BJ Services Techline Magazine: Year in Review. Tornado Tool (TM) implementation in Ameland....
TechLine A Publication of BJ Services Company
Volume 10
Inside this issue Chemical-free technology enhances production
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Cementing approach minimizes corrosion threat
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State-of-the-art tools benefit ultra-deepwater frontiers
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Ultra-lightweight proppant improves production declines
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Weak acid technique stimulates mature wells
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N E W S B R I E F S
Simultaneous fracs promote production A 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.
New vessel extends services in Asia
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.
Technology 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-thefly changes based on realtime downhole data, thereby ensuring stimulation success.
Tools, fluids clean Middle East well BJ 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 team’s professionalism after the work was completed ahead of schedule and without safety incidents.
C o n t en t s
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Selective solution: Coiled tubing tools clean each leg in multilateral wells.
BJ Services TechLine News
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Quantum quality: Electromagnetic waves stimulate oil production.
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Deepwater diversity: Proven technologies and integrated services improve ultra-deepwater economics.
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Chemical-free technology enhances production
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Cementing in corrosive environments
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Ultra-deepwater frontiers beckon
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BJ in Action: Case histories from BJ Services
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BJ Innovations: Novel solutions to oilfield problems
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Enumerations: A whimsical look at numbers in the oilfield
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BJ TechLine is published by BJ Services Company. Comments and inquiries should be submitted to: Editor: Stephanie Weiss 11211 FM 2920 Tomball, TX 77375 Tel +1 (832) 559-1308 Fax +1 (832) 559-1319 E-mail
[email protected] Copyright 2009, BJ Services Company. All rights reserved.
Coflexip® is a registered trademark of Technip.
Solvent system enables acidizing after OBM An 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 one—a modified Paravan™ D system—that 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.
Hammer sets piles offshore Canada BJ 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.
Table 1. Well A Results Pre-Job
Post-Job
PI
2
4
Skin
–2
–5
For future wells, the cleanup and breaker systems may be combined in a single operation. MAURIZIO FRATUS, Kazakhstan
BJ prepares deepwater infrastructure 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, 4
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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
Combined operation enables 44-zone horizontal frac 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 daylightonly 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
Adaptable cement system minimizes hurricane delay When 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 foam’s 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.
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 recordsetting 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 Castañeda, Luis Castro, Steven H. Craig and Chris Moore, Houston and Fort Worth
Enormous tool prepared A large-diameter casing station with Salvo™ torqueturn 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
Quick change of plans Because 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 www.bjservices.com/techline
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CT tools enable cleaning of A unique combination of patented coiled tubing tools recently enabled BJ Services to remove sand and mud from three lowpressure, 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 formation Previous 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.
InjectSafe® technology was used to restore continuous production to a liquid-loaded well in the North Sea.
Through-tubing solution relieves liquid loading 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’ surfacecontrolled subsurface safety valves (SCSSV). Modeling and analysis of the first well’s loading characteristics, using BJ’s proprietary FoamXpert™ software, confirmed that liquid loading was causing the well’s 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) 3 of /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
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Single-trip completion saves days of rig time The award-winning ComPlete™ MST system recently saved an estimated 14 days of rig time—valued at $2.1 million—for 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
CT, nitrogen service expands 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. JOSÉ LUIS MORALES, Bolivia
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multilateral wells The Sand-Vac tool’s 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
Coiled tubing technology is used to remove proppant and other fill from a low-pressure, multilateral well in Louisiana.
HPHT frac boosts gas Fracture treatments from BJ Services resulted in enormous production increases in one of India’s 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 field’s 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 340°F (171°C), 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). The Discovery™ stimulation vessel was used to frac a hot, highpressure formation offshore India, resulting in enormous production improvements.
SERGEY STOLYAROV and GREG DEAN, India
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New CT tools increase horizontal frac stages, speed Field-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 ½-in. liner. Some operators want 50+ fracture stages per horizontal wellbore. Recent case histories include: The proprietary SureSet™ assembly includes a mechanical collar locator, anchor slips, a • A 22-stage well resettable packer and a sand jet perforator. 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, Calgary The field-proven process increases the number of zones that can be stimulated, compared with frac port systems.
