C T I O N O P E R A T I O N S
• MARCH 1999 63
BLPD. A subsequent flowing-pressure-gra-
dient survey in January 1997 still showed
excessive pressure drop in the tubulars.
For the next 6 months, significant effortwas expended to obtain a reasonable expla-
nation for the differences between actual
and calculated tubing performance. Advice
was solicited from an international experton gas lift who also was unable to model
the actual performance with various nodal
analysis packages. Therefore, it was deter-
mined that some other unexplained phe-
nomenon was contributing to the problem.The following production-impairment
mechanisms were considered.
• Production/injection measurement
equipment.
• Hole in the tubing near surface.• Nonrepresentative flowing-pressure
gradient caused by production interference
from flow past the gauges.• Phase separation and stratification of
fluids (water, oil, and gas) in the tubing.All the metering was verified and
deemed to be providing accurate data. A
hole in the tubing near the surface was
ruled out because the flowing-pressure gra-dient indicated a definite gradient shift at
the gas-injection point. Wireline gauge
rings were run to confirm that no tubular
restrictions existed. Review of the flowing-
pressure-gradient results, with and withoutpressure gauges in the tubing (i.e., lubrica-
tor and sump), demonstrated that the
gauges were not interfering with produc-
tion; therefore, the gradients were deemed
to be accurate.Recent research and experiments on hor-
izontal- and deviated-well flow characteris-
tics indicate that phase separation in tubu-
lars can be an issue because higher-specific-gravity fluids will move at slower velocities
or even reverse the flow along the bottom
of the tubular. Because these slant wells are
a special application of an extended-reach
deviated well, it was postulated that theeffective flowing diameter of the tubing was
possibly smaller because of possible reverseflow of the heavier liquid phase on the low
side of the tubing. This effect would
increase pressure drops along the tubing.The tubing was replaced with 3.5-in. tubing
to obtain at least 1,450 BLPD; however,
only 1,130 BLPD was achieved, indicating
that the problem was probably of a different
nature and still not understood.
EMULSIONS AND DEMULSIFIERS
While trying to reconcile the underachiev-
ing gas-lift performance, discussions held
with the property team determined that theCountess YY crude oil tends to form tight
emulsions in the surface progressing-cavity
transfer pumps. The tight emulsions result
in significant pressure drops in the surfaceflowlines. The pressure-drop/emulsion
problem was being addressed through the
continuous injection of demulsifier
upstream of the transfer pump.
The design of a typical gas-lift mandrelintroduces the lift gas into the tubing flow
stream countercurrent to the liquid stream.
This action can create significant turbu-
lence in this area and cause significant
shearing/agitation of the liquid phases.These turbulent conditions could be the
catalyst that promotes severe emulsification
of the fluids.
Tests of emulsion samples taken at thewellhead revealed that they were very vis-
cous and stable. The viscous emulsified
flow regime created excessive pressure
drops within the wellbore that impededproduction. Surrounding wells are alsoprone to emulsions.
Several weeks after the August 1997
installation of larger tubing, a demulsifier
was introduced into the injection-gas
stream. After 2 days, the well respondedwith a very strong production surge. The
estimated rate was in excess of 2,830 BLPD.
The production spike would last for 2 to 3
hours then revert to its normal rate for 6 to
7 hours. This cycle repeated itself two tothree times every day. During these high-
rate surges, the surface piping at the well-
head vibrated vigorously and operational
problems were encountered with the sepa-ration and gas-processing equipment. The
demulsifier was a two-component blend of
active ingredients in hydrocarbon carriers.
The dry lift gas probably absorbed the
hydrocarbon carrier, causing the resultingthicker demulsifier active ingredient to
remain at the top of the annulus fluid.
Project economics dictated the installa-
tion of a chemical capillary string. The ded-
icated chemical-injection string allowsintroduction of chemicals where produced
fluids enter the tubing string, letting activa-tion take place before the fluids reach the
more turbulent region of lift-gas injection.
RESULTS
The initial chemical-injection rate of 5.3
gal/D was reduced to 4 gal/D after several
days. The production stabilized at 3,000BLPD. High wellhead pressures were caused
by surface piping restrictions that were recti-
fied in May 1998. A flowing-gradient survey
was run after the tubulars were upgradedand demulsifier was being injected through
the capillary string. The gradient surveydemonstrated excellent agreement between
measured pressures and pressures calculated
with the Hagedorn-Brown correlation.
Because the tight produced emulsions inthe tubulars impaired gas-lift performance,
a second well was upgraded in a similar
manner. Production increased from 380 to
1,775 BLPD, an incremental increase of 560
BOPD. The current rate is in close agree-ment with the theoretical predictions.
Subsequent to the introduction of this
chemical, no evidence of paraffin deposi-
tion within the tubulars has been seen.Dewaxing-related operating costs have
been reduced, and flow efficiencies
improved, probably because of increased
flowing temperatures. Also, with the
downhole injection of demulsifier, the useof the chemical for surface treatment at
the testing/transfer facility has been
reduced significantly.
Since July 1997, the oil-production ratesfrom the Countess YY pool increased 1,475B/D, from 1,825 to 3,300 B/D (even higher
than the previous peak rate of 3,000 B/D in
early 1994 shortly after the waterflood was
initiated). The perseverance in resolvingthe technical issues surrounding the poor
gas-lift performance of these wells has
improved cash flow and profitability of this
pool significantly.
SYSTEMATIC PROBLEM-
RESOLUTION CYCLE
The resolution of inadequate well-produc-tion performance occurred after several
iterations that followed a modified
Shewhart cycle. The four steps of this cycle
can be summarized as follows.
1. Plan: diagnose the problem, collectdata, determine changes, and develop an
action plan.
2. Do: execute the action plan to carry
out change.
3. Check: observe the results.4. Act: analyze the results. What was
learned? Do side effects or benefits still
exist? Was the plan successful? Repeat
cycle if unsatisfactory.During the entire process of arriving at
the most satisfactory solution for the issue
of obtaining production rates near the the-
oretical predictions, the multidisciplinary
team followed the systematic pattern forcontinuous improvement. This cycle was
repeated at least four times before the best
solution emerged.
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been peer reviewed.
8/15/2019 Production Operations (16pages)
3/16
64 MARCH 1999 •
Meters for measuring multiphase flow are
unique tools that allow measurement of
produced fluids (oil, water, and gas) with-
out separation into individual phases. Twodistinct and fundamental approaches to
multiphase-flow measurement exist. The
first includes no fluid separation, and the
second uses partial (hybrid) measurement.
No single multiphase-flow-measurement-system design or technology resolves all
multiphase-flow-measurement issues sat-isfactorily. Each approach has benefits as
well as shortcomings. Even with these lim-itations, worldwide use has increased.
Approximately 50 multiphase-flow
meters were in service in 1995; this num-
ber increased to approximately 150 in
1997. Subsea application was the majorreason for the original growth of the tech-
nology and is expected to be the dominant
driver in the future.
Most commercial multiphase-flow-meas-
urement systems have no level- or pressure-control equipment to maintain but do
include process-variable transmitters,
which generally are off the shelf with stan-
dard calibration procedures. However, mostsystems require some form of electrical
power and, in some cases, a controlled
environment (such as a control room) for a
flow computer. Because new electronic sys-
tems have been problematical wheninstalled in the field, Conoco was com-
pelled to test at the field level.
MPFM 1900VI DEVELOPMENT
The field-level performance-evaluation test
begun in late 1997 was the final step of adevelopment program started in 1992. A joint-industry-project (JIP) agreement
between Conoco Inc., Norske Conoco A/S,
and Fluenta A/S was reached in 1991 on a
program that spanned 2 years and consist-
ed of four development activities. The workresulted in Fluenta’s MPFM 1900VI multi-
phase-flow meter.
Previous testing of water-cut meters at
Conoco’s Grand Isle shore base in 1988indicated that “live” fluids (at bubblepoint)
affected the accuracy performance of many
instruments, causing them not to meet themanufacturers’ accuracy specifications.
This bubblepoint-fluid condition occurswhen pressure drops below the last separa-
tion pressure, which occurs as fluid flows
through pipes and fittings.
