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T e c h L i n eA Publication of BJ Services Company Volume
10
Inside this issue
Chemical-free technology enhances production 10
Cementing approach minimizes corrosion threat 12
State-of-the-art tools benefit ultra-deepwater frontiers 14
Ultra-lightweight proppant improves production declines 18
Weak acid technique stimulates mature wells 23
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N E W S B R I E F S
Tools, fluids clean Middle East wellBJ Services introduced
wellbore cleaning services in Saudi Arabia in 2009 with a
successful gas well cleanup operation. The goals were to clean and
recover debris from the blowout preventer, scrape the liner and
casing clean, remove water-based mud from tubulars, and displace
the well to clean water for completion operations. In operation,
the magnetic tools alone recovered more than 5 lb (2.5 kg) of
ferrous material. The drilling representative praised the BJ teams
professionalism after the work was completed ahead of schedule and
without safety incidents.
Simultaneous fracs promote productionA recent simultaneous
re-fracture treatment in the Bakken formation of Montana found BJ
Services treating three horizontal wellbores separated by 1300 ft
(400 m), using the outer wells to pressure-divert the fracs on the
center well. After 60 days, the outer wells have two-fold increases
in production and the center well has another fold of increase. The
customer plans additional simultaneous fracs, including several
four-well fracs and the possibility of five- and six-well scenarios
to further evaluate the technique.
On the cover: A BJ Services crew member aligns segments of a
ComPlete MST completion system during a recent installation
offshore Indonesia. Details of this time-saving work are on pages 6
and 14.
New vessel extends services in AsiaTechnology expertise,
teamwork and a new stimulation barge were the keys to a successful
two-stage fracture stimulation in an evaluation well in the South
China Sea, about 50 miles (80 km) offshore Vietnam. Because
pre-frac reservoir studies were limited, the stimulation was
designed to be flexible and enable on-the-fly changes based on
realtime downhole data, thereby ensuring stimulation success.
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C o N t E N t S
BJ Services TechLine News 4
Chemical-free technology enhances production 10
Cementing in corrosive environments 12
Ultra-deepwater frontiers beckon 14
BJ in Action: Case histories from BJ Services 18
BJ Innovations: Novel solutions to oilfield problems 25
Enumerations: A whimsical look at numbers in the oilfield 27
6Selective solution:
Coiled tubing tools clean each leg in multilateral wells.
14Deepwater diversity:
Proven technologies and integrated services improve
ultra-deepwater economics.
10 Quantum quality: Electromagnetic waves stimulate oil
production.
BJ TechLine is published by BJ Services Company. Comments and
inquiries should be submitted to:
Editor: Stephanie Weiss11211 FM 2920 Tomball, TX 77375Tel +1
(832) 559-1308Fax +1 (832) 559-1319E-mail
[email protected]
Copyright 2009, BJ Services Company. All rights reserved.
Coflexip is a registered trademark of Technip.
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4 B J T e c h L i n e www.bjservices.com/techline
Solvent system enablesacidizing after OBMAn operator in the
Karachaganak field of Kazakhstan was using water-base mud to drill
wells, followed by acid stimulation to bypass near-wellbore damage.
The operator wanted to change to an oil-base mud to improve
drilling performance and avoid formation damage from potential
content such as swellable clays.
The disadvantage of this approach is that when HCl acid contacts
oil-base mud (OBM), it forms a persistent, highly damaging emulsion
that essentially prevents production.
The operator drilled one well using the oil-base mud and
considered producing it without stimulation, but initial
productivity test results were far below expectation. Therefore,
the operator asked BJ Services for a plan to stimulate the 2460-ft
(750 m) horizontal openhole.
Using core plugs and samples of the oil-base mud, BJ lab
personnel tested several solvent, demulsifier, surfactant and acid
combinations to find onea modified Paravan D systemthat would break
down the surface mudcake for removal without creating other damage
to the formation.
In operation, the well was displaced with diesel and flowed back
for a clean up. The Paravan mudcake breaker system was then pumped
as a preflush and allowed to soak for four to six hours. After the
soak, an acid wash was performed using 15% HCl. Fluids were pumped
through coiled tubing with a Roto-Jet tool configured to maximize
the flow rate.
Operations have been successful. For example, Table 1 shows
before and after results for the first horizontal well treated
using the technique and formulation.
For future wells, the cleanup and breaker systems may be
combined in a single operation.
MAURIZIO FRATUS, Kazakhstan
Pre-Job Post-Job
PI 2 4
Skin 2 5
Table 1. Well A Results
BJ Services strengthened its pipeline precommissioning record
this year with high-profile, deepwater projects offshore Nigeria
and India.
In the central Niger Delta region, pipeline services specialists
in the Agbami field performed flooding, cleaning, gauging,
hydrotesting and dewatering services for subsea flowlines and water
injection risers related to subsea wells connected to a floating
production storage and offloading (FPSO) facility in about 4700 ft
(1433 m) of water.
With engineering and procurement support from Aberdeen, pipeline
services personnel in Port Harcourt,
Nigeria, coordinated the flooding of the water injection risers
and main flowlines as they were laid. A series of cleaning and
gauging pig trains in the production and gas injection loops
displaced the raw seawater with filtered, treated seawater.
In the Krishna Godavari basin offshore India, BJ Services
provided engineering, project management, cleaning, flooding and
pressure testing services for 8-in. production flowlines and a
6-in. gas injection riser associated with a field at water depths
of up to 3937 ft (1200 m) in the Bay of Bengal.
JAcqUelIne lAcOMbe, Houston
BJ prepares deepwater infrastructure
Hammer sets piles offshore CanadabJ Services hydraulic hammers
recently drove six
36-in. piles and 15 24-in. piles for an oil and gas
development in about 500 ft (155 m) of water
offshore newfoundland. The work was completed
from a specialized support vessel, which required
design and extensive pre-job testing of a custom
hammer frame, power packs and control system
for the S-200 hydraulic hammer.
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www.bjservices.com/techline B J T e c h L i n e 5
The Barnett shale was the venue for a record-setting OptiFrac SJ
multizone, horizontal completion combining state-of-the-art coiled
tubing and fracturing technologies.
BJ Services crews completed a record 44 zones in a 2800-ft (850
m) horizontal well in just 17 days of daylight-only operations.
Three technologies were significant in enabling this
accomplishment:
The EasyCut abrasive jetting tool to create clean, undamaged
perforations through the casing
Annular hydraulic fracture stimulation using a slickwater fluid
system and ending each zone with a LitePlug proppant slug that
effectively isolates the zone
A final CT cleanout after all zones were completed, using the
patented Tornado process
The technology combination has been used to stimulate hundreds
of zones in Canada, with typical completions featuring 300-ft (100
m) zone spacings. Zone spacing for the record-setting Barnett shale
well varied from 50 to 80 ft (15 to 24 m).
A total of 4.2 million lb (1900 t) of sand were pumped for the
combined operation. All of the sand plugs performed as designed.
Surface treating pressures averaged 3500 psi (24 MPa) and pump
rates ranged from 10 to 18 bbl/min (1.6 to 2.9 m3/min).
No other method available at the time could have enabled 44
treatments in the well, economically.
JUAn cARlOS cASTAedA, lUIS cASTRO, STeven H. cRAIg and cHRIS
MOORe, Houston and Fort Worth
Combined operation enables 44-zone horizontal frac
Adaptable cement system minimizes hurricane delayWhen hurricane
damage delayed a shipment of nitrogen and pumping automation
equipment to a deepwater rig in the Gulf of Mexico, BJ Services was
able to quickly redesign its cement system to save rig time without
sacrificing job quality or safety.
The rig was drilling in about 7000 ft (2130 m) of water in the
Keathley Canyon area, which is known for having a moderate to high
potential for shallow water flow.
A common method used to mitigate shallow water or gas flows is
to foam the cement. The foams compressibility allows it to offset
the hydrostatic pressure loss that initiates water or gas flow. In
addition, foam cements maintain an internal pressure that
counteracts the loss of volume as the slurry undergoes the
transition between a liquid and set state.
Quick change of plansBecause of these benefits, BJ Services
planned to mix DeepSet cement at 15.2 lb/gal (1.82 g/ml) and use
the automated equipment to foam the lead slurry to 13 lb/gal (1.56
g/ml).
To ensure accurate density during pumping, an Automated Foam
Cement System was loaded onto a delivery boat with the nitrogen.
However, a hurricane swept through the area, blocking the port with
debris.
Rather than try to locate and ship another foam unit, the
operator asked BJ for a different cement solution. BJ engineers
designed a safe nonfoamed lead slurry using the DeepSet cement
system and liquid additives that could be quickly delivered to the
rig from a different port.
The job was pumped successfully with no shallow water flow
problems. In addition, the operator minimized the nonproductive
time on a rig that cost about $650,000 per day.
