The tools of the oil and gas industry are getting smarter with more applications as operators and service companies pursue technology that keeps the bit on bottom and reduces the number of trips needed to perform downhole operations – saving money in the long run.

Improving drilling efficiency, especially in long, horizontal laterals, and increasing hydraulic fracturing effectiveness are top priorities for companies as the search for oil and gas moves into deeper, HP/HT, and more varied environments.

By combining processes into a single tool or a suite of tools in a single string, operators can achieve improved performance that leads to faster completion and earlier production.

For example, Atlas Copco designed a slightly modified hammer for a complete directional percussive bottomhole assembly (BHA). What used to require three bits per hole now gets two holes per bit, according to the company.

All of the technology is aimed at the bottom line. As these tools are tested and accepted in the field, the industry is finding viable methods for reducing nonproductive time (NPT) – saving on overall costs.

Tool removes debris during well intervention

For well intervention applications the M-I SWACO Well Scavenger vacuum debris removal tool captures and removes debris from the wellbore. The tool pumps driving fluid through the fluid jet pump, generating a reverse circulation flow around the bottom of the tool. This reverse circulation path allows the system to pick up debris and capture it in situ.

As debris is transported into the tool, it settles in the debris chambers as the fluid velocity decreases. The fluid then passes through the filter screen to remove suspended materials. Ferrous debris can be collected on the internal magnet section.

In Alaska a customer had set one packer at 3,061 m (10,100 ft) and was running a second packer downhole when it stuck prematurely at 2,469 m (8,148 ft). Once the stuck packer was drilled out, wellbore cleaning was required down to the top of the lower packer. Two runs with a boot basket retrieval tool yielded very little debris recovery. As an alternative, a BHA comprising the Well Scavenger tool and high-capacity Magnostar magnets was created.

The BHA included 27.3 m (90 ft) of wash pipe, a heavy-duty Razor Back casing cleanup tool, Magnostar magnets, a Well Scavenger tool, and a Single-Action Bypass Sub Jetting Tool. After running in-hole to a depth of 1,879 m (6,200 ft), progress stalled due to a large accumulation of debris on the lower side of the wellbore. With circulation and pipe movement the tool assembly was pushed to 1,903 m (6,280 ft), at which point the tools were pulled from the hole. Once on the surface, 85 lb of ferrous debris were recovered from the magnets.

While the magnets were cleaned, the boot basket fishing tool and magnet assembly were redeployed, recovering only 20 lb of ferrous debris. A second run of the Well Scavenger tool, in combination with three Magnostar magnets, yielded an additional 287 lb of ferrous debris on the magnets and a total of 1,033 lb of sand/silt recovered in the Well Scavenger debris chambers. An additional 168 lb of ferrous debris was recovered from the internal magnet assembly.

A final run was made with the three magnets, yielding an additional 145 lb of ferrous debris. In total, M-I SWACO tools removed 1,649 lb of ferrous and nonferrous debris from the wellbore.

Steel dart eliminates secondary run for jetting

With reliable performance, steel dart technology is increasingly being deployed in conventional, deepwater, and HP/HT wells. Churchill Drilling Tools is providing operators with enhanced downhole tool capabilities from its Smart Dart technology.

The steel darts deliver robust activation, multimodal capability, spatial economy, and geometrical stability. Each dart is packaged with application guidelines and operating parameters. Mechanical extrusion (MX) is an innovation that adds a double-shear point, making it easier to deploy the darts quickly at high flow rates.

MX dart shear mechanisms are an effective alternative to extruding ball devices that have a polymer mono-shear characteristic, where shear pressures are determined by temperature and fluid conditions or are reduced by previous deformation cycles.

One implementation of the dart/shear technology is the company’s DAV MX circulating sub, which has been run in more than 260 wells through year-end 2012.

Typically used for curing losses or boosting hole-cleaning, Churchill applied the dart technology for this tool category with a 100% reliability record through both 2011 and 2012. Performance of the darts has been demonstrated across the spectrum of applications from exploration to plugging and abandonment work.

Multiple multimodal functionality was demonstrated in November 2012 in a well in the Mississippi Canyon area of the Gulf of Mexico (GoM), with secondary lock-open activation delivering dry-trip and BOP jetting capability in a single pass exit from the hole.