Conoco’s multiphase-flow test and vali-
dation flow loop outside Lafayette,Louisiana, was commissioned in March
1993. Its original objective was to validate
meter performance with produced fluids by
use of multiphase (liquid/liquid, liquid/gas,and liquid/liquid/gas), clamp-on ultrasonic,
water-cut, and any other technology with
potential operational and economic
improvements.
Testing of Fluenta’s MPFM 900V, theforerunner of the MPFM 1900VI, began in
April 1993. The project was to end by
January 1994 with the tests of the MPFM
1900VI. Because of unplanned events,
however, the flow-loop-test phase did notend until February 1997. The JIP test pro-
gram was planned to be completed after the
conclusion of field-level testing in the U.S.
Gulf of Mexico.
USE OF MULTIPHASE-FLOW-
MEASUREMENT TECHNOLOGY
The economic incentive to use multiphase-flow technology is derived from the initial
savings of weight and space on convention-
al platforms, providing instantaneous flow-
rate information, reduced maintenance,and more efficient detection of problems
associated with declining production. In a
subsea application, multiphase-flow tech-
nology becomes an enabling technology,
allowing measurements in an environmentwhere separators are unproved.
A business case was developed for thisfinal field test that assumed that average
daily production volumes from the plat-
form would be increased by 1 to 2%. It was
further assumed that this increase in pro-duction would come about because the
meter would allow production adjustments
with faster feedback from measurements,
decreasing the apparent decline rate; pro-
duction tests could be performed moreoften and for shorter periods of time; and
response to unplanned production-rate
changes could be faster.
METER DEVELOPMENT
The meter measures oil, gas, and water flowrates without physical separation of the well
stream. The nonintrusive, real-time, full-
bore instrument requires no bypass line and
no invasive mixing device. The meter deter-
mines fluid slip automatically and calcu-lates volume flow rates at actual and cus-
tomer-supplied standard conditions. Fluid
slip is the relative velocity between liquid
and gas phases in a multiphase system
where gas tends to flow faster than liquid.The measurement system includes a
capacitance sensor, an inductive sensor, a
gamma densitometer, a venturi meter, and a
system computer. The capacitance sensor isused to measure the permittivity of the
mixture and the gas velocity in oil-continu-
ous multiphase-flow situations. If the flow
becomes water continuous, the system flow
computer automatically selects the induc-tive-sensor signals to calculate the conduc-
tivity and gas velocity of the mixture. The
gamma densitometer is used to measure the
density of the flow stream. The flow com-
puter performs the analysis on the data andthe data are brought safely to the computer
by cables through safety barriers.
Principle of Operation. Measurement of
the flow is divided into two parts, fluid frac-
tions and velocities. Oil, water, and gas flow
rates are calculated on the basis of the mea-sured fractions and velocities. The permit-
tivity and density are different for each of
the three components of an oil/gas/water
mixture. If these permittivities and densitiesare known and the total permittivity and
density of the mixture are measured accu-rately, the fractions of each of the three com-
METERING MULTIPHASE FLOW
IN THE GULF OF MEXICO
This article is a synopsis of paper SPE
49118, “Application of the First
Multiphase-Flow Meter in the Gulf of
Mexico,” by Edward G. Stokes, SPE,
Conoco Inc.; Dennis T. Perry, PetroTraces
Inc.; Marshall H. Mitchell, Conoco Inc.;
and Martin Halvorsen, Fluenta A/S, pre-
pared for the 1998 Annual Technical
Conference and Exhibition, New Orleans, 27–30 September.
P R O D U C T I O N O P E R A T I O N S
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66 MARCH 1999 •
P R O D U C T I O N O P E R A T I O N S
ponents can be determined. For water-con-
tinuous mixtures, the inductive sensor is
used to calculate the fractions. The principle
is basically the same, except that conductiv-ity (not permittivity) is being measured.
Studies have shown that generating
gas/liquid flowing conditions without slip
is virtually impossible. Even if no-slip con-ditions could be generated artificially, slip
would reoccur a very short distance down-
stream of the mixing device (typically 5 to
10 diameters). The strategy for this system
was to find and develop mathematical mod-els that give dependable velocity measure-
ments under all slip conditions.
This system determines the velocities of
the large and small gas bubbles and the liq-
uid. The capacitance and inductive sensorscontain a number of electrode configura-
tions that are used to measure the velocities
of the large gas bubbles through crosscorre-lation. The velocity of the small gas bubbles
and the liquid is found from the differentialpressure across the venturi meter. When
the two velocity components are deter-
mined, they are combined with information
from the fraction measurements to calcu-late the individual flow rates of oil, gas,
and water.
FIELD TESTING
Initial plans called for testing of all wells for
24 hours at a set gas-lift rate to establish a
base condition. This test would be followedby another 24-hour test at the same operat-
ing conditions of choke size, pressure, and
gas-lift rate to evaluate repeatability. After
the first two series of long-duration tests,
test duration was determined by field-oper-ations personnel. Adjustments also were
made to observe, in real time, each well’s
response to conditional changes (i.e.,
choke diameter, gas-lift rate, or process-
system settings).
Meter Installation. The meter system was
installed with upward vertical flow.
Physical installation included a drip pan tocontain spills, block valves to allow work tobe done on the meter without depressuring
the whole platform, and manual sample
ports at the meter inlet. The multiphase-
flow computer was installed in the opera-
tor’s doghouse on the well-bay deck.
Safety Issue (Gamma Densitometer).
The gamma densitometer used at the test
site was rented from ICI Tracerco and used
cesium-137 as the gamma-emitting isotope.
The source-energy rating is 24 mCi, which
requires special handling and operatingprocedures and personnel training.
FIELD OB SERVATIONS
Separator-Discharge Sampling. The sep-
arator-sediment/-water sampler was not
used because a representative sample couldnot be taken during the dump cycle.
Because of the nature of on/off fluid flow, a
dump cycle would start with mostly water
and end with mostly oil. Although thedump rate was reasonably consistent, sam-
pling the dump cycle yielded nonrepeat-
able results. Instead, liquid samples were
taken manually at the inlet to the multi-
phase-flow meter.
Fluid Cloud-Point Problem. One well
was found to flow at close to its cloud
point. After several series of tests where
various wells were flowed through the
metering system, the indicated water cutfor all wells became consistently lower
than the manual water-cut samples.Inspection and cleaning of the meter cor-
rected the problem and returned the meter
performance. The capacitance unit had aparaffin deposit covering the liner surface,
which had to be cleaned to enable prop-
er operation.
Safety. To use a gamma densitometer in the
field, a licensing procedure had to be devel-
oped that included the following.
1. Permission from regulatory agencies
to proceed with the usage.
2. Removal from previous location.3. Transportation to field.
4. Installation and leak check.
5. Field training and maintenance.
6. Contingency planning and documen-
tation of Items 1 through 5.7. Roll-up plan for removal of radioactive
source after use.
Observations. Multiphase-flow metersproved to be more robust than anticipated,with no mechanical failures during the test
period. It was very difficult to acquire all
the required data consistently and accurate-
ly over different shifts and rotating person-nel. However, less than 10% of the data waseliminated for poor quality. The only main-
tenance problems were with software early
in the program and paraffin buildup when
testing close to the fluid cloud point.
The field performance of the meteringsystem appeared to be similar to the flow-
loop performance. Measurement repeata-
bility was demonstrated, except for the
consistent accumulation of paraffin found
throughout the test period for one well.The piping and electrical installations were
simple and straightforward, making thesystem easy to move at low cost.
Testing indicated that the duration of the
well test does not affect the relative perfor-mance of the meter compared with the sep-
arator. Projected 24-hour production rates
from the separator and multiphase-flow-
meter system were affected in some wells
by the length of the well test. Many wells do
not flow at the average daily rate constant-ly; instead, they appear to cycle.
At some point in each well, the multi-
phase-flow meter was subjected to instan-
taneous flow conditions below the meter’sspecified liquid-rate minimum. This was
caused by surging, where a liquid slug is
followed by an extremely high gas fraction
with very low liquid rates. This sluggingoccurred at regular intervals. The meter
was useful in establishing optimum gas-lift
rates through the relatively instantaneous
nature of its data calculation and display.
Issues for Future Use. Future use of any
new-technology multiphase-flow-measure-
ment equipment depends on the following.
• The absolute accuracy of multiphase-
flow-measurement systems must improve
to a maximum of ±5% at all conditions of
flow for gas, oil, and water.
