Clean Water Subsea

Keeping Water in its Place

From topside to seabed, the Seabox™ SWIT™ technology revolutionizes offshore water treatment.

Clean Water Subsea

Keeping Water
in Its Place

Most wells lose production pressure after only 30 percent of the reservoir is extracted, leaving behind rich reserves. The U.S. Department of Energy and World Energy Council estimate that hundreds of billions of barrels of oil exist in old wells.

Up to 50 percent more oil can be tapped by increasing reservoir pressure via water injection and other methods. Global water injection requirements are projected to double or triple within 10 years, with offshore drilling creating much of this demand.

Removing sediment and bacteria from injection water is never cheap, and moving the process offshore only increases complexity. Oil and gas companies rely on preliminary well test information to estimate oil reserves and production rates before investing in costly topside water treatment systems. Even tiny miscalculations can lose millions of dollars. "Life-of-field" water injection requirements rarely match initial expectations, particularly if satellite fields are discovered and processed via the same offshore infrastructure.

The Seabox™ SWIT™ technology offers a flexible solution that moves offshore water treatment from topside to seafloor. This approach saves the cost, weight and space issues of topside systems and offers a modular approach to water treatment planning. Operators can adjust field drainage strategies as they go, reducing the uncertainties of planning traditional treatment systems within an industrial megaproject. This gives greater flexibility to optimize field drainage during or after investing in the infrastructure, aiding recovery of larger volumes of reserves.

At depths of less than 500 feet/152 meters, offshore production platforms are commonly fixed to the seabed. Deeper water requires self-contained capabilities such as floating production storage and offloading vessels and tension leg platforms. Traditional topside treatment requires bulky equipment costing up to $70,000/ton/tonne and weighing thousands of tons/tonnes. These units require large amounts of deck space, leaving little flexibility for change as reservoir knowledge evolves during production.

Imagine the Seabox SWIT technology as a structure that sits on the seabed and uses an injection pump to draw seawater through it. Disinfection chemicals such as chlorine and hydroxyl radicals are generated via electrolysis on their way through specially designed cells, removing the need for liquid chemicals or moving parts. The convoluted path and long residence time inside the box remove solids via sedimentation and provide a chlorine soak that thoroughly kills bacteria. The system can be scaled to any volume requirement, producing injection water with quality far superior to that of topside systems.

Artist-rendered video, left, represents two years of Seabox SWIT water treatment on the seafloor. A filtration membrane, right, appears almost new after six months of constant use, underscoring the unique capabilities of Seabox.

Subsea water treatment allows reservoir engineers to inject as much water as they need – when and where they need it – without relying on topside infrastructures. The system increases flexibility by relocating treatment units on the seabed, allowing injection to continue independently of platform production shutdowns.

The lack of moving or rotating parts supports a proven record of 99.8 percent reliability, compared with 85 percent for most surface-based seawater injection systems.

The large-volume still room weighs 47 tons/43 tonnes and contains a removable “treatment unit” with a maintenance window of up to four years. The system only requires electrical power for the electrolysis and control systems, with a design life of more than 20 years. The lack of moving or rotating parts supports a proven record of 99.8 percent reliability, compared with 85 percent for most surface-based seawater injection systems.

Major multi-national oil companies have acknowledged the Seabox SWIT technology as fundamental to adding incremental water injection with minimal facility pre-investment, allowing flexible adjustments to reservoir drainage strategies for the lifetime of a field. The technology offers significant environmental and safety benefits that include lower power requirements, no liquid-dosed chemicals, zero chemical handling and reduced offshore manning requirements.

Far below the surface of the ocean, Seabox will quietly transform top-heavy water treatment into a lean, green, maintenance-free machine.

Asset Management

Rugged and Reliable at 400 Degrees

TracID™ provides unprecedented life cycle management for the life of drill strings.

Asset Management

Rugged and Reliable
at 400 Degrees

Without robust life cycle management, rig operations are destined to suffer financially. Radio-frequency identification (RFID) is a critical part of asset tracking, but this technology has always faltered when exposed to unrelenting downhole conditions.

