production operations (16pages)

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.


2/16


• 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.


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


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.



4/16

66 MARCH 1999 •


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.






5/16

• 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


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.



6/16

68 MARCH 1999 •


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).





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.


7/16

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


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.


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


8/16


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.




synopsis has been taken has not been

peer reviewed.


9/16

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 (


10/16

74 MARCH 1999 •


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.






11/16

• 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


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.



12/16

76 MARCH 1999 •


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.






13/16

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


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.



14/16


• 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.




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