• How the conflict that arises (becausethe method of determining a separator’s
hydraulic efficiency in the field often is not
specified) when comparing typical perfor-
mance between a separator and a new-tech-
nology multiphase-flow meter is resolved .• How multiphase-flow-measurement
accuracy is proved after repair, recalibra-
tion, or system change (i.e., level or pres-
sure).
• How one determines whether a meas-urement-system performance change might
have occurred during use (such as the wax-
buildup problem experienced during the
field test).• The U.S. Minerals Management Service
(MMS) custody-transfer requirements are
2% for sales of gas and 0.25% for sales of
liquids. Currently, multiphase-flow-meas-
urement technology cannot meet thesestringent requirements. The question is
whether multiphase-flow technology can
be improved sufficiently to close this gap
and be approved for fiscal measurement by
the MMS.
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been peer reviewed.
8/15/2019 Production Operations (16pages)
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• MARCH 1999 67
The main objectives of production logging
are to diagnose well-production problems
(such as inflow rates and entries of unwant-
ed fluids), supply information for reservoirmodeling, and provide data to optimize the
productivity of future and existing wells.
Determining the inflow profile of oil can
help plan a drilling strategy, formulate
cleanup methods for current and futurewells, determine drainage patterns, and
allocate production to sidetracks. Deter-mining the water-entry locations and posi-
tion of the water cone can provide a betterunderstanding of the reservoir water-trans-
port mechanisms and supply data for
potential workovers. Ultimately, use of the
results should improve the productivity
and long-term recovery from the field.Most of this discussion refers to
oil/water systems, with occasional refer-
ences to gas/liquid systems. Many of the
oil-/water-system results are applicable to
gas/liquid systems. In a horizontal well,whether it is a barefoot completion or com-
pleted with a cemented casing or slotted
liner, oil/water flow tends to be segregated
by gravitational forces.Along different sections of the wellbore,
the heavy- and light-fluid phases segregate
according to the following regimes: strati-
fied with a flat interface; stratified with a
wavy interface; stratified with a bubblyinterface; light phase slugging over the
heavy phase; or one phase existing purely as
bubbles in the other phase. Except for very
heavy oils, stratified flow is normal when
the holdup is significant (>20%) for both oil
and water and can occur for liquid flowrates ranging from 0 to more than 12,000
B/D. Whatever the density contrast betweenthe heavy and light phase, stratified flow is
more likely for flow in sections of wellbore
with deviations greater than 90° (i.e., down-
hill flow). Stratified flow with a bubbly
interface can occur with low water holdupsand is more likely as deviation decreases
below 90°. Slugging of the light phase can
occur at deviations of less than 90° and is
more common in gas/liquid flow. Flow
where one fluid phase is mixed as bubblesin the continuous phase tends to occur
more often if the heavy and light phases
have similar densities or if one fluid phase
enters through a jet into the wellbore.Problems encountered in measuring
holdup and velocities in multiphase flow in
horizontal wells include the following.
• Sumps and traps change the cross-sec-
tional area open to flow.• Segregated flow where different fluids
have different velocities can greatly compli-
cate spinner readings.
• Slight slope deviations from horizontal
can cause significant changes in holdupand fluid velocities.
• Deviations of much less than 90° can
cause backflow and circulation.
• Sensors that relate the density of a col-
umn of fluid to the difference in pressuremeasured at the top and bottom of the col-
umn cannot work in horizontal wellbores.
• A nuclear fluid-density meter is unde-
sirable because it is environmentally haz-ardous and provides inaccurate measure-
ments (particularly in heavy-oil/water sys-
tems of the Northwest shelf of Australia).
• Slotted liners create complications foraccurate calculation of the total flow ratebecause of the uncertainty introduced by
the annulus between the liner and the
open hole (e.g., annular flow, changing
hole diameter, or variable eccentering of
the liner).• The spinner behaves insensitively at
low flow rates, which typically occur
toward the toe of the well where the inflow
contributions are often of strong interest.Because of segregated flow, interpretation
techniques for vertical wells often are not
applicable to horizontal wells. Moreover,existing correlations for horizontal and
deviated oil/water flow do not deal with the
effects of slight deviations. Therefore, a newtool string consisting of traditional and
recently developed sensors has been tested.
The possible existence of gas traps and
water sumps causes another general diffi-
culty when trying to understand flowbehavior in horizontal wells. Given the
observed production of these fluids at the
surface, it would be dangerous to construe
the downhole flow regime of water and gas.For example, when only oil is produced atthe surface, it generally would be incorrect
to assume that single-phase oil flow
exists downhole.
INTEGRATED PRODUCTION-
LOGGING TOOL
The tool string shown in Fig. 1 is astripped-down version of one designed to
deal with three-phase flow and is generally
adequate for flow that is mainly oil/water.
The tool string contains multiple sensors
that measure the same quantity. For exam-ple, the locations of water inflow into a
mainly oil-filled wellbore could be inferred
from an interpretation of data from the
spinner plus the fluid holdups measured
by Schlumberger’s Reservoir SaturationTool (RST) and FlowView Plus tool
(FVPT) or from the flow image and bubble
counts from the FVPT. All data from all
sources must be considered when perform-
ing the interpretation.
CONVEYANCE
The example wells were logged with the aid
of a tractor run above the tool string. It wasused to push the string toward the toe of the well. The logging was done while the
tool string was pulled out of the wellbore
by wireline.
EXAMPLES
Three wells were logged in the Wandoofield, 37 miles offshore Australia on the
Northwest shelf. The field contains a thin
oil column (72 ft) sandwiched between a
small overlying gas cap and a strong aquifer.The oil gravity is 19°API, with a reservoir
viscosity greater than 15 cp. Reservoir per-meability ranges from 500 to 10,000 md.
NEW PRODUCTION-LOGGING
TECHNOLOGY FOR HORIZONTAL WELLS
This article is a synopsis of paper SPE
50178, “Application of New-Generation
Technology to Horizontal-Well Produc-
tion Logging—Examples From the
North West Shelf of Australia,” by A.
Carnegie, SPE, Schlumberger, and N.
Roberts, SPE, and I. Clyne, Mobil E&P
Australia Pty. Ltd., originally presented
at the 1998 SPE Asia Pacific Oil & Gas
Conference and Exhibition, Perth, Australia, 12–14 October.
P R O D U C T I O N O P E R A T I O N S
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The field was developed with horizontalwells, 15 oil producers and one gas injector.
The average length of openhole section forthe oil producers is 3,281 ft.
Understanding of water influx into the
horizontal wells is crucial to the long-termrecovery from the field. Early breakthrough
of water was expected because of the thin
oil column, unfavorable mobility ratio, and
strong bottomwater drive. Results from a
previous production-logging campaignindicated that water influx occurred at the
heel of the well, the location of maximum
drawdown. Recent production logs suggest
that this assumption was applicable onlyfor wells intersecting sands of uniform per-
meability or for wells with higher-perme-
ability sands at the heel.
Example 1. Well WB1a intersects higher-permeability sands at the toe of the well.
These sands are thought to have incurred
large fluid losses during drilling operations,
which may have damaged the formation.
Test objectives were to determine the flow
contribution of the sidetrack, the wellinflow profile, and water-entry locations.
The tool string consisted of a directional
full-bore spinner; an FVPT; and sensors for
pressure, temperature, and acceleration. AnRST analysis was unnecessary because thedownhole flow regime was known to be
essentially two phase (oil and water). The
holdup in an oil/water flow regime can be
determined by the FVPT reliably.
The shut-in log data show a strong cor-relation between parameters: the FVPT
bubble counts and water-holdup-analysis
results and the low sections of the well tra-
jectory. The spinner indicated that cross-flow was insignificant or nonexistent.
Data from the FVPT corroborate the spin-
ner with respect to water at low points inthe wellbore. But only the spinner can be
used to suggest the existence of gas pock-
ets at high sections of the wellbore. Water
sumps and gas traps typically are found inshut-in wells with little or no crossflow.During the flowing pass, the full-bore
directional spinner indicated that inflow
to the wellbore was relatively uniform,
probably indicating that the sidetrack was
not contributing significantly.The holdup analysis shows that, during
flowing conditions, the sumps had been
dispersed and smeared except for one at
5,676 ft, where the flow from the toe wasprobably too low to affect it. The bubble-
map log track, which was blank for the
shut-in pass, shows an abundance of bub-
bles under flowing conditions. These bub-
bles are probably water because they usual-ly occur on the lower side of the liner.