JOHn ST. cleRgY, Houston
A large-diameter casing station with Salvo torque-turn
monitoring capabilities helped BJ Services completion assembly
personnel prepare a 46-in. circulating cap running tool for
operations in the North Sea. Two pieces of equipment were
engineered and manufactured for this work: A 22-in. power tong to
apply 100,000 ft-lb (149,000 N-m) of torque on the 6.5-in.
drillpipe, and an adapter to securely grip the massive tools on the
casing station. After assembly, the team pressure-tested the tools
to 500 psi (3.4 MPa) before third-party testing verified the
assembly.
JeFF THOM, Aberdeen
Enormous tool prepared
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6 B J T e c h L i n e www.bjservices.com/techline
CT tools enable cleaning of multilateral wellsA unique
combination of patented coiled tubing tools recently enabled BJ
Services to remove sand and mud from three low-pressure,
multilateral wells in northwestern Louisiana.
The wells were completed openhole in a limestone reservoir with
bottomhole pressures around 1000 psi (6895 kPa) at 5900 ft (1800 m)
TVD, with the deepest total depth of 13,400 ft (4085 m). Two wells
were bilateral and the third was drilled with four laterals.
Minimizing fluid on the formationPrevious cleanout attempts
using conventional techniques had taken more than one month per
well to complete and resulted in incomplete fill removal due to
continuous loss of fluids to the formation. For this reason, the
Sand-Vac system was used on a 2 x 1-in. concentric coiled tubing
string.
The award-winning ComPlete MST system recently saved an
estimated 14 days of rig timevalued at $2.1 millionfor a well in
Indonesia.
BJ Services installed a six-zone, 2764-ft (843 m) bottomhole
assembly in one trip to 13,428 ft (4092 m). Despite 16 hours of
nonproductive time (NPT) unrelated to BJ equipment, the job was
completed in 4.5 days, from picking up the tools to finalizing the
outer assembly with a 6000-psi (41.3 MPa) test after the final
pumping job.
During this series of three wells, BJ completed 16 zones in 31
days with about 2 hrs of NPT. The total completion operation time
was only 14 days for all three wells. The customer estimated that
the combined operations saved at least 50 days of rig time.
cHUnMIng lI, Indonesia
BJ Services expanded its coiled tubing and nitrogen services to
Bolivia in October, beginning with two operations in the
Naranjillos field.
The first operation was a matrix stimulation treatment using BJ
Sandstone Acid system and Gas Zone Acid, which increased gas
production from 0 to 177 Mscf/D (5,000 sm3/D) without water cut.
The second was a sand and scale wash using a Vortex nozzle.
JOS lUIS MORAleS, bolivia
Single-trip completion saves days of rig time
CT, nitrogen service expands
BJ Services recently extended its InjectSafe technology record
by successfully relieving a liquid loading issue in the UK sector
of the North Sea.
Several gas wells on a large platform had stopped producing. The
operator considered several methods to restore continuous
production, but most of the economically viable options would
impede functionality of the wells surface-controlled subsurface
safety valves (SCSSV).
Modeling and analysis of the first wells loading
characteristics, using BJs proprietary FoamXpert software,
confirmed that liquid loading was causing the wells impeded
production. Further analysis revealed that injecting foam to the
perforations could solve the problem.
To provide a clean path for foaming chemical treatment all the
way to the perforations, BJ proposed to install its InjectSafe
technology.
BJ crew members snubbed more than 16,500 ft (5029 m) of 3/8-in.
capillary tubing into the well and connected the top of the
capillary string to an InjectSafe wireline-retrievable SCSSV. The
entire procedure was performed live, with a production tubing
pressure of at least 850 psi (5860 kPa).
The technology restored the well to continuous production, and
additional installations are scheduled.
MIcHAel TAggART, Aberdeen
Through-tubing solution relieves liquid loading
InjectSafe technology was used to restore continuous production
to a liquid-loaded well in the North Sea.
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www.bjservices.com/techline B J T e c h L i n e 7
CT tools enable cleaning of multilateral wells
The Discovery stimulation vessel was used to frac a hot,
high-pressure formation offshore India, resulting in enormous
production improvements.
Coiled tubing technology is used to remove proppant and other
fill from a low-pressure, multilateral well in Louisiana.
The Sand-Vac tools proprietary jet pump system vacuums solids
into the tool, carrying them out of the wellbore through the CCT
annulus without the need for nitrogen to maintain returns. In order
to gain entry into the laterals, researchers at BJ Services Coiled
Tubing Research and Engineering Centre in Calgary developed a
bridge tool to attach the LEGS multilateral entry system to the
Sand-Vac tool.
During the campaign in early 2009, all eight lateral junctions
were located and entered with the combined tool assembly. As a
result, the operations were able to remove approximately 25 bbl (4
m3) of drilling fluids, formation fines, shale pebbles and proppant
per lateral.
HeATH MYATT, Kilgore, Texas
HPHT frac boosts gasFracture treatments from BJ Services
resulted in enormous production increases in one of Indias most
important gas fields, despite the challenge of a hot, high-pressure
formation.
An operating company drilled 15 appraisal wells in the
Krishna-Godavari basin in eastern India as part of an effort to
determine how to maximize recovery of the fields estimated 20 Tcf
(566 million sm3) in reserves from a formation with extreme
temperatures and pressures.
In May 2009, BJ stimulated one of the appraisal wells to
quantify well deliverability from two zones of interest and to help
determine the necessity of hydraulic fracturing in the full field
development plan.
The well, located in about 230 ft (70 m) of water, was
directionally drilled to about 16,730 ft (5100 m) with a 42
deviation across the intervals of interest. Bottomhole static
temperature was 340F (171C), reservoir pressure 10,900 psi (75.1
MPa) and formation permeability 0.15 md.
Planning for the frac began with fluid testing at the BJ
laboratory in Mumbai. The Medallion Frac HT fluid was found to
provide good friction reduction and suspension of the resin-coated
ceramic proppant under the expected downhole conditions. HighPerm
BR encapsulated breaker was chosen to ensure controlled and
complete polymer degradation downhole.
The two zones were stimulated separately, each beginning with a
mini-frac and step-down test. Stabilized production from the first
zone increased from 0.7 to more than 4 MMscf/D (20,000 to 113,000
sm3); production from the second zone rose to 3.9 MMscf/D (110,000
sm3).
SeRgeY STOlYAROv and gReg deAn, India
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8 B J T e c h L i n e www.bjservices.com/techline
New CT tools increase horizontal frac stages, speedField-proven
coiled tubing tools enable stimulation of more frac stages in less
time than alternative multizone technologies, improving the
economics of long horizontal wells, in particular.
The SureSet process* comprises abrasive perforating down the
coiled tubing, followed by annular fracturing, with zonal isolation
provided by a resettable packer on the CT bottomhole assembly.
The proprietary assembly is run into the well and positioned
precisely using the EasyTag mechanical collar locator. Slips and
the packer are set with pressure and weight, isolating any lower
zones. Perforations are jetted using the EasyCut sand jet
perforator. Finally, the fracture treatment is pumped down the
annulus. After the treatment, the anchor slips and packer retract,
and the assembly can be moved uphole to the next zone, where the
sequence is repeated.
The process can be used in a variety of completion systems,
including conventionally cemented or expandable liners that avoid
costly and complicated completion hardware, such as frac port
systems. In addition, recovery from screenouts
is quick, and no post-job milling is required.
Finally, the process increases the number of zones that can be
stimulated, compared with frac port systems that are typically
limited to 20 ports in a 4 -in. liner. Some operators want 50+
fracture stages per horizontal wellbore.
Recent case histories include: A 22-stage well
in the Bakken shale, treated with 22,000 lb (10,000 kg) of 20/40
Ottawa sand per stage to a depth of 9500 ft (2900 m) in a single
trip of 51 hours.
A 30-stage well in the Bakken shale, treated with 11,000 lb
(5000 kg) of Ottawa sand per stage to a depth of 8500 ft (2600 m)
in a single trip of 66 hours. The job required the use of a
lubricant to allow the CT to apply enough force to set the anchor
and packer for the bottom zone.
A 12-stage well in the Viking formation, treated with 25000 lb
(11,000 kg) of Ottawa sand per stage to a depth of 4900 ft (1500 m)
in a single trip of 17 hours.
*The process is licensed by ExxonMobil Upstream Research
Company.
lYle lAUn, calgaryThe field-proven process increases the number
of zones that can be stimulated, compared with frac port
systems.
a fiber additive in the lead slurry to stop the losses. While
running the casing, losses increased to 100 bbl/hour
(16 m3/hour). Therefore, the BJ service supervisor added fiber
to the mud before batch mixing the slurries.
During the cementing operation, the losses dropped to 20
bbl/hour (3 m3/hr). By the time the tail slurry was finished
pumping, full returns were achieved.
The operator was pleased with the performance of the fiber
additive and with the cement bond log, especially across the thief
zone. The well has since been perforated successfully.
YAcIne bAbAAMeR, HUSAM ellIed and KHAlIFA FITOURI, libya
Cement additive stops lossesFor a recent cementing operation in
Libya, BJ Services engineers designed lead and tail slurries based
on the operators expectations about the formationand then
redesigned them to meet actual downhole conditions and stop severe
fluid losses.