TracID™ from NOV Tuboscope succeeds where other technologies have failed. As part of the industry's most comprehensive life cycle management option, this rugged RFID-based system tracks drill stem asset conditions during all phases of drilling.

At the core of TracID are RFID-enabled tags, engineered for maximum performance in extreme environments. TracTag™ is the industry's only RFID tag field-proven to perform at 400 degrees Fahrenheit (205 degrees Celsius) and 22,500 psi. More than 40,000 in-service units have logged an unprecedented track record of less than one percent failure rate over 10 years of service.

TracID helps ensure that successful life cycle management begins long before drill pipe arrives at the rig. RFID tags are embedded on drill stem assets to capture critical history, such as inspections, repairs and rotating hours. Collected data is uploaded into TruData™ - a comprehensive reporting management system - to ensure that the correct quantity, condition and grade of assets are delivered to the rig.

The AutoTally™ component also delivers a 100-percent accurate drill string tally in real time. As joints are run in hole, a rig floor reader identifies assets and their individual histories, relaying that information to the driller's screen. Maintaining an accurate drill string tally reduces the non-productive time (NPT) associated with missed depths, stuck pipe and twist-offs.

Drill string fatigue failure is the most common and costly type of drilling failure, with an estimated $100,000 per failure.

Drill string fatigue failure is the most common and costly type of drilling failure, with an estimated $100,000 per failure. Monitoring the complete history of assets can detect repetitive issues - such as thread galling, pitted seals or disproportionate connection repairs - and take worn elements out of service before they fail.

A well-documented, current asset inventory can intercept drill pipe that should be repaired or retired. Without this information, fatigued assets can mistakenly become part of a drill string and later fail during drilling. Reliable inventory and quality control can reduce handling costs by up to 90 percent and lower thread repair costs by 44 percent.

Drill stem troubleshooting can identify equipment that may be directly affecting pipe integrity. These trend lines lead to corrective actions that have been proven to extend the productive life of assets by as much as 22 percent, potentially reducing NPT by up to 30 percent.

NOV recently conducted an extensive comparison of managed offshore pipe assets against their standard, non-managed counterparts in the North Sea. Final analysis showed a 55 percent reduction in connection damages for the managed assets, saving $2.7 million over 18 months.

The TracID system also offers the benefits of "intelligent tagging." TracPLATES™ technology integrates RFID transponders into conventional tag plates, or they can be retrofitted into existing metal tags. TracPLATES can be attached to many types of equipment, providing superior inventory control beyond the wellbore.

TracID is currently installed throughout major oil and gas regions from Mexico to the Middle East. Efficient life cycle management is essential for all phases of drilling - because you can't manage what you don't monitor.

High Temperature

Staying Cool Under Pressure

The TUNDRA™ MAX mud chiller reduces downhole drilling temperatures for longer equipment life and faster drilling.

High Temperature

Staying Cool
Under Pressure

The heat is on for well operators, and it's only getting hotter. Deeper wells mean higher borehole temperatures, with drilling friction adding to the hot, unforgiving downhole environment. This one-two punch can knock heat levels above 300 degrees Fahrenheit/149 Celsius - the threshold where equipment begins to break down more often.

Excessive heat can stall the performance of components such as drilling motors and rotary steerable systems, dramatically shortening their life spans. Heat-damaged electronic components can silence data collection and communication in the downhole environment, increasing rig non-productive time and equipment repair costs.

TUNDRA™ MAX land mud chillers are closed-loop refrigeration systems designed to cool drilling fluids even under extreme conditions. A portable, computer-controlled, dual-stage mud chilling system cools high-temperature mud in a two-stage process.

Within normal temperature ranges, drilling fluid protects downhole equipment and maintains optimal performance. Extreme temperatures degrade mud properties, creating issues such as increased mud loss, thermal instability and inconsistent rheology measurements. Mud performs best at lower temperatures, saving the cost of additives or replacement.

Cooler drilling fluid prevents heat-related equipment failures and recoups time throughout the drilling process. Stable downhole temperatures reduce the time needed to recondition mud returned from the wellbore. This speeds up the process to re-optimize mud formulas for downhole temperature fluctuations, all while providing better wellbore stability.