Example 2. The next well logged was
Well WB4a, which intersects higher-per-
meability sands at the toe of the well.
These sands constitute 9% of the total
openhole section of the well. The initial
logging passes were shut-in spinner-cali-bration passes. When the surface flow
rates were stable at 3,490 BOPD and 7,265
BWPD, logging was performed.
Near the toe of the well, the fluids werestratified vertically (water underneath,hydrocarbon on top) and the bubble count
was low (compared with the heel). Moving
up the hole, the temperature, bubble count,
and water holdup increased dramatically
and the flow became more mixed. The bub-bles between 6,300 and 6,102 ft were likely
water because the water holdup increased
dramatically (from 6,300 to 6,234 ft). This
influx location coincides with the pointwhere the well intersects the higher-perme-
ability sands at the toe of the well.
In the segment of wellbore between6,102 to 3,281 ft, the water holdup
decreased. The flow became bubbly, and
the bubbles probably were oil because most
occurred on the high side of the liner. Water and hydrocarbon also became pro-gressively more mixed (i.e., dispersed).
From 6,102 to 3,281 ft, all the influx was
oil. On the basis of the spinner response,
the oil productivity was uniform.
Example 3. The third horizontal well sur-
veyed was Well WB9, which wasgeosteered under an existing producer and
intercepted a water cone at 4,921 ft. The
tool string consisted of an FVPT and an
RST. The FVPT provided the wellbore
water-/hydrocarbon-holdup data. Thesedata were necessary to interpret the forma-
tion measurements made by the RST. The
RST was used to determine the oil, water,
and gas saturations in the formation and to
provide wellbore holdup data. The resultsindicated that the residual-oil saturation in
the zone from 4,970 to 5,102 ft was
approximately 27%, compared with 19%
from core analysis.The data from the RST tool, acquired
while in dual-burst pulsed-neutron mode,
clearly show character that is not an artifact
of the wellbore conditions and, therefore,
should be a formation response. Thisresponse implies that the RST may be used
for time-lapse monitoring. The wellbore
holdup determination from the RST agrees
well with that from the FVPT. These results
are being used by Mobil for reservoir mod-eling and for time-lapse monitoring.
Fig. 1—Tool string used for the Australian Northwest shelf examples (conveyed by tractor—not shown).
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been peer reviewed.
Combinable
production-logging toolto obtainpressure andtemperature.
The RST used to
determine waterflow; three-phaseholdup; formationoil, water, and gassaturations; andgamma ray count.
Full-bore directionalspinner used todetermine totalflow rate.FVPT
Flowview tool Flowview tool
Combined tools positioned at a 45° offset and usedto determine holdup, flow image, bubble map, andbubble velocity.
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70 MARCH 1999 •
Water management is important in the pro-
duction of hydrocarbons, especially when
water volumes steadily increase as fields
age. Novel approaches that can reduce thewater volume downhole may supplement
the traditional approach to oil/water separa-
tion at the surface. Taking produced water
out of the well stream downhole increases
production-tubing and process-facilitycapacity for oil and gas. Downhole oil/water
separation (DOWS) can reduce the need toupgrade water-treating facilities.
Downhole separation offers an alterna-tive to debottleneck constrained water-han-
dling facilities with potentially positive side
effects, such as more favorable conditions
for separating oil from water, increased pro-
ductivity as a result of better wellhydraulics, reduced discharges of oily
water, and maintenance of reservoir pres-
sure. Reducing water at the source also
diminishes the need for water treatment
and for prevention of corrosion, scale, andhydrates. When wells are already pumped
or when produced water is already reinject-
ed, downhole separation will be beneficial,
particularly in wells where water shutoff has proved ineffective.
New concepts for DOWS have been
developed under a joint-industry project
run by the Centre for Engineering Research
(Canada). The technical feasibility of com-pleting wells with hydrocyclones and
downhole pumps to achieve in-well pro-
duction, separation, and reinjection was
demonstrated. The first successful installa-
tion outside North America became opera-
tional in Germany in 1997.
CANDIDATE WELLS
Candidate wells have a relatively low pro-
duction rate (95%). Wells with a risk of sand pro-
duction or emulsification must be avoided.
The Eldingen field, east of Hannover,Germany, has produced from a shaly sand-
stone reservoir since the 1950’s and meets
the screening criteria. Well Eldingen-58
produces light oil from three consolidated-
sandstone intervals that are in pressurecommunication. The reservoir pressure is
approximately 72 bar at a 1460-m perfora-tion depth. Production has been lifted by a
beam pump at 80 m3 /d with 97 to 98%
water cut. In preparation of the DOWSinstallation, a packer was set to isolate the
top zone from the two lower zones. The top
zone was to be the producing interval and
the lower zones the injection interval.
EQUIPMENT DESIGN
The downhole separator was designed in
consultation with the equipment supplier
on the basis of reservoir and well data. TheDOWS for Well Eldingen-58 includes one
hydrocyclone and two electrical-sub-
mersible pumps (ESP’s). Fig. 1 depicts the
downhole equipment and flow paths.
The high-water-cut oil flows from theproduction perforations upward to the top
of the motor shroud. The bottom of theshroud is coupled to the pump housing by
a fluid-tight seal, forcing all fluids over the
top of the shroud and downward along themotor into the pump. From the pump
intake, all fluids are pumped downward by
the total-flow pump (an upside-down ESP
with a thrust bearing at the top and dis-charge at the bottom) into the hydrocy-
clone where the bulk of the water is sepa-
rated from the oil. The underflow of the
hydrocyclone produces water clean enough
for injection into the disposal zone. Theoverflow, oil with the remainder of the
water, flows through bypass tubes into the
concentrate pump for production to the
surface. These three 20-m-long, 0.9525-
cm-diameter tubes that bypass the lowerpump and motor are sized so that erosion
and pressure drop are minimal.
A common motor drives both pumps.
This motor has protectors at top and bot-
tom, unlike a normal ESP. The motor ispowered from the variable-speed drive at
the surface through a flat cable, which is
strapped to the tubing with metal bands
and cross-coupling protectors. With a vari-
able-speed drive and an adjustable surfacechoke, the system can cover the expected
variability in injectivity and productivity.
The pump design depends on the flows
and pressures required to lift the oil-richstream compared with those needed to
reinject the water. The push-through sys-
tem used in Well Eldingen-58 is most effi-
cient for dealing with the low reservoir
pressure in Eldingen. This concept alsoavoids any breakout of gas in the hydrocy-
clone. If the reservoir pressure is sufficient-
ly high, a concentrate pump is not needed.
Alternatively, the well stream may be sepa-rated before being pumped; this so-called
DOWNHOLE SEPARATOR PRODUCES
LESS WATER AND MORE OIL
This article is a synopsis of paper SPE
50617, “Downhole Separator Produces
Less Water and More Oil,” by P.H.J.
Verbeek and R.G. Smeenk , Shell Intl. E&P,
and D. Jacobs, BEB Erdgas und Erdöl,
originally presented at the 1998 SPE
European Petroleum Conference, TheHague, The Netherlands, 20–22 October.
P R O D U C T I O N O P E R A T I O N S
Fig. 1—Downhole equipment lineup of well completion and flow paths forEldingen-58.
Tubing to surface
Concentrate pump
Motor upper protector
Motor lower protector
Pump intake
Total-flow pump
Bypass tubes
Hydrocyclone
Injection pressure sub
Separation packer andlocator seal assembly
Injectionzone
Productionzone
Motorshroud
Motor
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P R O D U C T I O N O P E R A T I O N S
pull-through concept can be applied pro-
vided the bubblepoint pressure is high
enough to prevent gas breakout in the
hydrocyclone. In some crude oils, the latterconcept would avoid emulsions and poor
injection-water quality as observed in earli-
er DOWS trials with heavy oil.
Solids carried by the separated water arethe biggest concern for sustained injectivi-
ty. However, the consolidated reservoir in
Eldingen has little sand production. For
efficient oil/water separation, the split
between overflow and underflow of thehydrocyclone can be controlled by chokes.
