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.

Automation

Change the Way You Drill

The eVolve™ Optimization Service enhances real-time analytics capabilities.

Automation

Change the Way
You Drill

Operators have conventionally relied on annular pressure measurements at the bit and hydraulics models to estimate the equivalent fluid density along the string. However, the future of drilling demands high-speed, real-time data to help drillers make informed decisions that optimize drilling performance.

The eVolve™ Optimization Service equips existing rigs and crews with an advanced toolkit that increases performance, enables informed decision making and enhances real-time analytic capabilities. The premier tier of the service, AUTOMATE, provides better well control and makes drilling more efficient while reducing well delivery times and improving safety.

Total E&P Norge AS is currently developing a Norwegian North Sea field that consists of an oil reservoir and several deeper, structurally complex, high-pressure gas and condensate reservoirs. Wells drilled in this field have a narrow pressure window that requires a more complete understanding of the environment. The eVolve team provided an extended dataset that offered a detailed picture of the pressure and equivalent circulating/static density distribution.

To meet the specific challenges of this project, BlackStream™ along-string measurement (ASM) tools were incorporated to meet and exceed the stated objectives. BlackStream ASM tools acquire temperature, annular pressure, rotation and three-axis vibration data at high frequency from sensors embedded throughout the drillstring at regular intervals. These measurements are taken and streamed to the surface via the IntelliServ™ high-speed Wired Drill Pipe telemetry network, with or without flow.

This suite of tools provided Total E&P Norge AS with the downhole data to overcome the limits of hydraulics modeling. The measurements were used to accurately analyze and understand the wellbore conditions - not only at the bit, but also in critical parts such as the casing shoe. The streaming visualization of the downhole data substantially improved hole cleaning monitoring, reduced non-productive time, enhanced well control and sustained wellbore integrity.

This ongoing project has the dual intent of providing significant and immediate value to the operator while developing lessons learned for future operational implementation and continued engineering developments. The eVolve team upgraded access to wellbore pressure information and provided the support to incorporate this new information into performance improvements across multiple phases of the drilling operation.

This ongoing project has the dual intent of providing significant and immediate value to the operator while developing lessons-learned for future operational implementation and continued engineering developments.

Using this innovative NOV solution, Total E&P Norge AS improved drilling in the reservoir section by using automation to safely increase rate of penetration and drill an additional 656 feet/200 meters of reservoir. The additional reservoir drilling saved the drilling cost of one less well while still reaching planned production levels.

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.

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.

Change the Way You Drill

Automation

Operators have conventionally relied on annular pressure measurements at the bit and hydraulics models to estimate the equivalent fluid density along the string. However, the future of drilling demands high-speed, real-time data to help drillers make informed decisions that optimize drilling performance.

The eVolve™ Optimization Service equips existing rigs and crews with an advanced toolkit that increases performance, enables informed decision making and enhances real-time analytic capabilities. The premier tier of the service, AUTOMATE, provides better well control and makes drilling more efficient while reducing well delivery times and improving safety.

Total E&P Norge AS is currently developing a Norwegian North Sea field that consists of an oil reservoir and several deeper, structurally complex, high-pressure gas and condensate reservoirs. Wells drilled in this field have a narrow pressure window that requires a more complete understanding of the environment. The eVolve team provided an extended dataset that offered a detailed picture of the pressure and equivalent circulating/static density distribution.

To meet the specific challenges of this project, BlackStream™ along-string measurement (ASM) tools were incorporated to meet and exceed the stated objectives. BlackStream ASM tools acquire temperature, annular pressure, rotation and three-axis vibration data at high frequency from sensors embedded throughout the drillstring at regular intervals. These measurements are taken and streamed to the surface via the IntelliServ™ high-speed Wired Drill Pipe telemetry network, with or without flow.

This suite of tools provided Total E&P Norge AS with the downhole data to overcome the limits of hydraulics modeling. The measurements were used to accurately analyze and understand the wellbore conditions - not only at the bit, but also in critical parts such as the casing shoe. The streaming visualization of the downhole data substantially improved hole cleaning monitoring, reduced non-productive time, enhanced well control and sustained wellbore integrity.

This ongoing project has the dual intent of providing significant and immediate value to the operator while developing lessons learned for future operational implementation and continued engineering developments. The eVolve team upgraded access to wellbore pressure information and provided the support to incorporate this new information into performance improvements across multiple phases of the drilling operation.

This ongoing project has the dual intent of providing significant and immediate value to the operator while developing lessons-learned for future operational implementation and continued engineering developments.

Using this innovative NOV solution, Total E&P Norge AS improved drilling in the reservoir section by using automation to safely increase rate of penetration and drill an additional 656 feet/200 meters of reservoir. The additional reservoir drilling saved the drilling cost of one less well while still reaching planned production levels.

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.

About NOV

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