The original plan was to set the 7-in. casing at 3,600 ft (1100
m) with a 12.5-lb/gal (1.50 g/ml) lead slurry and 15.8-lb/gal (1.89
g/ml) tail. During drilling, however, one zone was weaker than
expected, and the well began to experience losses of the 9.2-lb/gal
(1.10 g/ml) mud.
BJ personnel redesigned the slurry as a 11.7-lb/gal (1.40 g/ml)
lead and 14.5-lb/gal (1.74 g/ml) tail, including
The proprietary SureSet assembly includes a mechanical collar
locator, anchor slips, a resettable packer and a sand jet
perforator.
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www.bjservices.com/techline B J T e c h L i n e 9
Capillary tubing used in instrumented abandonmentBJ Services
DynaCoil capillary tubing was recently used in an Australian
coalbed methane well for a unique instrumented plug-and-abandonment
operation.
Capillary services personnel from Kilgore, Texas, ran -in.
capillary tubing into the well with instruments attached at several
depths corresponding to coal seams in the reservoir. A BJ pumping
services crew from Perth then pumped cement through the capillary
to fill the casing to surface.
The operator benefited from the smaller equipment footprint
(compared with a normal plug-and-abandon operation) and lower
costs. In addition, the instruments, cemented into the well, will
continue to monitor pressures from the coalbed methane reservoir
and transmit data to surface equipment.
bRYAnT STOKeS, Kilgore, Texas
B R I E F L Y N o t E D
Congo CampaignRecent stimulation treatments in the Republic of
Congo included StimPlus services, in which a Wax-Chek paraffin
inhibitor was pumped during hydraulic fracturing to prevent
damaging deposits as the well produces. (Johnny Falla, Congo)
Proppant PremieresLiteProp 108 ultra-lightweight proppant was
pumped in several fracture treatments in Argentina and
Colombiamarking the first use of BJs newest ultra-lightweight
proppant technology in those countries. In Colombia, the proppant
was used for the first time to prevent closure after an acid frac.
(Marcelo Valdivia and Roberto Sentinelli, Argentina; and Ruben
Castillo, Colombia)
Acid AchievementDivert S acid, a self-diverting
surfactant-gelled HCl system for matrix and fracture acidizing, was
recently pumped in Brazil for the first time as the main treatment,
successfully stimulating a well in the Campos Basin. (Abraho Jardim
and Fernando Gaspar, Maca, Brazil)
Protective PackA screen prepacked with sand and 12/20-mesh
ScaleSorb solid chemical has been manufactured for a Gulf of Mexico
operator. The pack material comprises a scale inhibitor adsorbed
onto a solid substrate to provide long-term inhibition in produced
water. The material, field-proven in fracture stimulation and
frac-pack treatments, is also being used in gravel packs. (Amit
Singh and Steve Szymczak, Houston)
Better BorateThe new, high-yield Lightning Plus fluid has been
pumped in several fracture stimulation treatments for an operator
in Mississippi. The borate fluid system works with lower polymer
loading at relatively high formation temperatures, reducing costs
and gel residue. (Stan Craft, Columbia, Miss.)
Redesigned RetarderA new high-temperature synthetic retarder,
SR-34L, replaced conventional lignosulfonate retarders in a recent
Haynesville shale cementing operation, providing more predictable
thickening time and better compressive strength. (Paul Zaher,
Bossier City, La.)
Vapor VarietyA recent fracture stimulation operation marked the
first VaporFrac treatment in the state of Arkansas. The technique
combines Liquid LiteProp technology with high-pressure nitrogen to
ensure good proppant transport with minimal fluid. (Ryan Dent,
Tulsa, Okla.)
Fast work serves operatorWhen an operator called one Sunday
evening in October with an emergency request for a safety valve, BJ
Services personnel responded by providing high-quality equipment on
a tight deadline.
During a recompletion of an offshore well, another suppliers
tubing-retrievable safety valve failed to operate and had to be
locked open. The operator called several suppliers for a
replacement wireline-retrievable valve, but only BJ Services could
meet the operators tight deadline.
A FlowSafe safety valve system was machined to order, assembled,
tested and delivered to the rig for installation in just 46 hours
with no safety incidents.
MAx MOndellI, Houston
A novel approach to abandonment reduced the cost and footprint
of the operation and provided the operator with ongoing pressure
data to monitor reservoir drawdown.
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10 B J T e c h L i n e www.bjservices.com/techline
Chemical-free technology enhances production
Economical, ecologically benign technology stimulates production
by altering near-wellbore chemistry.
Downhole Deposition causes production declines and well failures
around the world. Traditional stimu-lation treatments remove
damaging deposits from the near-wellbore area, perforations and
tubing but may create economic, environmental and safety
challengesor even cause new near-wellbore concerns.
Instead, the new EcoWave technology from BJ Services uses tuned
energy waves to alter molecular bonds downhole, stimulating
production increases by disrupting damaging deposits and altering
relative permeability in the near-wellbore area.
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www.bjservices.com/techline B J T e c h L i n e 11
molecules stay in solution longer, minimizing agglomeration, and
relative permeability to both oil and water are affected in a way
that promotes additional oil production.
To employ the technology (for which a patent has been applied)
in the field, wave frequencies are chosen to optimally target
specific chemical bonds. Using a fit-for-purpose antenna deployed
on the tree or into the annulus through the wellhead, a treatment
lasts from 30 minutes to two hours. Results have been demonstrated
to last as long as three months.
Ultimately, the EcoWave systems greatest benefit is economic:
reduced lifting costs and increased hydrocarbon production. After
extensive laboratory testing, the technology has been used in more
than 60 wells in Texas, Oklahoma, New Mexico and Utah. Applications
have included both flowing and pump-assisted wells.
Real-world improvementsImportantly, operators have reported
production increases from 20 to more than 120%, compared with
slight increases in chemically treated offsets. All wells are being
monitored to determine treatment longevity, with benefits
continuing more than 60 days after treatment in most wells.
The technology was recently used to stimulate eight wells near
Levelland, Texas. Historically, the wells had been treated with hot
water every 90 days to maintain production, and with occasional
workovers to remove deeper organic deposits. Two months after the
EcoWave treatments, oil production had increased by as much as 20%,
and gas chromatography results indicated a significant reduction in
long-chain carbon molecules. All eight wells produced continuously
with no issues for the three-month test period after the
treatment.
In another example, the technology was used in two wells near
Hobbs, N.M. Historically, these wells were treated with hot oil
every 90 days to maintain production. Fifteen days after an EcoWave
treatment, oil production from Well #1 had increased by 57% and
from Well #2 by 126%. The increased production was sustained for at
least 90 days. An offset well that was treated only with chemicals
(dispersant, solvent and wetting agent) has recorded mostly steady
production.
This text is adapted from an article in the October 2009
issue of E&P magazine.
For more information, please contact BJ Services
representatives Carlos Camacho, Greg Darby or
J.R. Becker, or visit www.bjservices.com/techline
Near-wellbore damageA number of damage mechanisms can affect a
wells ability to produce.
Pressure and temperature changes in the near-wellbore area,
perforations and in the tubing affect the chemistry of the produced
fluids: Paraffins and asphaltenes begin to deposit from produced
hydrocarbons and from produced water. These changes also cause
hydrate and salt blocks that affect production, downhole equipment
and surface equipment.
Produced water can also carry and create other downhole
problems: bacteria, fines migration, clay swelling, emulsions, and
corrosion.
Traditional solutions canif not properly engineeredcreate
additional problems. For example, inexpensive hot oil and hot water
treatments are often used to melt waxy wellbore deposits for easy
removal. Typically, these treatments affect only the upper 1000 ft
(300 m) of the tubing because the treatment fluid cools as it
falls, thus losing effectiveness. They also generally affect only
the lighter waxes, leaving heavier, more persistent deposits that
eventually must be resolved with an expensive workover.
As another example, incompatible fluid treatment systems
(biocides, scale and corrosion inhibitors, non-emulsifiers, etc.)
can alter formation wettability and relative permeability, thereby
inhibiting production.
Given the wide variety of downhole problems and the potential
for common solutions to exacerbate one problem while treating
another, a main goal of any stimulation or remediation treatmentand
the focus of BJs BlueField services for mature fieldsshould be to
first, do no harm.
Using energy wavesThe latest addition to this fit-for-purpose
stimulation portfolio is the new EcoWave technology, an
environmentally friendly, chemical-free means of stimulating
hydrocarbon production by removing near-wellbore damage. Instead of
chemical and mechanical energy, this safe and economical technology
uses directed energy waves to alter downhole fluid chemistries.
The theory behind the technology is the use of tuned energy
waves as a means of altering proton and electron spin states, which
affects molecular bonding (Becker and Brown, SPE 124144).
Calculations related to the process of wax crystallization
suggested that a low-energy system tuned to ideal wavelengths could
interfere with static forces and hydrogen bonding. The result is
similar to that of typical oilfield threshold inhibitors and
surfactants: Potentially problematic
The EcoWave unit is compact, portable and robust enough for
routine oilfield use..