The oil-in-water content in the underflow
of the hydrocyclone should be 100 to
300 ppm. To ensure this water quality into
the disposal zone, a rule of thumb forDOWS is to keep the surface water cut
slightly higher than 50%. The separation
efficiency depends largely on characteristicsof the oil/water mixture, in particular oil
droplet size. Knowledge of the droplet-sizedistribution in oil-in-water emulsions
downhole could enable better separation.
FIELD PERFORMANCE
Recompleting the well has increased net oil
production by 300%, while net water pro-
duction to surface has decreased by 64%. In
the first year of operation, reinjection of
water, separated downhole, did not damage
matrix permeability; however, a water-cutincrease was observed in the project area.
TECHNOLOGY OUTLOOK
Well re-entry has not been required for cor-rective action on downhole equipment. Thewater is injected under matrix-flow condi-
tions, and no sign of permeability damage
has been observed. Adjacent wells have
experienced an increase in fluid level and
water cut. These trends result primarilyfrom the influence of DOWS because these
wells produce from the lower zones into
which Well Eldingen-58 is injecting.
Despite favorable performance, the eco-nomics of DOWS is still relatively poor.
Assuming U.S. $15/bbl and a production-rate
increase of 30 B/D, payback time is approxi-mately 1 year. Important factors include oil
price, process-facility capacity, and an increasein tubing oil-flow capacity. Phasing well con-
versions in accord with increasing water rates
also would limit exposure of large up-front
investments. The concept, developed origi-
nally for debottlenecking production facili-ties, is being upgraded with a more efficient
downhole separator aimed at reducing the
infrastructure and facilities for offshore fields.
CONCLUSIONS
• Industry still needs to prove that down-
hole separation is a reliable, cost-effective
means to increase oil production from
capacity-constrained facilities, potentiallylengthening the life of oil fields.
• The downhole-separation concept, devel-
oped originally for debottlenecking onshore
facilities, has the potential to reduce the infra-
structure and facilities of offshore oil fields.• Evidence exists that water, separated
downhole, can be injected under matrix-
flow conditions, which may lead to signifi-
cant power savings in water-injection sys-
tems if sustained.• Water-cut development in the Eldingen
field indicates that DOWS should be
applied in reservoir configurations withflow barriers between producing and injec-
tion intervals.
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been
peer reviewed.
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72 MARCH 1999 •
Fig. 1 shows a subsea-satellite field on theNorwegian continental shelf, 200 km
northwest of Bergen, connected through a
9-in. production line to a concrete gravity-
based production platform. Production,
which started in 1994, is from four pro-duction templates, and water injection, for
pressure support, is through two injection
templates. Oil production currently is
25 000 m3 /d. Recoverable reserves are esti-
mated to be 55×106 m3 of oil from Brentgroup sandstone.
Squeeze chemicals can be injected intothe wells through a 21 / 2-in. methanol line
from the platform, 16 km from the farthest
production template. The individual wellsare completed differently, but most are ver-
tical or highly deviated, with 51 / 2-in. tub-
ing. Placement of chemicals is difficult
without the use of coiled tubing and an
intervention vessel, which is expensive.The most attractive solution is to bullhead
the treatment through the methanol line
and into the wells.
THE NEED
When a scale-inhibitor squeeze treatment
with a traditional water-based product is
needed, several operational constraints
must be considered. These constraints,
caused by the long distance between theplatform and the templates and the large
volume of fluid that has to be pumped and
backproduced, include the following.
• High friction and low pump rates will
be experienced because of the high reser-voir pressure and long distance.
• Poor placement can result because of
the low injection rates through the 21 / 2-in.
methanol line into 51 / 2-in. tubing.• Each production template is connected
to four producers. Because a separate test
line does not exist, the other wells at thetemplate must be shut in after a squeeze
treatment to enable the squeezed well to
produce through the 9-in. production line.
If use of an oil-soluble scale inhibitor
(OSSI) is possible, the squeezed well can bebackproduced without shutting in the
other wells at the same template. Also,
fewer relative permeability effects for dry
wells means that a squeeze treatment canbe performed before water breakthrough
without risking deferred production
because of a prolonged cleanup period. Anextended squeeze life may be possible
because the OSSI can be placed deeper intothe formation without causing water block,
as often observed with water-based prod-
ucts. Better placement, with a higher
squeeze rate into the formation, may be
possible because of a lack of pressure dropcaused by changes in saturation.
OSSI
OSSI’s are better described as oil-miscible
scale inhibitors. They were developed ini-
tially for gas-lift applications and some-times applied as combined scale/corrosion
inhibitors. Early OSSI’s often contained
multiple components and mutual solvents
to hold the package together. In special
applications, undesirable side effects (suchas behaving as a surfactant) limited the
flexibility of component selection. New
OSSI’s do not contain a mutual solvent and
will dissolve in most hydrocarbons at infi-
nite ratios.
HYDROCARBON CARRIER
As part of the test program, the authors
examined different carrier fluids (hydrocar-bon for the pill) that might be available inthe field (e.g., diesel, kerosene, crude,
paraffin, and xylene). While xylene is theleast likely candidate, its inclusion provides
direct comparison with the others because
it often is regarded as the best hydrocarbon
solvent and is used in many oil-treating
chemicals. The choice of carrier fluiddepends on costs, handling, availability,
and its effect on the OSSI. The last point is
critical because the hydrolysis and parti-
tioning kinetics of the OSSI, when it finallycomes into contact with the in-situ water
phase, control the success of the squeeze
treatment in the field. Also, the selectedhydrocarbon carrier must demonstrate full
compatibility with the OSSI at differentoperating temperatures (i.e., platform,
seabed, and downhole).
In the tests, 10% OSSI solutions were
made up in crude, kerosene, diesel, paraf-
fin, and xylene. The solutions were mixed5:1 with formation water to prepare test
samples. The samples were shaken briefly
and left in an oven overnight at 80°C. The
aqueous and the oil layers from each sam-ple were separated and analyzed.
None of the solvent carriers appeared to
have a major influence on the mass-transfer
process of the OSSI. On contact with water,
most of the OSSI molecules transferredfrom the oil phase into the aqueous phase
through a combined hydrolysis and parti-
tioning process. The level of transfer was
extremely high, with little (
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74 MARCH 1999 •
P R O D U C T I O N O P E R A T I O N S
mild scaling-regime change from CO3 to
SO4 scale when seawater breaks through.
After transferring into the water phase, the
OSSI molecules must demonstrate ade-quate inhibition efficiency. Performance
tests were carried out by use of a conven-
tional tube-blocking-test apparatus to
determine the minimum inhibition con-centration (MIC).
Precolumn Test. A second tube-blocking-
test procedure uses a precolumn sandpack
inserted into one of the water flowlines
placed upstream of the test coil. The col-umn simulated a squeeze treatment in the
sandpack before the test. The arrangement
is suitable for screening and ranking differ-
ent scale inhibitors for squeeze treatment
before the more expensive and time-con-suming core tests. If the effluent samples
can be preserved and stabilized, such anarrangement can provide simultaneous,
inexpensive comparisons of inhibition effi-cacy and retention characteristics of the
scale-inhibitor chemicals.
This apparatus possibly can be expanded
so that a reservoir-conditioned-core con-
tainer is coupled with a standard tube-blocking-test apparatus. By monitoring the
pressure drop, the level of scale-inhibitor
residuals, and the scaling ions in the efflu-
ents, a more representative MIC level and
squeeze life might be determined forfield applications.
Once the OSSI molecules hydrolyzed
and partitioned in the connate water, they
migrated toward the sand surface, wherethe adsorption process took place. Their
return is not affected by the passage of
hydrocarbon but follows a desorption pro-
file similar to that of a water-based
scale inhibitor.Poorer performance with the water-based
scale inhibitor seems contradictory at first.
However, after reviewing other data gener-
ated during this study, it became clearer and
is explained by the unique mechanism of
“enhanced partitioning.” When injecting awater-based scale inhibitor, the best out-
come is complete replacement of the con-
nate water by the injected squeeze pill. The
maximum concentration gradient that candrive the adsorption process is equal to the
pill concentration. However, for the OSSI,
the maximum concentration that can be
attained by the connate water is governedby the mass-transfer process between the
oil and water phases.
