Efficient process restores flow to sand- and liquid-loaded well in Ameland Island - BJ Techline Magazine

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

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.

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.

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.

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


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.


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


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.


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.


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.


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.


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


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


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.

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.


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.

Quality control and continuous improvement efforts ensure reliable, long-term performance from all BJ Services screensshown here being run offshore Indonesia.


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.

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


(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.

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


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.


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.


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.


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.


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,


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.

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,


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


Automated equipment, experienced personnel and robust XtremeSet cement were drivers behind BJ Services recent record-setting cement operations in the Gulf of Mexico.


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,


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


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.


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.


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.

5334

426

ME

TE

RS


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

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)

Documents

Efficient process restores flow to sand- and liquid-loaded well in Ameland Island - BJ Techline Magazine