Cement additive stops losses For a recent cementing operation in Libya, BJ Services engineers designed lead and tail slurries based on the operator’s expectations about the formation—and 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 8
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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
Capillary tubing used in instrumented abandonment BJ 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 ¾-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
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Congo Campaign Recent 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 Premieres LiteProp™ 108 ultra-lightweight proppant was pumped in several fracture treatments in Argentina and Colombia— marking the first use of BJ’s 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 Achievement Divert™ 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. (Abrahão Jardim and Fernando Gaspar, Macaé, Brazil)
Protective Pack A 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) 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.
Fast work serves operator When 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 supplier’s 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 operator’s 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
Better Borate The 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 Retarder A 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 Variety A 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.) www.bjservices.com/techline
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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 stimulation treatments remove damaging deposits from the near-wellbore area, perforations and tubing but may create economic, environmental and safety challenges—or 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 nearwellbore area.
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Near-wellbore damage A number of damage mechanisms can affect a well’s ability to produce. Pressure and temperature changes in the nearwellbore 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 can—if not properly engineered—create 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 treatment—and the focus of BJ’s BlueField™ services for mature fields—should be to “first, do no harm.” Using energy waves The latest addition to this fit-for-purpose stimulation portfolio is the new EcoWave™ technology, an environmentally friendly, chemicalfree 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 EcoWave™ technology from BJ Services stimulates production without chemicals, providing ecological and economic benefits compared with traditional treatments.
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-forpurpose 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 system’s 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.
The EcoWave™ unit is compact, portable and robust enough for routine oilfield use. .
Real-world improvements Importantly, 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 www.bjservices.com/techline
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Cementing in corrosive environments New technologies and good cementing practices minimize the potential for corrosive attacks from formation fluids, injected and in-situ gases, and downhole chemical systems.
I
nternational 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 cement—even in wells exposed to corrosive fluids for several decades— as 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 mechanisms The 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 Radial/Tangential Stress Field
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, it’s 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 cracks—producing 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 Radial/Tangential Stress Field
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 80°F (27°C).
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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, Figure 2. CO2 attacks cement in a three-step process. One way to slow the process is to whereas portlandite does minimize cement water content and chemical reactions that create additional water. not contribute to cement and more water, or with the C-S-H strength. Furthermore, the portlandite crystals phases to create calcium carbonate and disrupt the interlocking mechanism of C-S-H phases, amorphous silica gel. increase the brittleness of set cement and can be 3) Finally, additional carbonic acid reacts easily leached out during corrosive attacks. with the calcium carbonate, creating highly Therefore, in the new CO2 corrosion-resistant soluble calcium bicarbonate. The result is PermaSet™ cement system, all portlandite is a weakened, porous cement sheath, which converted into C-S-H phases during the setting allows deeper chemical attack and further process. This and a lower water-to-cement ratio dissolution. reduce the cement permeability and ensure good compressive strength with flexibility to vary other Minimizing corrosion mechanical properties to create fit-for-purpose The chemical damage process sounds designs. For the PermaSet systems, a significant disastrous—and can be—but it is typically very amount of Portland cement is replaced by costslow. For example, a well in West Texas was effective and CO2-free pozzolanic materials, cemented with neat Portland cement around resulting in an economical and environmentally 15.5 lb/gal (1.9 g/ml), and exposed to reservoir sustainable cement system with technical temperatures of 130°F (54°C) and pressure advantages. of 2600 psi (18 MPa) for 25 years, allowing extensive hydration of the cement. It was then C o nc l u s i o n s exposed to CO2-brine in enhanced recovery efforts To minimize corrosion of oilfield cement: for 30 years. Finally, the cement was sampled, and corrosion depth was found to range from • Follow good cementing practices, such as 0.07 to 0.4 in. (2 to 10 mm) (Carey et al., 2007). engineered spacers, centralizing the pipe, rotating CO2 has been injected into oil and gas wells and reciprocating, etc. as a stimulation or enhanced recovery fluid for • Improve cement bond and reduce formation more than 30 years. In that time, no reports have permeablity with a preflush of Surebond spacers surfaced to show well failures or leaks that could be attributed only to CO2 corrosion of the cement • Design the cement system with mechanical sheath. Still, it is a risk that should be minimized. properties that will accommodate reservoir One way to accomplish that is to minimize conditions and stresses—including hydraulic the water available to form the carbonic acid that fracturing—that may affect the sheath over begins the corrosion cycle. Because set cement its lifetime is a water-filled porous system, even a dry CO2 • Use fit-for-purpose cements designed to minimize flood can produce carbonic acid. However, good specific corrosion attacks expected over the life of mixing practices and careful attention to waterthe well to-cement ratio during pumping will minimize the capillary pores responsible for permeability. For more information, please contact BJ Services Reducing the permeability of the set cement representative Andreas Brandl, or visit means CO2 and other chemicals cannot easily www.bjservices.com diffuse into the cement matrix.