During the course of this study, it was
observed that the equilibrium concentra-
tion in the aqueous phase can be signifi-cantly higher than that in the original OSSI
solution. This may explain the fact that,
while the same activity of scale inhibitor
was present in both cases, the desorption
profile of the OSSI seemed to be better
because of the much higher concentrationgradient that drove the adsorption process
in the first place. Hence, the time required
to scale up the test coil was longer.
Reservoir-Conditioned-Core Tests. The
results from the precolumn tube-blocking
tests cannot predict accurately what will
happen in the field. As part of the product-
development program, a reservoir-condi-tioned-core test is essential to determine
whether the OSSI can offer a reasonable
squeeze life when deployed in the field.
Also, any potential damage to the forma-tion that might be caused by the OSSI
chemical must be assessed.
To examine the retention characteristicsof the OSSI, the effluents from both the
adsorption and desorption stages were ana-lyzed. None of the samples showed any
detectable level of scale inhibitor. The
results from a separate analysis also con-
firmed that less than 1% of the injected
OSSI remained in these samples. It appearsthat all the OSSI injected had been
adsorbed and that very few of these
adsorbed molecules had been released dur-
ing the kerosene flush. A likely explanation
for such a unique phenomenon is that thehydrolysis and partitioning of the OSSI
were highly efficient within the porous
media. With only 2.7 pore volumes (PV) of
OSSI injected, all injected scale inhibitorhad been retained. The desorption profile
with formation brine is more like that of
traditional scale inhibition. After peaking at
approximately 44 000 ppm, the scale
inhibitor returned to approximately 100ppm after 50 PV and finally down to 1 ppm
after 600 PV of brine injection.
For the injectivity and formation-dam-
age study, the differential pressure across
the core was monitored during the injec-
tion of the spearhead, main pill, and theinitial backflow of kerosene and formation
brine. A small pressure rise was registered
when the spearhead and desorption brine
were injected. In both cases, the injectionfluid was immiscible with the in-situ fluid.
A small, gradual rise in the differential
pressure occurred toward the end of the
OSSI injection, which coincided with thebreakthrough of a minute quantity of
water. The authors believe this likely was
caused by the end effect and redistribution
of the water phase. If an interaction
between the OSSI chemical and the corematerial occurred, which might have
caused formation damage, a sharp increase
in the injection pressure or a cessation of
flow after the locked-in period would
be expected.
Effect of W ater Saturation. For a mainly
water-wet formation, the connate-water
saturation in the reservoir can vary between5 and 25%, even if the field is not yet pro-ducing water. In formations where immo-
bile-water pockets exist, the localized satu-
ration can be even higher. One of the final
tests carried out was to combine the OSSIpill (10% solution in kerosene) with forma-
tion water in various ratios. Nine samples,
with OSSI/water ratios ranging from 1:9 to
9:1, were prepared. Apart from one sample
with a 1:9 OSSI/water ratio showing minorturbidity, all other samples remained fully
compatible. Mass transfer of OSSI mole-
cules was observed in all cases. For thehigh-water-cut sample (90%), the observed
minor incompatibility can be overcome inthe field by use of a properly sized hydro-
carbon spearhead.
CONCLUSIONS
OSSI molecules hydrolyze and partition
readily on contact with an aqueous phase.Once partitioned, the hydrolyzed OSSI
molecules exhibit inhibition efficiency and
retention characteristics similar to those of
generic water-based products. The mass-
transfer process of the OSSI molecules fromthe oil phase to the water phase appears to
be irreversible. Depending on the phase sat-
uration, enhanced partitioning can be
achieved. A larger hydrocarbon spearhead
should be considered for wells with a 10 to25% water cut. The combination of an OSSI
squeeze pill and a suitable hydrocarbon
overflush will minimize many flowback
problems associated with relative perme-ability and water block. Also, the cleanup
period will be much shorter, leading to
quick restoration of oil production to its
presqueeze rate. This restoration of produc-
tion rate is particularly beneficial to dry ornearly dry wells and to reservoirs with poor
lift energy. For offshore environments, an
OSSI squeeze minimizes water handling
and subsequent discharge to the sea, there-
by reducing the commonly observed oil-in-water problem after a conventional water-
based squeeze treatment.
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been peer reviewed.
8/15/2019 Production Operations (16pages)
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• MARCH 1999 75
Uncontrolled growth of sulfate-reducing
bacteria (SRB) in oilfield systems can create
safety, environmental, and operational
problems (such as microbiologically influ-enced corrosion, solids production, and
biogenic H2S generation). Anthraquinone,
a nontoxic biodegradable substance,
uncouples the electron-transfer process in
SRB required for the bacteria’s respirationwith sulfate. When this metabolic pathway
is blocked, SRB are incapable of reducingsulfate to H2S; therefore, the reaction of H2S
with soluble iron also is blocked.
Anthraquinone is essentially insoluble inwater; however, the chemically reduced
form (anthrahydroquinone) is soluble in a
caustic solution. Anthraquinone, as treat-
ments are referred to in this paper, was
injected as a 10-wt% solution of the solubleanthrahydroquinone disodium salt in caus-
tic. Injection of this solution into a flowing
water stream forms submicron-sized parti-
cles of the inhibitor. The small particles
coat the interior surfaces of pipelines ininjection systems and subsequently become
incorporated into the biofilm. Once the
particles are incorporated into the biofilm,
they partition into the cell membrane of thebacterial cells and inhibit sulfate reduction.
These relatively insoluble, nonreactive par-
ticles are believed to provide a “time-
released” treatment within the biofilm and
a continual source of sulfide inhibitor.Periodic treatments are required to replace
anthraquinone that has been biodegraded
or dissolved in flowing untreated water.
Anthraquinone is not biocidal. Bacteria
other than SRB also may be harmful in oil-field water systems and should be con-
trolled with conventional biocides.
Consequently, anthraquinone treatments
are designed to be used as a supplement in
these applications to extend the life of tra-ditional biocide treatments.
FIELD DESCRIPTION
The facility is composed of two separate
systems, A and B. Both systems receive
water from the same source. System A is a
single injection plant pumping approxi-mately 29,000 B/D of produced water to 28
injection wells. System B has three injectionplants that pump a total of approximately
28,000 B/D of filtered produced water to 51
injection wells. Water lines that were out of service dur-
ing the field trial were inspected visually for
solids deposition and found to be fouled
heavily with accumulated solids. The pre-sumption was that this condition was repre-
sentative of the lines treated during the trial.
LABORATORY STUDIES
Measurable sulfide production from the
untreated field-initiated bottle tests began 4days after the wellhead-water samples were
taken, while samples treated with the
anthrahydroquinone solution were inhibit-
ed for at least 12 more days. Laboratory-ini-
tiated bottle tests used a synthetic mediumwith the cultured SRB. This test was
designed to evaluate the effect of Fe2+ on
the inhibition because Fe2+ forms a weak
equimolar complex with anthrahydro-
quinone. The Fe2+ content in the field pro-
duced water was approximately 100 kmol,while the anthrahydroquinone concentra-
tion injected during the field trial was
approximately 500 kmol. The laboratorystudy was run with approximately equimo-lar Fe2+ and anthrahydroquinone(500 kmol and 440 kmol, respectively) and
with excess Fe2+ (500 kmol) at the same
440-kmol anthrahydroquinone level. The
results indicate that the iron had negligible
impact on the inhibition effect of theanthrahydroquinone, although high iron
levels did affect the ultimate sulfide
level obtained.
Results from two sets of dynamicbiofilm-inhibition studies show significant
inhibition of sulfide production for about 3days. After sulfide production increased,
subsequent repeat treatments (500 ppm of
the anthrahydroquinone solution for 2 or 4
hours) directly into the biofilm columnrestored inhibition for at least 1 day.
During the second test, two treatments
were applied before inhibition ceased, but
these treatments did not appear to extend
the inhibition period beyond that observedfor the first test. The initial treatment of the
influent SRB flow allows the anthrahydro-
quinone solution to contact the SRB inti-mately for approximately 1 minute before
entering the biofilm column. This delayallows molecules of anthrahydroquinone
to partition into the SRB cell membrane
and inhibit sulfate respiration after an ini-
tial lag period. The inhibition duration forthis laboratory system with a synthetic
medium apparently is limited to approxi-
mately 3 days. Subsequent treatments of
the developing biofilm are not as effective
as the initial treatment because of thehydrodynamics of the laboratory system.