EcoWave technology from BJ Services stimulates production
without chemicals, providing ecological and economic benefits
compared with traditional treatments.
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12 B J T e c h L i n e www.bjservices.com/techline
quickly in response to specific events or changing conditions:
downhole pressure and temperature changes, geological events such
as salt migration, or pipe movement. To avoid this type of damage,
its important to understand the reservoir and consider events that
may affect the cement over the life of the well. For example, a
well that is likely to see high injection pressures from
stimulation or flooding operations may need a cement with more
flexural strength (Figure 1).
Chemical attacks, including corrosion, are slow but can be
exacerbated if the chemical agents have access to greater cement
surface area, such as if the cement sheath has already been damaged
due to mechanical stress, or if a poor primary cement job resulted
in channels or micro-cracks.
Chemical attacks can damage the cement in two ways. Expansive
attacks, such as those from sulfate-containing formation fluids,
create poorly soluble products that increase pressure within the
cement until it cracksproducing new surface area for additional
chemical attack. Dissolving attacks, such as those from acids or
magnesia-containing fluids, create water-soluble products that can
be removed from the surface, creating voids and additional surface
area for further attacks.
For example, CO2 attacks set cement in a three-step process
(Figure 2):
1) CO2 reacts with water to form carbonic acid.
2) Next, this acid reacts with portlandite in the cement to
create calcium carbonate
International interest in CO2 sequestration has increased
awareness of laboratory research indicating that corrosive
chemicals can attack oilfield cements, reducing their effectiveness
over the long term.
The potential economic, health and environmental consequences of
cement failure are severe. However, cement corrosion is not as
prevalent in real-world cementeven in wells exposed to corrosive
fluids for several decadesas it appears in the laboratory.
Furthermore, good cementing practices and thoughtful slurry
design can minimize the opportunity for corrosion and ensure that
the resulting cement performs as expected for the life of the
well.
Damage mechanismsThe main purposes of the cement sheath are
zonal isolation and support for the casing, including protecting
the casing from formation fluids and potential corrosion. Thus,
damage to the cement can result in loss of production, mingling of
producing zones, damage to the casing and even collapse of the
pipe, requiring abandonment.
The best way to maximize the life of a cement sheath is to
follow good cementing practices when placing it: condition the
hole, centralize the pipe, and rotate/reciprocate during pumping to
ensure complete fill.
After a good cement sheath is in place, the two most significant
potential damage mechanisms are mechanical stress and chemical
attack.
Stresses and mechanical loads cause damage
Cementing in corrosive environmentsNew technologies and good
cementing practices minimize the potential for corrosive attacks
from formation fluids, injected and in-situ gases, and downhole
chemical systems.
Figure 1. Tangential stress graphs comparing survivability of
flexible PermaSet cement (left) with conventional Class G cement
(right), in a system where wellbore pressure increases by 500 psi
(3450 kPa) and temperature by 80F (27C).
Radial/Tangential Stress Field Radial/Tangential Stress
Field
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www.bjservices.com/techline B J T e c h L i n e 13
Finally, recall that in the second step of a CO2 attack,
reaction of carbonic acid with portlandite creates water, which is
then available to react with CO2 to create more carbonic acid.
Reaction with the C-S-H phases does not create the additional water
needed to carry on the process. The C-S-H phases are also critical
to developing strength as the cement sets, whereas portlandite does
not contribute to cement
strength. Furthermore, the portlandite crystals disrupt the
interlocking mechanism of C-S-H phases, increase the brittleness of
set cement and can be easily leached out during corrosive
attacks.
Therefore, in the new CO2 corrosion-resistant PermaSet cement
system, all portlandite is converted into C-S-H phases during the
setting process. This and a lower water-to-cement ratio reduce the
cement permeability and ensure good compressive strength with
flexibility to vary other mechanical properties to create
fit-for-purpose designs. For the PermaSet systems, a significant
amount of Portland cement is replaced by cost-effective and
CO2-free pozzolanic materials, resulting in an economical and
environmentally sustainable cement system with technical
advantages.
C o N C l U s i o N s
To minimize corrosion of oilfield cement:
Follow good cementing practices, such as engineered spacers,
centralizing the pipe, rotating and reciprocating, etc.
Improve cement bond and reduce formation permeablity with a
preflush of Surebond spacers
Design the cement system with mechanical properties that will
accommodate reservoir conditions and stressesincluding hydraulic
fracturingthat may affect the sheath over its lifetime
Use fit-for-purpose cements designed to minimize specific
corrosion attacks expected over the life of the well
For more information, please contact BJ Services
representative Andreas Brandl, or visit
www.bjservices.com
and more water, or with the C-S-H phases to create calcium
carbonate and amorphous silica gel.
3) Finally, additional carbonic acid reacts with the calcium
carbonate, creating highly soluble calcium bicarbonate. The result
is a weakened, porous cement sheath, which allows deeper chemical
attack and further dissolution.
Minimizing corrosionThe chemical damage process sounds
disastrousand can bebut it is typically very slow. For example, a
well in West Texas was cemented with neat Portland cement around
15.5 lb/gal (1.9 g/ml), and exposed to reservoir temperatures of
130F (54C) and pressure of 2600 psi (18 MPa) for 25 years, allowing
extensive hydration of the cement. It was then exposed to CO2-brine
in enhanced recovery efforts for 30 years. Finally, the cement was
sampled, and corrosion depth was found to range from 0.07 to 0.4
in. (2 to 10 mm) (Carey et al., 2007).
CO2 has been injected into oil and gas wells as a stimulation or
enhanced recovery fluid for more than 30 years. In that time, no
reports have surfaced to show well failures or leaks that could be
attributed only to CO2 corrosion of the cement sheath. Still, it is
a risk that should be minimized.
One way to accomplish that is to minimize the water available to
form the carbonic acid that begins the corrosion cycle. Because set
cement is a water-filled porous system, even a dry CO2 flood can
produce carbonic acid. However, good mixing practices and careful
attention to water-to-cement ratio during pumping will minimize the
capillary pores responsible for permeability.
Reducing the permeability of the set cement means CO2 and other
chemicals cannot easily diffuse into the cement matrix.
Figure 2. CO2 attacks cement in a three-step process. One way to
slow the process is to minimize cement water content and chemical
reactions that create additional water.
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Ultra-deepwater frontiers beckonEnormous reserves have always
been out there, under ultra deep waters around the world. Whats new
is the current obsession with developing them, and thats the result
of a perfect storm: operator economics driving developments of new,
enabling technology that creates new economic drivers for another
cycle. From well construction through completion and production, BJ
Services fuels the storm with state-of-the-art tools and services
that improve economics, logistics and safety for ultra-deepwater
development.
From Brazils Tupi field to the South China Sea, in water depths
greater than 5000 ft (1500 m) and with target formations at 10,000
to 30,000 ft (3000 to 9000 m) below the mudline, ultra-deepwater
developments are an enticing new frontier for both operators and
service com-panies. However, these high-value properties need new
technologies to make them economical and to maximize resource
recovery.
Even in less challenging offshore wells, high bottomhole
pressures and temperatures, corrosive fluids and long pay intervals
have sparked development of reliable well construction and
completion technologies, with much more under way. Now, as water
and well depths increase, downhole systems that were typically
rated for 10,000 psi (68 MPa) differential pressures a few
years ago are now available to 15,000 psi (103 MPa), with rugged
20,000-psi (138 MPa) systems under design.
Rig costs are steep for these ultra-deepwater projects, so
reliable, synergistic technologies and services that save rig
timewithout compromising safety or job qualityare important to
ensure development economics. In addition, technologies that
minimize fluid, proppant and chemical volumes simplify the
logistics related to delivering materials far offshore.
Finally, workovers on these subsea developments are
prohibitively expensive, so durable and reliable technologies are
vital, as are technologies that provide flow assurance by
inhibiting downhole problems such as scale deposition or hydrate
formation.
14 B J T e c h L i n e www.bjservices.com/techline
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HPHT solutionsThe initial challenge for ultra-deep wells has
been the combination of pressure and temperature. Wells in the Gulf
of Mexicos Lower Tertiary play are expected to see initial
bottomhole pressures of some 20,000 psi (138 MPa) and temperatures
in the range of 400F (204C).
Individually, high pressure and temperature are minor concerns
for oilfield equipment, and specialized tools are available for one
condition or the other. But combining both creates a design
nightmare. In addition to affecting material strengthwhich affects
pressure rating high temperatures increase corrosion effects and
increase the chance for stress cracking. Furthermore, the extreme
depths increase stretch on tool strings, altering their reactions
to mechanical manipulations such as picking up and setting down
weight.
For these reasons, oilfield equipment for ultra-deepwater must
be redesigned based on rigorous evaluation to ensure that it is as
reliableor even more sothan prior generations of equipment.