TUNDRA MAX performs when conventional cooling methods fail. Air cooling is slow, inefficient and highly dependent on ambient temperatures. The dual-stage cooling system can actually reduce the temperature of processed drilling fluid to below the ambient air temperature.

Air systems have limited value in regions with extreme climates. This is especially true in places like the Middle East where temperatures can climb above 120 degrees Fahrenheit/49 Celsius. Water-based cooling systems require a local water source - an uncertain commodity at some remote land drilling sites.

In 2015, a detailed field study in the Eagle Ford shale tested how well TUNDRA MAX could reduce drilling fluid temperatures at a high flow rate with a small footprint. The study compared wells in South Texas equipped with advanced drilling automation tools, both with and without the mud chiller. The analysis included drilling speed, efficiency and downhole tool operational safety.

The well not using the mud chiller logged two temperature-related downhole tool failures, causing significant downtime. When TUNDRA MAX was activated on the second well, the operator reported zero temperature-related failures. A reduction in downhole tool trips alone allowed the well to be drilled two days faster than the previous well.

A reduction in downhole tool trips alone allowed the well to be drilled two days faster than the previous well.

In this same study, the battery on the high-speed downhole dynamics measurement tool achieved 240 of 250 hours of maximum battery life. This unprecedented 44 percent increase – up from 167 typical hours – was credited to TUNDRA MAX reducing bottomhole temperature by 22 degrees Fahrenheit/12 Celsius.

Superior cooling reduced the amount of circulation required to lower the temperature of the well. The cooler environment gained an additional 1,000 feet/305 meters before equipment-damaging temperatures were encountered. Drilling restarted sooner and saved 51 hours of non-productive time.

Well operators in southern Louisiana have also confirmed the high performance of TUNDRA MAX. The mud chiller was enabled on a well at 16,900 feet/5,150 meters, reducing the temperature gradient by 15 percent and saving 28 hours of temperature-related downtime.

TUNDRA MAX mud chillers eliminate dependence on local air and water conditions while extending equipment life and increasing drilling performance. These tough, efficient units are giving well operators a faster, more reliable way to beat the heat.

Keeping Water in its Place

Clean Water Subsea

Most wells lose production pressure after only 30 percent of the reservoir is extracted, leaving behind rich reserves. The U.S. Department of Energy and World Energy Council estimate that hundreds of billions of barrels of oil exist in old wells.

Up to 50 percent more oil can be tapped by increasing reservoir pressure via water injection and other methods. Global water injection requirements are projected to double or triple within 10 years, with offshore drilling creating much of this demand.

Removing sediment and bacteria from injection water is never cheap, and moving the process offshore only increases complexity. Oil and gas companies rely on preliminary well test information to estimate oil reserves and production rates before investing in costly topside water treatment systems. Even tiny miscalculations can lose millions of dollars. "Life-of-field" water injection requirements rarely match initial expectations, particularly if satellite fields are discovered and processed via the same offshore infrastructure.

The Seabox™ SWIT™ technology offers a flexible solution that moves offshore water treatment from topside to seafloor. This approach saves the cost, weight and space issues of topside systems and offers a modular approach to water treatment planning. Operators can adjust field drainage strategies as they go, reducing the uncertainties of planning traditional treatment systems within an industrial megaproject. This gives greater flexibility to optimize field drainage during or after investing in the infrastructure, aiding recovery of larger volumes of reserves.

At depths of less than 500 feet/152 meters, offshore production platforms are commonly fixed to the seabed. Deeper water requires self-contained capabilities such as floating production storage and offloading vessels and tension leg platforms. Traditional topside treatment requires bulky equipment costing up to $70,000/ton/tonne and weighing thousands of tons/tonnes. These units require large amounts of deck space, leaving little flexibility for change as reservoir knowledge evolves during production.

Imagine the Seabox SWIT technology as a structure that sits on the seabed and uses an injection pump to draw seawater through it. Disinfection chemicals such as chlorine and hydroxyl radicals are generated via electrolysis on their way through specially designed cells, removing the need for liquid chemicals or moving parts. The convoluted path and long residence time inside the box remove solids via sedimentation and provide a chlorine soak that thoroughly kills bacteria. The system can be scaled to any volume requirement, producing injection water with quality far superior to that of topside systems.