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Ultra-deepwater frontiers beckon Enormous reserves have always been out there, under ultra deep waters around the world. What’s new is the current obsession with developing them, and that’s 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.
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rom Brazil’s 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 companies. 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 14
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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 time—without compromising safety or job quality—are 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 solutions The initial challenge for ultra-deep wells has been the combination of pressure and temperature. Wells in the Gulf of Mexico’s Lower Tertiary play are expected to see initial bottomhole pressures of some 20,000 psi (138 MPa) and temperatures in the range of 400°F (204°C). 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 strength—which 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 ultradeepwater must be redesigned based on rigorous evaluation to ensure that it is as reliable—or even more so—than 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 350°F (177°C). 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 400°F (204°C). Extreme well construction Similarly, 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 580°F (304°C) 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 (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. www.bjservices.com/techline
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Quality control and continuous improvement efforts ensure reliable, longterm performance from all BJ Services screens—shown here being run offshore Indonesia.
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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 saltcompatible 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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Saving days of rig time To 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 ultradeepwater 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.
I nte g ratin g for s y ner g y Efficient ultra-deepwater fluid systems include weighted completion and stimulation fluids, pumped from fit-forpurpose stimulation vessels, such as the Blue Ray™ vessel shown here.
Many operators have found that integrated systems and services create synergies that exceed the value of individual components and services. BJ’s 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
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 solutions In 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 cost—often 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
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 fiveto 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 time—more than $10 million at current deepwater rig day rates—per well. Another single-trip solution, the fieldproven 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 (continued on page 26)
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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 R esults: Achieve highest cumulative production among comparable offsets with the highest stabilized monthly production rate
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n 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
Fracture stimulation using LiteProp™ ultra-lightweight proppant has delayed the production declines experienced in offset wells in an Oklahoma field.
A frac in the Woodford shale used LiteProp™ ultra-lightweight proppant to achieve stable long-term production.
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 production For 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 producer—and highest initial producer—started 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
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Optimized stimulation fluids prevent emulsion, improve production While 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
systems, to select an economical but effective chemical and surfactant package—an optimized Paravan™ system—to prevent emulsions.
Value calculation
Compatibility through chemistry The 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 operator’s 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.
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 R esults: Increase gas production and reduce drawdown without chemical remediation or intervention operations
For more information, please consult BJ Services representative Amit Singh, or visit www.bjservices.com/techline
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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Stimulation treatment delays need for expensive intervention Value calculation hallenge: Enable C steady, long-term production from wells in a field with high water cut and severe sand production requiring frequent intervention S olution: Remove scale and other downhole 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
Water flooding is the primary production mechanism for the high-permeability Caballos sandstone reservoir in Colombia’s 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 gravelpacked 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 treated Well 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 Screenless Sand Control Results PI PI before after (bbl/D/psi) (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.