The new CompSet II HP Ultra packer, for example, is functionally
the same as prior CompSet packer technologies, but it was
re-engineered for extreme conditions, achieving an ISO 14310 V0
rating at a differential pressure of 15,000 psi (103 MPa) and
temperature of 350F (177C).
The Ultra packer technology is used for gravel packing,
high-rate water packing, frac packing and stimulation. Packers and
completion systems for even more extreme conditions are in the
research phase, with operators looking ahead to developments that
may see pressures up to 30,000 psi (207 MPa) and temperatures above
400F (204C).
Extreme well constructionSimilarly, cementing technology is
challenged to meet the extreme deepwater requirements. BJ Services
has led this effort since 2004, when a customer asked BJ to cement
a well with anticipated bottomhole temperature above 580F (304C)
and pressure above 35,000 psi (241 MPa). The result was XtremeSet
cement, which was used successfully in the highest-pressure well
drilled to date in the Gulf of Mexico, and the longest solid
expandable tubing liner ever run (see page 22).
For less-demanding well segments, DeepSet cement provides early
compressive strength development to control shallow water and/or
gas
www.bjservices.com/techline B J T e c h L i n e 15
www.bjservices.com/techline B J T e c h L i n e 15
(continued on page 16)
Saving days of rig time by completing several zones in one trip,
BJ Services personnel run the ComPlete MST system into a well
offshore Indonesia.
Facing page: A BJ Services pipeline dewatering spread arrives at
a deepwater location.
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Quality control and continuous improvement efforts ensure
reliable, long-term performance from all BJ Services screensshown
here being run offshore Indonesia.
16 B J T e c h L i n e www.bjservices.com/techline
saving days of rig timeTo achieve economic goals, deepwater
wells typically require long pay zones, which can be difficult to
complete for several reasons:
Safety. Perforating one long interval requires running hundreds
of feet of guns.
Reliability. Completion hardware must operate after being
bounced, scraped and manipulated through long deviated segments,
and then continue to operate as expected for the producing life of
the well.
Logistics. Rigs and stimulation vessels have a limited amount of
payload for fluids and proppant.
Economics. Rig time is expensive, and nonproductive tripping
time through deep water adds up.Operators avoid some of these
issues by
completing and stimulating long pay zones as several smaller
zones using stacked frac packs. The new retrievable ComPlete FP
(frac pack) system was designed specifically for ultra-deepwater
frac- or gravel-pack applications.
Based on the CompSet II HP Ultra packer, the tool is
specifically designed for extreme conditions. Features include
extended tool length and positive weight indications for changes in
tool position.
flow in deepwater drilling environments. Shallow water flow is
known to be a concern in many deepwater regions, including the
Caspian Sea, Gulf of Mexico, Indian Ocean, Mediterranean Sea, North
Sea, Norwegian Sea and the South China Sea. It may also be a
problem in the Adriatic Sea and offshore northwestern
Australia.
The Set for Life family of cement systems is designed to be
adaptable and ensure good zonal isolation and casing protection for
the life of a well. The basic XtremeSet and DeepSet systems meet
typical deepwater needs, but the design for a particular well might
also include components from the flexible DuraSet system, the
environmentally compliant EnviroSet system, the lightweight LeanSet
system, the corrosion-resistant PermaSet system, or the
salt-compatible SaltSet system.
To ensure high-quality cement pumping operations, reliable and
automated Seahawk cement units are working on rigs around the
world. Each unit includes an integral precision mixing system that
accurately maintains slurry density and consistency over a wide
range of requirements. For ultra-deepwater applications, the
high-performance 2300-bhp Seahawk unit provides the power, accuracy
and safety required for next-generation wellbore isolation
operations.
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longer than previous one-zone completions in the same area. The
operator estimated the system saved more than three days of rig
time. In another example, recent work in Indonesia saved an
operator more than 14 days of rig time over three wells (see page
6).
One operator planning a project in the Lower Tertiary area
estimated that each five- to six-zone well in the project would
require 100 days to drill and 100 days to complete using
traditional technology. Using the ComPlete MST system will save the
operator about three weeks of rig timemore than $10 million at
current deepwater rig day ratesper well.
Another single-trip solution, the field-proven and reliable
ComPlete HST (horizontal single-trip) system, is designed to enable
gravel packing in long, openhole horizontal sections that require
sand control solutions.
Even with an efficient tool, gravel packing in a horizontal
deepwater well can be challenging. Deepwater wells often have
excessive fluid loss, variations in hole stability and hole
geometry, and/or an extremely narrow pressure window between
bottomhole pressure and fracture gradient. The narrow pressure
window, in particular, can be a significant concern because high
pump rates required for long-distance proppant transport may
fracture the formation, causing fluid loss and a sand bridge during
the
To minimize the potential for erosion even in large treatments
with abrasive gravels, the service tool position is the same in the
squeeze and circulating positions. The Ultra system for larger
casing (9 5/8, 9 7/8 and 10 1/8 in.) has undergone 40-bbl/min (6
m3/min) erosion testing with more than 1 million lb (450 t) of
16/30 bauxite.
single-trip solutionsIn many situations, traditional
stack-and-pack operations are undesirable, necessitating many trips
into the well, and increasing nonproductive time and expense. As
water and well depth increase, tripping time becomes a significant
costoften the bulk of the well cost. Instead, single-trip
completion tools save rig time by combining multiple functions.
For example, the ComPlete MST (multizone, single-trip) system
uses patented technology to facilitate one-trip gravel- or
frac-packed completions across multiple production intervals. To
date, the system has been used to complete 25 shallow- and
deepwater wells in the Gulf of Mexico, India and Indonesia, with as
many as six zones isolated in one trip.
The result is an effective reduction in completion cycle time
and cost. For example, in the Gulf of Mexico, a 9 5/8-in. ComPlete
MST system allowed crews to complete the well and perform frac-pack
stimulations in two distinct zones, with operations lasting only
seven hours
www.bjservices.com/techline B J T e c h L i n e 17
(continued on page 26)
INTEgRATINg FOR SyNERgyMany operators have found that integrated
systems and services create synergies that exceed the value of
individual components and services. BJs Blue Wellbore teams combine
personnel from multiple service lines, working with operators to
create time- and money-saving solutions. For example, a deepwater
integration team can bring together:
Planning services, including Understand the Reservoir First
studies
Cementing services to isolate the formation and protect the
casing
Wellbore cleaning tools and fluid systems
Completion tools, sand control screens and related systems
Tubular services including nonmarking ChromeMaster tongs and
slips, and screen-running systems
Chemical systems for flow assurance and fines control
Pumping services for stimulation
Umbilical and pipeline precommissioning services
Coiled tubing services, including the DuraLink connector
Service tools
Efficient ultra-deepwater fluid systems include weighted
completion and stimulation fluids, pumped from fit-for-purpose
stimulation vessels, such as the Blue Ray vessel shown here.
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0.3 to 0.6 lb/ft2 (1.5 to 2.9 kg/m2) have more space around each
proppant particle, resulting in superior fracture conductivity with
much less proppant (Darin and Huitt, SPE 1291).
Better cumulative productionFor the Oklahoma well, the fracture
stimulation was pumped in six stages with a total of 76,000 bbl
(12,000 m3) of fluid, 1.1 million lb (500 t) of sand and 33,000 lb
(15,000 kg) of LiteProp 108 proppant. Production in the first six
months met operator expectations and was the second highest among
five comparable offsets wells drilled by the operator. (The offsets
were stimulated with 10,000 to 16,000 bbl [1600 to 2600 m3] of
fluid and 290,000 to >325,000 lb [130 to 150 t] of proppant per
stage.)
More significantly, after 14 months, cumulative production from
the well treated using LiteProp 108 proppant exceeded that of every
offset well. Its production remained stable around 26,000 Mcf/month
(740,000 m3/month). Production from the next-best cumulative
producerand highest initial producerstarted higher but declined
after only seven months to a monthly production rate less than the
well treated using LiteProp 108 proppant.
For more information, please consult BJ Services
representative Scott Nelson or Rocky Freeman, or
visit www.bjservices.com/techline
Ultra-lightweight proppant frac improves declines in
production
Value calculation
Challenge: Stimulate long-term production from wells with a
history of rapid post-stimulation declines
SOlutiOn: Design and pump fracture stimulation using LiteProp
108 ultra-lightweight proppant placed in partial monolayers
ReSultS: Achieve highest cumulative production among comparable
offsets with the highest stabilized monthly production rate
18 B J T e c h L i n e www.bjservices.com/techline
An operator looking for a long-term stimulation solution for
wells in the Woodford shale of Oklahoma turned to patented BJ
Services technology.
Traditional fracture stimulation using sand proppants would
result in production increases, but production would decline
rapidly, sometimes after only a few months. As a means of achieving
more stable, long-term production, BJ Services proposed to fracture
one of the wells using LiteProp 108 ultra-lightweight proppant
(ULWP) placed in a partial monolayer design.