The drop in pH of the treatment solution
as it is injected into the medium causes the
formation of rather large particles of
anthrahydroquinone that cannot penetratethe biofilm well because of the low shear
stress at the wall of the biofilm column. In
the field situation, where pipeline Reynolds
numbers and shear stresses are high, how-
ever, the anthrahydroquinone particlesthat form as the pH drops are colloidal and
are transported easily to the biofilm on the
pipe wall by shear dispersion. Additionally,
small particles are necessary to obtain highlevels of sulfide inhibition.
FIELD TRIAL
A California facility was chosen for ananthraquinone-treatment program because
of the very active SRB population and
resulting production of iron sulfide solids.
The active SRB population in the producedwaters of this facility required daily treat-
ments with acrolein. The field trial was
conducted during the summer of 1997 to
determine whether cotreatment with
anthraquinone could extend the intervalbetween acrolein treatments.
H2S concentrations for Systems A and Bwere monitored daily. In System A, the pro-
CHEMICAL MITIGATION OF SULFIDE
IN WATER-INJECTION SYSTEMS
This article is a synopsis of paper SPE
50741, “A New Chemical Approach To
Mitigate Sulfide Production in Oilfield
Water-Injection Systems,” by M.D.
Johnson, M.L. Harless, and A.L.
Dickinson, Baker Petrolite, and E.D.
Burger, SPE, EB Technologies, original-
ly presented at the 1999 SPE
International Symposium on OilfieldC hemistry, Houston, 16–19 February.
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76 MARCH 1999 •
P R O D U C T I O N O P E R A T I O N S
duced water flowing to Injection Well A-2
soured the most rapidly during each treat-
ment cycle because of the relatively long
residence time in the 31 / 2-in., 1,900-ftpipeline from the header to the well. Most
other injectors had smaller-diameter flow-
lines or shorter lengths from the headers.
Well A-3 was the only other System A wellto experience a significant increase in H2Sin the injection water during each cycle. In
System B, no injection water soured during
the first treatment cycle, although the
diatomaceous-earth-filter outlet water had
high H2S on 16 July because of exceptionalfouling. The problem was resolved by back-
washing the filter. Only the water trans-
ported to the most remote System B well, B-
1, soured significantly during the second
and third cycles.In System B, H2S concentrations
increased most rapidly during the thirdcycle, possibly because the ambient temper-
ature increased almost 18°F (to 104°F dur-
ing the daytime) throughout that cycle.Because most pipelines are not buried, flow-
ing-water temperature also increased, prob-
ably contributing to higher SRB activity.
This high activity may account for the
shorter period before H2S began to increase.During generation of baseline (control)
data, produced water collected from System
A Injection Well A-3 had a significant
increase in H2S after 1 day. Produced water
collected from System A Injection Wells A-1 and A-2 had increased concentrations of
H2S after 2 days. Produced water collected
from all System B injection wells had
increased concentrations of H2S 1 to 2 days
after the start of the control period. Theseresults confirmed that daily acrolein treat-
ments were required to maintain stable H2S
levels in both injection systems.
TOTAL SUSPENDED SOLIDS (TSS)
No correlation between TSS and theacrolein/anthraquinone treatments was
noted during the field trial or control peri-
od. Random fluctuations in TSS were notedin produced waters collected from each of the injection wells monitored. Downstream
TSS levels correlated closely with the TSS
levels entering the systems. TSS levels were
elevated slightly only during the third treat-
ment cycle in System B, corresponding tothe increased H2S levels observed duringthat cycle. Also, both H2S and TSS levels
were higher than those of the initial two
treatment cycles during the System B con-
trol period. Again, increased SRB activity
cause by elevated water temperatures dur-
ing the third treatment cycle and absence of acrolein/anthraquinone treatments during
the control period are probable causes of
these increased H2S and TSS levels.
SRB MEASUREMENTS
Results from SRB serial dilutions for System
A indicate that the population remained rel-
atively stable throughout the trial and con-
trol periods for the sample sites monitored.The SRB levels in the System B influentwater varied more than those in System A,
although, overall, they were slightly lower
than those entering System A. This variabil-
ity most likely was caused by growth of SRBin the filter cake of the diatomaceous-earth
filter coupled with backwashing frequency.
Except for two wellhead water samples, the
SRB levels were between 101 and 103
cells/mL throughout the treatment and con-trol periods.
ANTHRAQUINONE RESIDUALS Water samples were collected at various
locations in each system during the treat-
ment periods to determine system use of the chemical and to confirm that the chem-
ical traveled through the system. These data
indicate that the anthraquinone concentra-
tion decreased rapidly immediately down-
stream of the injection location, then slow-ly decreased as the pipe branched to remote
wells. Deposition of the anthraquinone in
the biofilm was confirmed by the decrease
in concentration within the pipeline seg-
ments. Monitored parameters following thetreatments indicate that sufficient
anthraquinone generally reached all parts
of the system during each injection period.
CONCLUSIONS
Laboratory studies confirmed field resultsthat biogenic sulfide production within this
California oil field’s water-injection system
can be inhibited with anthraquinone treat-
ments. Extended-duration inhibition wasobtained in the laboratory. The presence of
iron does not appear to affect sulfide inhi-
bition. Simple laboratory studies were diffi-
cult to perform with this type of inhibitorbecause of the need for more realistichydrodynamic conditions to keep the insol-
uble inhibitor particles small and bioavail-
able, as they are in a field pipeline system.
During the field trial, H2S concentrations
remained stable for up to 9 days in both
Systems A and B following eachacrolein/anthraquinone treatment cycle.
After these stable periods, sharp increases
in H2S concentrations indicated that the
available anthraquinone concentrations
within the biofilm had dropped below
inhibitory levels. H2S level appears to bethe most responsive parameter for monitor-
ing treatment efficacy. Significant increases
in wellhead-water H2S levels could be
detected more easily and reliably than TSS
or SRB levels.As with H2S concentrations, steady
increases in TSS were expected during the
cycle period but were not observed during
the field trial. Instead, TSS concentrationsfluctuated throughout the trial and controlperiods. Therefore, no correlation could be
made between TSS concentration and each
acrolein/anthraquinone treatment or con-
trol period. The observed TSS concentra-tion fluctuations likely were caused by
changes in influent-water quality rather
than the effects of downstream SRB activity.
The SRB population in the wellhead-
water samples generally remained stablethroughout both water-injection systems.
As with TSS levels during the first and sec-
ond treatment cycles, variability most like-ly was the result of changes in the influent-
water quality.The increased H2S concentrations toward
the end of each acrolein/anthraquinone
treatment, coupled with a relatively stable
SRB population throughout the field trial,
indicate that anthraquinone was acting as a
sulfate-reduction inhibitor rather than as abiocide. If the treatment program was per-
forming as a biocide, a decline in the SRB
population would have been observed
immediately after each treatment. This
decrease would have been followed by anincrease in SRB population over time. The
anthraquinone treatment was acting to con-
trol any further growth and reproduction of
the SRB population, resulting in a stablepopulation over the period of each
acrolein/anthraquinone treatment.
Additional field work is required to
determine the treatment life of anthra-
quinone in other systems. Anthraquinonemust penetrate biofilms to contact sessile
SRB, and, therefore, treatment periods and
concentrations may be influenced signifi-
cantly by the biofilm thickness. It is possi-
ble that less-heavily-fouled systems wouldrequire fewer anthraquinone treatments or
lower concentrations to achieve adequate
inhibition of SRB sulfate reduction for
extended periods.
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been peer reviewed.
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78 MARCH 1999 •
Oil and gas production in the Appalachian
basin is characterized by mature, water-sen-
sitive wells. Many wells have been produc-
ing for more than 25 years. Most of the stor-age wells have been in use 40 years or more.
These wells often are plagued with entry
problems caused by restrictive fittings,
valves, or tubing that hinder the repair and
replacement of corroded, faulty, or under-sized wellheads and casing top joints. The
conventional approach uses coiled tubing(CT) with inflatable packers that are set
through the restriction into the good casingdownhole, allowing uphole repairs. These
tools are expensive and pose stability and
safety problems in old casing. An alterna-
tive is to use CT to place crosslinked-poly-
mer plugs to protect the formation from thekill fluid used to isolate the formation pres-
sure during repair operations.