Artist-rendered video, left, represents two years of Seabox SWIT water treatment on the seafloor. A filtration membrane, right, appears almost new after six months of constant use, underscoring the unique capabilities of Seabox.

Subsea water treatment allows reservoir engineers to inject as much water as they need – when and where they need it – without relying on topside infrastructures. The system increases flexibility by relocating treatment units on the seabed, allowing injection to continue independently of platform production shutdowns.

The lack of moving or rotating parts supports a proven record of 99.8 percent reliability, compared with 85 percent for most surface-based seawater injection systems.

The large-volume still room weighs 47 tons/43 tonnes and contains a removable “treatment unit” with a maintenance window of up to four years. The system only requires electrical power for the electrolysis and control systems, with a design life of more than 20 years. The lack of moving or rotating parts supports a proven record of 99.8 percent reliability, compared with 85 percent for most surface-based seawater injection systems.

Major multi-national oil companies have acknowledged the Seabox SWIT technology as fundamental to adding incremental water injection with minimal facility pre-investment, allowing flexible adjustments to reservoir drainage strategies for the lifetime of a field. The technology offers significant environmental and safety benefits that include lower power requirements, no liquid-dosed chemicals, zero chemical handling and reduced offshore manning requirements.

Far below the surface of the ocean, Seabox will quietly transform top-heavy water treatment into a lean, green, maintenance-free machine.

Rugged and Reliable at 400 Degrees

Asset Management

Without robust life cycle management, rig operations are destined to suffer financially. Radio-frequency identification (RFID) is a critical part of asset tracking, but this technology has always faltered when exposed to unrelenting downhole conditions.

TracID™ from NOV Tuboscope succeeds where other technologies have failed. As part of the industry's most comprehensive life cycle management option, this rugged RFID-based system tracks drill stem asset conditions during all phases of drilling.

At the core of TracID are RFID-enabled tags, engineered for maximum performance in extreme environments. TracTag™ is the industry's only RFID tag field-proven to perform at 400 degrees Fahrenheit (205 degrees Celsius) and 22,500 psi. More than 40,000 in-service units have logged an unprecedented track record of less than one percent failure rate over 10 years of service.

TracID helps ensure that successful life cycle management begins long before drill pipe arrives at the rig. RFID tags are embedded on drill stem assets to capture critical history, such as inspections, repairs and rotating hours. Collected data is uploaded into TruData™ – a comprehensive reporting management system - to ensure that the correct quantity, condition and grade of assets are delivered to the rig.

The AutoTally™ component also delivers a 100-percent accurate drill string tally in real time. As joints are run in hole, a rig floor reader identifies assets and their individual histories, relaying that information to the driller's screen. Maintaining an accurate drill string tally reduces the non-productive time (NPT) associated with missed depths, stuck pipe and twist-offs.

Drill string fatigue failure is the most common and costly type of drilling failure, with an estimated $100,000 per failure.

Drill string fatigue failure is the most common and costly type of drilling failure, with an estimated $100,000 per failure. Monitoring the complete history of assets can detect repetitive issues – such as thread galling, pitted seals or disproportionate connection repairs – and take worn elements out of service before they fail.

A well-documented, current asset inventory can intercept drill pipe that should be repaired or retired. Without this information, fatigued assets can mistakenly become part of a drill string and later fail during drilling. Reliable inventory and quality control can reduce handling costs by up to 90 percent and lower thread repair costs by 44 percent.

Drill stem troubleshooting can identify equipment that may be directly affecting pipe integrity. These trend lines lead to corrective actions that have been proven to extend the productive life of assets by as much as 22 percent, potentially reducing NPT by up to 30 percent.

NOV recently conducted an extensive comparison of managed offshore pipe assets against their standard, non-managed counterparts in the North Sea. Final analysis showed a 55 percent reduction in connection damages for the managed assets, saving $2.7 million over 18 months.