ULWP has much lower specific gravity than conventional proppant,
reducing its settling rate in water and providing unprecedented
proppant transport and longer effective frac length. This
transportability allows the creation of proppant partial
monolayers. Conventional multilayer proppant packs are typically
designed at 1 to 2 lb/ft2 (4.9 to 9.8 kg/m2) to achieve about 10 to
12 layers of proppant. Partial monolayers designed at
A frac in the Woodford shale used LiteProp ultra-lightweight
proppant to achieve stable long-term production.
Fracture stimulation using LiteProp ultra-lightweight proppant
has delayed the production declines experienced in offset wells in
an Oklahoma field.
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www.bjservices.com/techline B J T e c h L i n e 19
systems, to select an economical but effective chemical and
surfactant packagean optimized Paravan systemto prevent
emulsions.
Compatibility through chemistryThe Paravan system was pumped as
a component of all the fluid systems injected into the formation
during the completion. This allowed the chemical package to
accompany the fluids as they met the SOBM in the formation,
preventing emulsions from forming.
Initial well production was more than 10 MMscf/D (283,000 sm3/D)
at low drawdown, which was better than the operators expected
potential. After three months, the well has shown no indications of
emulsions, and no remediation or chemical treatment has been
required. These factors significantly improved the economics of the
well compared with the offsets.
For more information, please consult
BJ Services representative Amit Singh,
or visit www.bjservices.com/techline
Optimized stimulation fluids prevent emulsion, improve
productionWhile drilling a 10,500-ft (3200 m) gas well in the Gulf
of Mexico, an operator lost more than 4200 bbl (670 m3) of
synthetic oil-base mud (SOBM) to an underpressured zone.
When smaller losses had occurred on neighboring wells completed
by another service company, the SOBM, high-density completion
brines and frac-pack fluids created emulsions that plugged the
wells immediately after completion, preventing production.
An attempt to clear the emulsion in one well with an acid job
was unsuccessful because injectivity could not be established.
Later, expensive remedial coiled tubing interventions with a
solvent/surfactant chemical enabled sub-optimal production with
high drawdown. Average production from the treated wells was
reported to be about 7.5 MMscf/D (212,000 sm3/D) with more than
6000 psi (41.4 MPa) flowing tubing pressure.
To avoid these problems in the new well, BJ Services performed
detailed compatibility studies with the SOBM, heavy brine and
frac-pack
Value calculation
Challenge: Prevent emulsions, related remediation costs and
production impairment after high losses of oil-base mud
SOlutiOn: Pump completion and stimulation operations with an
optimized Paravan chemical system
ReSultS: Increase gas production and reduce drawdown without
chemical remediation or intervention operations
To prevent emulsions from impairing production from a new Gulf
of Mexico well, BJ Services created an optimal Paravan surfactant
and solvent package.
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20 B J T e c h L i n e www.bjservices.com/techline
proppant to ensure deep proppant transport with minimal frac
height growth, and with FlexSand proppant additive to stabilize the
proppant pack. AquaCon relative permeability modifier was used
during the pad for added water conformance.
After this screenless sand control treatment, no additional
intervention has been required for more than six months, with
production continuing as this article was going to press.
Casing damage and rocksWell B was producing 37 bbl/D (5.8 m3/D)
of oil when its sand control systems began to fail spectacularly,
requiring three intervention operations in two months. In an early
2009 intervention, the wells lower zone was isolated, dropping oil
production without significantly reducing sand production. During a
sand cleanout operation just weeks later, returns included
fragments of casing and formation particles and rocks as large as
-in. in diameter.
No scale or organic deposits were expected in this well, so the
screenless sand control operation comprised a three-stage skin
bypass frac. In two stages, produced water from the field was used
with SpectraStar fluid to reduce job costs; in the other stage,
injection water was used. As with Well A, the fluids carried
LiteProp 125 ultra-lightweight proppant and FlexSand additive.
As this magazine was going to press, this severely damaged well
had been producing continuously for 6 months without further
intervention.
For more information, please contact BJ Services
representative Rubn Castillo or Juan Manuel Rojas,
or visit www.bjservices.com/techline.
Stimulation treatment delays need for expensive
interventionWater flooding is the primary production mechanism for
the high-permeability Caballos sandstone reservoir in Colombias San
Francisco oilfield. Pore pressure has declined and water cut has
increased, so wells produce at maximum drawdown to achieve
economics. Consequently, sand production and proppant flowback have
become common problems in the field.
The problem is expensive, resulting in frequent intervention
operations. Additionally, in some cases, the sand influx damages
downhole pumps, casing and other equipment.
To mitigate the problem, gravel packs have been used in sand
control completions, but gravel-packed wells usually show reduced
productivity index and higher chances of mechanical problems
(collapsed screens, corrosion, etc). For this reason, BJ Services
recommended an alternative strategy in two challenging wells.
First well treatedWell A began filling with sand in early 2009.
By March, two interventions were needed within just two weeks to
maintain production.
During the first intervention, the lower (openhole) zone was
isolated, resulting in production dropping, with continued high
sand production.
In the second intervention, BJ Services recommended a new
treatment: skin removal and screenless sand control.
The operation began with removing scale and organic deposits
from the well using the S3 Acid system and a solvent system,
respectively. The BJ team then pumped a customized SandChek fines
control system to stabilize the formation and prevent fines
migration. The treatment continued with a skin bypass frac using
city water and Viking fluid with LiteProp 125 ultra-lightweight
Value calculation
Challenge: Enable steady, long-term production from wells in a
field with high water cut and severe sand production requiring
frequent intervention
SOlutiOn: Remove scale and other down-hole deposits, and then
pump a screenless sand control treatment
ReSultS: Six months of uninterrupted production after a
treatment that cost 50% less than conventional gravel packs
Fracture stimulation treatments designed to stabilize a
high-permeability sandstone formation and proppant pack have
enabled long-term, continuous production.
PIbefore
(bbl/D/psi)
PIafter
(bbl/D/psi)
Sand production
before (lb/1000 bbl)
Sand production
after (lb/1000 bbl)
Well A 0.19 0.3 12 1.5
Well B 0.04 0.065 N.A.
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www.bjservices.com/techline B J T e c h L i n e 21
a horizontal single-trip system for standalone screen
applications by adapting reliable BJ CompSet II HP packers, setting
and releasing tools, crossover tools, closing sleeves, and
horizontal washdown shoe assemblies.
After modifying the tools to suit the application, the
components were spaced out in the completion workshop and
function-tested to ensure confidence in the systems ability to
achieve the customers objectives.
The system was first used in February 2009 for a 6-in.
standalone screen completion in a well drilled to about 11,400 ft
(3475 m) TD with a 940-ft (286 m) lateral. Over the course of the
five-day lower completion operation, the screen was run, the packer
set, outer and inner acid treatments pumped to remove the mud
filtercake, and the flapper valve closed to ensure
a stable wellbore while running the upper completion
assembly.
The efficient tool and process saved the customer about
US$2.5
million by eliminating a coiled tubing operation to stimulate
the horizontal section, plus three days of time on the
semisubmersible rig spread.
A second version of the system has been used for an 8 -in.
standalone screen completion.
For more information, please contact
BJ Services representative David Subero,
or visit www.bjservices.com/techline
Single-trip completion system improves standalone screen runAn
operator developing a field in the Gulf of Guinea, about 25 miles
(40 km) offshore Nigeria, designed the well completions as openhole
wells with standalone screens. After running the screen into the
well, a coiled tubing operation was typically required to remove
the calcium carbonate filter cake and oil-base mud from the
screen/openhole and screen/washpipe annulus. The operation would
have added expense and nonproductive tripping time to the
completion costs.
Instead, the operator asked BJ Services to provide a completion
system that would have washdown capability while running the screen
assembly into the well, and the ability to displace the oil-base
mud in both annuli.
The field-proven ComPlete HST system could accomplish those
tasks in one trip.
However, it is designed for single-trip horizontal gravel- or
frac-packing operations, so it contains many components that are
not needed for a simpler standalone screen application. As a
result, the operator asked for a less complex and more economical
solution.
Reducing complexity and costTo achieve the operators economic
goals, the BJ Services completion team in Nigeria developed
Value calculation
Challenge: Improve the economics for a standalone screen
completion
SOlutiOn: Develop a completion tool system to run the screen and
remove oil-base mud in one trip
ReSultS: Minimize completion time and save the customer about
U.S. $2.5 million
The efficient tool and process saved the customer about U.S.
$2.5 million plus three days of time on the semisubmersible rig
spread.
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With mud weight of 18.0 lb/gal (2.16 g/cm3), the cement for the
liner was designed at 19.3 lb/gal (2.31 g/cm3) to perform at a
bottomhole circulating temperature of 354F (179C) with zero free
water, fluid loss less than 50 cm3/30 minutes, compatibility with
the salt zone, and adequate time to place and expand the liner.
To ensure good bonding with both liner and formation, the cement
was preceded by a SealBond engineered spacer. The job was pumped
using best cementing practices, with full returns and good density
control. The plug landed at the calculated displacement, and the
liner was expanded over the next 24 hours. The cement maintained
its fluidity, allowing the expansion without issue.