BACKGROUND
Many additives and fluid systems have been
introduced to control fluid loss or to pro-vide a nonmechanical means to isolate
intervals. These systems usually are high-
viscosity fluids and can contain solid partic-
ulates. Tests have shown that these systems
can be difficult to remove and can damagethe intervals they are designed to protect.
Crosslinked-polymer plugs provide a
clean method of protecting a producing
zone from damaging workover fluids.
These crosslinked gels contain higher con-centrations of polymer than other
crosslinked fluids, such as fracturing fluids.
CROSSLINKED-POLYMER PLUG
The crosslinked-polymer plug used in this
application consists of a carboxymethyl-hydroxyethylcellulose at a concentration of
1.2 wt% when mixed in fresh water. The
system is buffered with an organic acid to a
pH of 3.5. To ensure complete hydration,
the polymer is preslurried in isopropylalcohol. A water-soluble zirconium salt is
added at 0.15 vol% as the crosslinker. The
system has a delayed, or retarded, crosslink
that occurs as a function of time and tem-perature. This delay allows proper place-
ment of the plug downhole before
crosslinking. The plug can be placedthrough casing, tubing, or CT, and a wide
variety of breaker systems can be used toremove the plug.
LABORATORY DATA
The crosslinked-polymer plug has been
successfully hydrated and crosslinked in
many fluids, including fresh water, 2%potassium chloride (KCl), 3% ammonium
chloride, and 16.0-lbm/gal fluid spiked
with zinc bromide. Crosslinking of the sys-
tem is both a function of temperature and
pH. The optimum pH of the system isbetween 3.5 and 4.0. The system is normal-
ly placed as a linear fluid, with crosslinking
occurring once the fluid is in place.
Typically, the higher the temperature and
lower the pH, the faster the crosslink.These variables need to be taken into
account when designing job procedures.
The crosslinked-polymer plug is stable
at downhole temperatures up to 200°F forseveral days. For temperatures higher than
175°F, gel stabilizers and extra polymer can
be added for stability. Tests indicate that
the crosslinked-polymer plug can help pre-
vent damaging workover fluids from enter-ing a productive zone even in high-perme-
ability formations.
When zonal isolation is no longer
required, the crosslinked-polymer plug
must be removed without causing damageto the formation. Breaker systems evaluated
included oxidizers, enzymes, and acids.
Return permeability of almost 100% was
obtained in all cases.
CASE HISTORIES
Wellhead Changeout and Pipe Repair.
The first case history with the crosslinked-polymer plug was for wellhead changeouts
on 12 Pratt storage-pool wells in Greene
County, Pennsylvania. The wells were
drilled in the late 1920’s and recompleted as
storage wells during 1945–50. The storage-pool sand is a moderately clean conglomer-
ate. Well depths range from 2,700 to 3,000
ft. Pool pressure during the project ranged
from 450 to 500 psi. The wells were com-
pleted with 51 / 2-in. casing with the cementtop 1,000 ft off-bottom. Approximately half
the wells were openhole completions, andthe rest were openhole with 31 / 2-in. perfo-
rated liners. All the wells have a restricted
entry above the “T” caused by a weldedswedge and a 4-in. restricted inside-diame-
ter valve.
Changeout Procedure. Wellhead change-
outs were performed with a CT unit. Once
on bottom, the CT was pulled up 25 to 30ft and 250 gal of the crosslinked-polymer
plug was mixed. The pH of 4.0 provided
adequate pumping time. To water wet the
pipe, 1 to 2 bbl of 2% KCl was pumped; this
was followed by the crosslinked-polymerplug. The plug was displaced out of the
tubing with 10 bbl of 2% KCl, and the CT
was pulled to the estimated top of the plug
at 2,600 ft. After approximately 1 hour, 2%
KCl water was pumped at 1.0 bbl/min untilthe pressure increased to 200 psi higher
than the pool pressure to allow the
crosslinked-polymer plug to set fully. The
pressure was bled off into the flowbacktank, and pumping resumed at 1.0 bbl/min.
This procedure was continued until the
well was killed at 750 psi overbalanced
pressure. The CT was pulled to surface, and
the CT unit was moved off the well whilethe operator changed the wellhead and
made repairs to the top joints of pipe with-
out experiencing any problems.
Removing the Crosslinked-Polymer Plug.
Nitrogen was used to unload the well whiletripping in with CT to the top of the poly-
mer plug. Then, 15% HCl was pumped in
as an external breaker. As the gel started
breaking, the acid was jetted to the bottom.
Nitrogen was used to circulate the hole
clean to total depth. The CT was tripped
out of the hole while pumping nitrogen and
the wellhead pressure monitored as itreturned to pool pressure.
NONDAMAGING POLYMER PLUGS
FOR TEMPORARY WELL ISOLATION
This article is a synopsis of paper SPE
51054, “Novel Application of
Nondamaging Polymer Plugs With
Coiled Tubing Improves Efficiency of
Temporary Well-Isolation Projects,” by
Brian B. Beall, SPE, and Thomas E.
Suhy, SPE, BJ Services Co., originally
presented at the 1998 SPE Eastern
Regional Meeting, Pittsburgh,Pennsylvania, 9–11 November.
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P R O D U C T I O N O P E R A T I O N S
• MARCH 1999 79
Shale Control. A crosslinked-polymer plug
was used to control caving shales. While
drilling the Berea formation at approxi-
mately 2,400 ft, a 4-MMcf/D open-flow gaszone was encountered. Rather than cement
the 41 / 2-in. casing, the decision was made
to set the casing on a formation packer at
1,350 ft, just above a sloughing shale.Below the shale, the well was completed asa 61 / 4-in. open hole. After producing the
well for several months, cavings from the
Sunbury shale bridged off over the produc-
ing zone and shut off gas production.
Several attempts were made with a conven-tional service rig to remove the bridge and
reset the 41 / 2-in. casing approximately 120
ft lower to stop the caving. After each
cleanout attempt, the shale caved back in
before the tool string could be removed andthe casing released and lowered.
CT Cleanout. CT was tripped into thewell with a 2.875-in. drill motor on 11 / 4-in.
tubing. The bridge was drilled out at 2,500
ft while circulating with gelled water. Oncethe 10- to 20-ft bridge was drilled through,
the tubing and tools were run in the hole
until a solid bridge was encountered at
2,900 ft. While continuing to circulate,
500 gal of crosslinked-polymer plug was
pumped through the tubing and drill
motor. The tubing was then pulled into the
casing to allow the polymer plug to set.After 1 hour, the CT was tripped out of the
hole and the 41 / 2-in. casing packer released.
Four joints of pipe were added, and the cas-
ing packer was reset at 1,470 ft. The CT was
tripped back into the hole with a jettingnozzle, and 500 gal of 15% HCl was used tobreak the gel and remove any additional
bridges. The well was cleaned out with
nitrogen, the tubing tripped out of the well,
and the well returned to production.
Fluid-Loss Control for Cementing Water
Zones. While drilling a well near Brandy-
wine, West Virginia, two water-producing
zones were encountered in high-fluid-loss
shales before total depth could be reached.A crosslinked-polymer plug was pumped
ahead of the cement plug as a fluid-lossmaterial to avoid losing the cement volume.
A volume of 250 gal/zone was pumped
through the drillpipe, each zone pluggedoff successfully, and the well completed
as planned.
Cement Retainer To Plug and Abandon a
Salt-Solution Mine. This well was drilled
in the 1950’s and used to produce salt-brine
solution for the retrieval of minerals and
chemicals. Repairs to the casing were per-
formed frequently because of the corrosiveenvironment. The 6,500-ft well was com-
pleted with 7-in. casing to the top of the salt
cavern. The plant was abandoned in the
late 1980’s, and the well and plant revertedto the original owner. Plugging and aban-
donment was required. The 7-in. casing
was highly scaled, with the inside diameter
reduced to 2 in. Usually, inflatable packers
are set in the casing just above the cavern;in this case, however, no CT unit was avail-
able to set the plug. A 500-gal crosslinked-
polymer plug was pumped ahead of the
cement and balanced in the casing with
3,200 psi cavern pressure. The polymerplug held the cement in place during the set
time without any problems.
Please read the full-length paper for
additional detail, illustrations, and ref-
erences. The paper from which the
synopsis has been taken has not been
peer r