The TracID system also offers the benefits of "intelligent tagging." TracPLATES™ technology integrates RFID transponders into conventional tag plates, or they can be retrofitted into existing metal tags. TracPLATES can be attached to many types of equipment, providing superior inventory control beyond the wellbore.

TracID is currently installed throughout major oil and gas regions from Mexico to the Middle East. Efficient life cycle management is essential for all phases of drilling – because you can't manage what you don’t monitor.

Staying Cool Under Pressure

High Temperature

The heat is on for well operators, and it’s only getting hotter. Deeper wells mean higher borehole temperatures, with drilling friction adding to the hot, unforgiving downhole environment. This one-two punch can knock heat levels above 300 degrees Fahrenheit/149 Celsius – the threshold where equipment begins to break down more often.

Excessive heat can stall the performance of components such as drilling motors and rotary steerable systems, dramatically shortening their life spans. Heat-damaged electronic components can silence data collection and communication in the downhole environment, increasing rig non-productive time and equipment repair costs.

TUNDRA™ MAX land mud chillers are closed-loop refrigeration systems designed to cool drilling fluids even under extreme conditions. A portable, computer-controlled, dual-stage mud chilling system cools high-temperature mud in a two-stage process.

Within normal temperature ranges, drilling fluid protects downhole equipment and maintains optimal performance. Extreme temperatures degrade mud properties, creating issues such as increased mud loss, thermal instability and inconsistent rheology measurements. Mud performs best at lower temperatures, saving the cost of additives or replacement.

Cooler drilling fluid prevents heat-related equipment failures and recoups time throughout the drilling process. Stable downhole temperatures reduce the time needed to recondition mud returned from the wellbore. This speeds up the process to re-optimize mud formulas for downhole temperature fluctuations, all while providing better wellbore stability.

TUNDRA MAX performs when conventional cooling methods fail. Air cooling is slow, inefficient and highly dependent on ambient temperatures. The dual-stage cooling system can actually reduce the temperature of processed drilling fluid to below the ambient air temperature.

Air systems have limited value in regions with extreme climates. This is especially true in places like the Middle East where temperatures can climb above 120 degrees Fahrenheit/49 Celsius. Water-based cooling systems require a local water source - an uncertain commodity at some remote land drilling sites.

In 2015, a detailed field study in the Eagle Ford shale tested how well TUNDRA MAX could reduce drilling fluid temperatures at a high flow rate with a small footprint. The study compared wells in South Texas equipped with advanced drilling automation tools, both with and without the mud chiller. The analysis included drilling speed, efficiency and downhole tool operational safety.

The well not using the mud chiller logged two temperature-related downhole tool failures, causing significant downtime. When TUNDRA MAX was activated on the second well, the operator reported zero temperature-related failures. A reduction in downhole tool trips alone allowed the well to be drilled two days faster than the previous well.

A reduction in downhole tool trips alone allowed the well to be drilled two days faster than the previous well.

In this same study, the battery on the high-speed downhole dynamics measurement tool achieved 240 of 250 hours of maximum battery life. This unprecedented 44 percent increase – up from 167 typical hours – was credited to TUNDRA MAX reducing bottomhole temperature by 22 degrees Fahrenheit/12 Celsius.

Superior cooling reduced the amount of circulation required to lower the temperature of the well. The cooler environment gained an additional 1,000 feet/305 meters before equipment-damaging temperatures were encountered. Drilling restarted sooner and saved 51 hours of non-productive time.

Well operators in southern Louisiana have also confirmed the high performance of TUNDRA MAX. The mud chiller was enabled on a well at 16,900 feet/5,150 meters, reducing the temperature gradient by 15 percent and saving 28 hours of temperature-related downtime.

TUNDRA MAX mud chillers eliminate dependence on local air and water conditions while extending equipment life and increasing drilling performance. These tough, efficient units are giving well operators a faster, more reliable way to beat the heat.

About NOV

Every day, the oil and gas industry’s best minds put more than 150 years of experience to work to help our customers achieve lasting success. We have the people, capabilities and vision to serve the needs of a challenging and evolving industry. One the world can’t live without.

Throughout every region in the world, across every area of drilling and production, our family of companies provides the technical expertise, advanced equipment and operational support necessary for success – now and in the future.

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