After allowing time for the cement to cure, the shoe was drilled
out and 10 ft (3 m) of new formation was drilled to perform a
leakoff test. No remedial work was required, which allowed the
operator to continue the exploration work.
For more information, please contact
BJ Services representative Bryan Simmons,
or visit www.bjservices.com/techline
Deep, hot liner cement job sets record for expandablesAs the
industry drills deeper, exploring for vast new reserves, challenges
become the normal mode of operation. This increases the demands on
service companies to improve performance and enable continued
operations in environments once considered too difficult to
reach.
A recent example was a cementing operation in the Gulf of
Mexico. The operator had drilled a 9 7/8-in. hole to 21,165 ft
(6450 m) and decided to run a 6217-ft (1895 m) solid expandable
tubular liner from the prior casing shoe. These statistics plus the
bottomhole static temperature of 368F (187C) made the operation the
longest solid expandable liner ever run.
Two additional factors complicated the slurry design: the slurry
would have to remain fluid for 15 hours at this high temperature
while the liner was expanded; and the liner would be set across a
1700-ft (518 m) section of salt.
BJ Services industry-leading experience with cementing
high-pressure, high-temperature wells led engineers to begin the
slurry design process with the XtremeSet cement system, choosing
additives based on extensive lab testing, circulating temperature
determination and simulation data.
Value calculation
Challenge: Safely and effectively cement the worlds longest,
solid expandable tubular liner
SOlutiOn: Design and pump a fit-for-purpose XtremeSet slurry
ReSultS: Successful cement placement, liner expansion and
leakoff test operations, followed by continued drilling
22 B J T e c h L i n e www.bjservices.com/techline
Automated equipment, experienced personnel and robust XtremeSet
cement were drivers behind BJ Services recent record-setting cement
operations in the Gulf of Mexico.
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www.bjservices.com/techline B J T e c h L i n e 23
Three wells near Whiteface, Texas, were originally completed
more than 19 years ago to about 4850 ft (1480 m). All were acidized
on initial completion with 15% hydrochloric acid. Later acid
treatments and pump replacements are surmised based on production
results, but actual well history is unknown.
Because all are presumed to have experienced a number of acid
treatments and therefore a large surface area for acid exposure, a
new treatment was designed for the wells using concentrated weak
acid: a small HCl injection to ensure good fluid entry into the
perforated intervals followed by 2000 gal (8 m3) of 30% acetic acid
solution, and flushed with 40,000 gal (150 m3) of fresh water. The
wells were treated at a low injection rate to minimize the increase
in water production.
After treatment, oil production increased by an average of 145%
and water cut by an average of only 12% on Wells #2 and #3 and by
only 1% on Well #1.
oil production gainsTwo wells in a second area were originally
completed 12 years ago to about 5400 ft (1650 m). They were
acidized initially with 4000 to 5000 gals (15 to 19 m3) of 15%
hydrochloric acid with smiliar long but largely unknown treatment
history.
Recently, the wells underwent the SloTreat process, using 2500
to 3000 gal (9 to 11 m3) of 30% acetic acid solution with ball
sealers for diversion, followed by a flush with approximately
40,000 gal (150 m3) of fresh water.
These treatments resulted in an average oil production increase
of 106% with water cut increase of 2%.
For all five wells, production increases ranged from 9% to more
than 300%, for an average increase of 125%. At the same time, low
treatment rates and the slow-reacting acid controlled water cut
changes from 0% to 12% with an average change of 6%.
For more information, please consult
BJ Services representative Steve Metcalf,
or visit www.bjservices.com/techline
Weak acid technique stimulates mature Permian Basin
wellsCarbonate formations are predominant in the Permian Basin and
are repeatedly stimulated with acids to maintain productivity over
the life of a well. The success of an acid stimulation is dependent
on penetrating deeper into the formation. Strong acids, such as
hydrochloric, are very efficient at creating wormholes into the
formation, but they react very fast. Therefore when they encounter
the surface area created by a previous acid treatment, they spend
before achieving additional penetration (Figure 1).
A weak acid, such as acetic, is retarded enough to achieve
increased penetration where the strong acids cannot. The new
SloTreat process further enhances this penetration of weak acid, as
shown in recent Permian Basin field studies.
Mature wells treatedThe San Andres is a dolomitic formation with
average permeability over 9 md and average porosity greater than
13%.
The keys to a successful stimulation treatment here are deep
penetration, staying out of water and minimizing costs. Since these
wells have been acidized before, the effectiveness of a subsequent
acid treatment depends on making changes to either rate, volume or
type of acid system used. Because rate is limited by the desire to
avoid stimulation of water zones and volume is limited to minimize
cost, a change in acid system is the best option. An acid system
with reactivity control or retardation has to be used.
Figure 1. Unlike repeated strong acid treatments that spend
before they get past previously treated surface areas, the SloTreat
stimulation process creates new pathways into the formation.
Value calculation
Challenge: Increase oil production in five mature wells that
were previously stimulated with strong acid, without significantly
increasing water production
SOlutiOn: Treat wells by pumping slow-reacting acetic acid
solution at low rate
ReSultS: Increase oil production by average of 125% and water
cut by only 6%
First treatment, 15% HCl
Second treatment, 15% HCl
SloTreat process
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24 B J T e c h L i n e www.bjservices.com/techline
less time and with 40% less fluidminimizing the chance of
killing the well and requiring an additional lifting operation.
While running into the live well, nitrified fluid was pumped
through the coiled tubing and the Tornado tool in forward-jetting
mode to fluidize the sand, enabling penetration through two
consolidated sand bridges before reaching total depth.
After reaching the target depth, the tool was switched to
rearward jetting by increasing the pumping pressure and the
nitrogen volume fraction. One 13-hour wiper trip was sufficient to
remove all of the sand from the well.
The well produced hydrocarbons throughout the operation, and was
able to flow unassisted after the job without additional lifting
operations. Production increased from 7.8 to 19.4 MMscf/D (220,000
to 550,000 m3/D).
For more information, please consult BJ Services
representative Manuel Navarro, or visit
www.bjservices.com/techline
Efficient process restores flow to sand- and liquid-loaded
wellAn operator with a J-shaped well off the northeastern coast of
The Netherlands needed help to restore continuous production to a
liquid- and sand-loaded well.
The well had been flowing at 17.7 MMscf/D (500,000 sm3/D) at 290
psi (20 bar) flowing tubing head pressure. After a short shutdown,
the wells production dropped by half, and the well was found to
contain about 160 ft (50 m) of sand.
The well started to produce intermittently but was limited
because sand covered more than 70% of the perforations. To restore
the wells performance, BJ Services proposed a coiled tubing
cleanout operation using its Tornado process.
less fluid, shorter jobBJ Services proprietary CIRCA simulation
software showed that a conventional sand cleanout would leave sand
in the well even after pumping large amounts of fluid over more
than 20 hours. The software showed that the Tornado process,
washing forward on the way into the well and jetting rearward on a
wiper trip out of the well, could clean the well completely in
Value calculation
Challenge: Restore production to a J-shaped well clogged with
fine sand and loaded with liquid
SOlutiOn: Perform a sand cleanout using coiled tubing with
patented Tornado technology and energized fluid
ReSultS: Double production and enable natural flow, using 40%
less fluid and at least seven fewer hours of operations compared
with conventional cleanouts
One wiper trip was enough to remove 160 ft (50 m) of fill from a
J-shaped well offshore in the The Netherlands, where operations
take place under green lights designed to minimize the impact of
oilfield operations on migrating birds.
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www.bjservices.com/techline B J T e c h L i n e 25
gel isolates zones, formation
Replacing mechanical annular isolation systems and temporary
cement, the new GelBlock temporary diverter gel offers a unique
solution for uncemented multizone horizontal well completions.
The gel system is designed for use in horizontal wells to
isolate zones of interest for fracture stimulation. The chemical
gel system can also be used as a non-damaging, temporary sealant
(disappearing cement) between casing and a formation. A patent
application has been filed for the technology.
The system is designed to control the hydration and crosslinking
of a polymer for up to several hours. It can be broken with
conventional breakers in a controlled fashion. The gels can be
designed to provide isolation for several hours or several days.
Development testing has been performed for application in the
Bakken and Marcellus shales at 150 to 250F (66 to 121C).
Freeze jacket material aids pipeline operations
ThermoBond freeze jacket bonding compound is a laminated
polyester hydrophilic material (fabric blanket), which forms a
water-activated, thermally-conductive bond between a freeze jacket
and a pipe. Improper bonding during a pipe freeze operation can
limit the heat energy a freeze jacket can extract from the liquid
inside the pipe, negatively influencing the freeze time and
potentially causing failure of the freeze plug.
Instead, the ThermoBond material ensures tight bonding of the
freeze jacket to the pipe outer wall allowing good conductive heat
transfer, minimizing job time and enhancing safety. It can also
reduce the amount of liquid nitrogen required for the
operation.
The material is manufactured from inert, nonhazardous materials,
and any residue left after removal of the freeze jacket is easily
cleaned with water.
Slickwater fluid systems offer environmental benefits
Designed for use in the hydraulic fracturing of extremely
low-permeability rocks, typically gas shale reservoirs, HydroCare
slickwater fluid systems are specifically formulated to ensure
proper treatment of either fresh or salt water during fracturing
operations. These systems help ensure optimal reservoir protection
and environmental compliance.
The systems include a formulation of high-quality friction
reducers, biocides, clay stabilizers and/or surfactants tailored to
specific fracture treatments and well conditions.
Types and concentrations of additive packages have been
carefully engineered to ensure cost-effective, ecological
compatibility with fresh or salt water and fracturing and formation
fluids.
Salt compatibility includes 2% KCl, KCl substitute and produced
water or flowback water after appropriate testing.
Surfactants enhance oil recovery
By releasing trapped oil from the rock matrix, the new StimMax
surfactants enhance oil recovery.StimMax C surfactant is designed
for enhanced
oil recovery from carbonate formations and StimMax D surfactant
from diatomaceous formations. Both are particularly effective in
naturally fractured, vuggy and high-permeability formations that
are bounded by capillary forces.
The systems provide two production benefits: The fluid is
spontaneously imbibed into the rock matrix, improving oil
displacement; and the rock surface changes from oil- to
water-wet.
As a tertiary benefit in acidizing applications, the surfactants
function as a chemical acid retarder, enabling deeper treatment
penetration or improved fracture etching properties.
gravel-pack system provides economical option
Applicable in either circulating or squeeze sand control
operations, the EZPack gravel-pack (GP) system provides customers
with an economical choice for sand control completions. The system
can be customized based on the particular needs of the well.
Applications include vertical and deviated wells in land and
inland water locations where economics are critical. The system is
also useful in wells that cannot hold a full column of fluid.
The system can be run with a variety of production packers and
other accessories, and can use a full-opening TST3 service packer
for gravel-packing operations.
Completion tools described
The new, comprehensive catalog of BJ Services completion tools
includes technical descriptions, features and benefits for more
than 80 commercially available oilfield products.
Catalog sections include single-trip completion systems, fluid
loss and zonal isolation systems, production flow control systems,
sealbore packers and accessories, tubing-run packers and
accessories, safety systems and well screens.
The catalog is available as a printed document and on a mini-CD
for easy searching and electronic retrieval.
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26 B J T e c h L i n e www.bjservices.com/techline
Ultra-deepwater frontiers beckon(continued from page 17)
alpha stage or an early screenout in the beta stage. To avoid
these problems, LiteProp ultra-lightweight
proppant can be used as gravel in the LitePack openhole gravel
services approach. Ultra-lightweight gravel settles out of fluids
much more slowly than do heavier conventional sands. This buoyancy
greatly extends the length of the open hole that can be packed at a
given pump rate. In addition, pump time can be
cut in half, compared with conventional gravels. The concept has
been used to enable long, horizontal gravel packs in wells around
the world, including the Gulf of Mexico, Brazil and West
Africa.
saving time with fluidsCompletion and stimulation fluids must
also be carefully designed for these wells, ensuring compatibility
with completion tools, tubulars and formation fluids, and
considering rig pump pressure limitations. Pumping large volumes of
fluid is another source of nonproductive time that most operators
would like to minimize.
Weighted fluids are an efficient solution. For example, in a
recent deepwater Gulf of Mexico completion, the operator used
15.4-lb/gal (1.84 g/ml) synthetic oil-base mud to drill a sidetrack
to 16,700 ft (5090 m). After displacement to 15.2-lb/gal (1.82
g/ml) ZnBr2 completion fluid, the well was to be completed with a
frac pack.
In a conventional indirect displacement, mud is displaced to
seawater and then to the desired completion fluid. In traditional
direct displacements, cleaning spacers are built in water and the
completion brine follows the cleaning spacers. For this well,
however, the hydrostatic pressure difference for either of these
options would have required extremely high pump pressures to
achieve the annular velocity required to achieve good cleaning
efficiency. (And a clean well is critical to ensuring that
high-performance completion tools can function as designed!)
Furthermore, the rig pump limited the pump
rate significantly, adding 30 hours of displacement time to the
job, plus any additional time that might be required for cleanup
due to the reduced efficiency.
Instead, BJ completion engineers proposed a weighted
displacement procedure designed to directly displace mud to brine
with premixed cleaning spacers, and to clean the wellbore without
time-consuming filtration cycles. To achieve efficient cleaning,
the displacement used weighted spacers with robust brushes and
scrapers.
After the displacement was pumped and the completion fluid was
in place, it was circulated for one hole cycle before being
considered clean. Total pump time was eight hours, saving an
estimated 15 hours of nonproductive time valued at ~$200,000.
Similar time and pump horsepower savings are possible during
stimulation by employing weighted fracturing fluids, such as our
BrineStar fluid systems.
Another option is to build a fit-for-purpose ultra-deepwater
stimulation vessel, as BJ has done with its new Blue Dolphin
vessel, which will join the Blue Ray and Challenger vessels in the
Gulf of Mexico. The first 20,000-psi (138 MPa) pressure-rated
stimulation vessel specially designed for Lower Tertiary
conditions, the Blue Dolphin vessels mission-critical hardware
includes multiple Coflexip reeled flexible umbilical lines, eight
skid-mounted 3000-bhp Gorilla frac pumps and storage capacity for
2.75 million lb (1250 t) of proppant, 11,800 bbl (1880 m3) of
fluids or completion brines, 12,600 gal (48 m3) of raw acid and
6300 gal (24 m3) of solvent.
Planning for flow assuranceEven after completion,
ultra-deepwater wells face problems. The pressure and temperature
extremes at the bottom of the well increase the potential for
pressure crystallization and hydrate formation as produced fluids
rise. Even for wells that will be produced only to the seabed, cold
water temperatures create a potential for flow assurance
problems.
In some cases, specialized packer fluids, such as the InsulGel
family of fluids, can minimize temperature-related flow assurance
problems. These thermally insulated fluids help minimize heat
transfer from produced fluids, reducing opportunities for paraffin
and asphaltene deposition, and hydrate formation, even during long
shut-in periods.
Because the Lower Tertiary play is expected to be consolidated
rock, experts expect hydraulic fracturing to be a standard
stimulation technology. This opens an opportunity for long-term
flow assurance: StimPlus services, which combine stimulation with
long-lasting, solid chemicals that inhibit scale, paraffin,
asphaltene, salt and/or corrosion.
Because the solid inhibitor is placed with the proppant during
the frac, it reaches deep into the reservoir to prevent flow
assurance problems before they affect production. The treatment has
negligible effect on the cost of a typical stimulation treatment;
however, delaying and/or avoiding intervention reduces operation
expenses and improves project economics, especially in deep
water.
The reliable, automated Seahawk cement unit provides the power,
accuracy and safety required for next-generation wellbore isolation
operations, such as this one offshore Brazil.
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www.bjservices.com/techline B J T e c h L i n e 27
E n u m e r a t i o n s
Maximum working pressure, in psi, of the Blue Dolphin deepwater
stimulation vessel
20,000
Maximum recommended chamber pressure, in psi, for a .38 special
handgun
17,000
Maximum differential pressure, in psi, for a
ComPlete FP single-trip, retrievable frac pack completion
system
15,000
Pressure, in psi, of a household pressure cooker
1515
Length, in miles, of oil & gas pipelines inspected by
BJ technology and people around the world each year
12,400Time, in minutes, required for light to travel 155 million
miles
Time, in minutes, required for light to travel 155 million
miles
Area, in square kilometers, those tiles
would cover
Area, in square kilometers, of Gibraltar
Distance, in miles, driven each year
by BJ Services light and heavy vehicles
155 million
Flight distance, in miles, from your current location to
its antipode
12,400
Years required to inspect a pipeline from the Earth to the
moon
20
Years required to inspect a pipeline from the Earth to the
moon
20
Burst pressure, in psi, of a
blood vessel
Burst pressure, in psi, of a
blood vessel
300300
W Y O M I N G
Mass, in millions of pounds, of TerraProp
intermediate-strength
ceramic proppant pumped in 42 Wyoming wells between
January and July 2009
1.75
Number of 12 x 12-in. ceramic floor tiles combined to weigh 1.75
million lb
525,000
7.02 6.84height, in meters, of the stack of tiles
height in meters, of the Rock of gibraltar
1.75
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BJ TechLine magazine is a periodical publication of BJ Services
Company. Its editorial mission is to inform readers about new and
emerging oilfield technology solutions available to operators in
more than 50 countries around the world. The map above locates
subjects of articles in the current issue.
For articles ending with a , more information is available
online at www.bjservices.com/techline. To request information about
other technologies described in this issue, or to make comments or
suggestions about TechLine, visit the website and click on the icon
or the e-mail link.
Real World. World Class.Worldwide.
Briefs (p. 2)
News (pp. 4-9)
Technology in Focus (pp. 10-17)
BJ in Action (pp. 18-24)
Enumerations (p. 27)