The primary activation enabled a bit bypass circulation cycle. When complete, the bypass cycle was followed by a quick-closing cycle to return to through-bit circulation drilling mode again. Prior to pulling out of hole, a lock-open dart was selected to activate and simultaneously hold the tool open. As it was pulled from the hole, string draining was enabled, which kept the rig floor dry and safe. Being open, the tool was ready for jetting as the sub reached the BOPs, eliminating the need for a secondary run in-hole for jetting.

A more recent dart innovation was the activation of Churchill’s drilling float subs in the North Sea. In fall 2012 two supermajors were able to delay the setting of floats until actually required. Using shear-pin innovation, the floats can be given a dormant phase to circumvent top-filling and spillage-safety costs on the run into hole, with accelerated running into restricted sections provided by the surge-relief characteristics.

Hydraulic toe valves designed for cemented applications

An innovative and economical multizone well completion system designed for both open-hole and cemented fracing operations includes the ORIO Toe Valve, which provides a method for performing a high-pressure casing test prior to establishing injection into the formation.

The hydrostatically operated sliding sleeve is part of Team Oil Tools’ T-Frac System. The patented ORIO Toe Valve is run at the bottom of the completion string in horizontal wells. The tool is specifically designed to work in a cemented environment. After completion of the test, excess pressure is applied to open the valve and allow immediate injection to commence fracing operations, including the traditional plug and perf method.

The toe valve’s design ensures that the sleeve will open even if excess cement is left in the wellbore. The inner piston is the only moving part in the tool and is completely isolated from the cement. There are no moving parts on the inside diameter (ID) or outside diameter of the tool. The ORIO’s unique three layers enable it to function as required.

The toe valve specifications include a rupture disk with ratings up to 20,000 psi that allows pressure-testing of the casing in excess of 15,000 psi and a temperature rating of 177°C (350°F). The certified rupture disks allow the valve to be opened within 2% of design.

Traditional toe valves yield higher failure rates due to the necessity for the sleeve to “crush” any excess cement. The use of an atmospheric chamber means the valve can remain fully open with hydrostatic pressure alone. This particular feature allows higher injection rates as the tool fully opens once activated.

Once the rupture disk has burst, hydrostatic pressure continues to drive the sleeve fully open and maintains it by acting against an atmospheric chamber that allows maximum flow area throughout. Shouldered connections allow rotation while running in the hole or during cementing.

Interventionless toe initiation not only provides an operational cost reduction but also serves as a technology enabler for the cemented, ball-activated frac sleeves. Without an interventionless toe initiation, ball-activated frac sleeves cannot be used in a cemented lateral.

R&D in conjunction with field studies has resulted in toe valves that are fit-for-purpose and function properly regardless of the amount of excess cement left in the pipe. Notably, the ORIO Toe Valve has been tested and proven in more than 300 wells with cemented environments by multiple North American operators. The valve has collectively provided more than US $30 million in cost savings to the industry, according to Team Oil Tools.

Directional hammer improves drilling time, cuts cost

“Twenty percent of drilling footage in the US could be air-drilled, and it’s only 5% to 10%. Some companies that were drilling with air had returned to mud,” said Tom Weller, drilling superintendent for Carrizo Oil and Gas in the Marcellus shale region, who had spent 20 years demonstrating the profitability of drilling with air around the globe.

But when he returned to the US, he said, “It looked as if air drilling stalled out.” Carrizo Oil and Gas, though, was a company after his own heart. “They were doing fairly well directional drilling on rotary air, but I wanted to use a hammer.”

That is when Weller connected with Atlas Copco’s Jeff White, a down-the-hole specialist sharing Weller’s passion. White worked with Atlas Copco Secoroc to modify existing technology.

The patented solution its engineers came up with, White said, was “beautiful for its simplicity.” When skeptics asked, “If it’s so simple, why hasn’t it been done before?” White replied, “It needed an advocate like Tom Weller.”

White also credited the project’s success to Carrizo’s dedication. Brad Fisher, the company’s vice president of operations, had patiently endured the development process of tooling modifications, with each tweaked and studied one by one.

“We already have jet subs and run motors on air,” White said. “We just needed a slightly modified hammer for a complete directional percussive bottomhole assembly.” The resulting BHA was built on an Atlas Copco Secoroc TD 90 hammer.

Crescent Directional Drilling, Carrizo’s directional contractor, shortened its motor’s driveshaft to compensate for hammer length, and Atlas Copco designed an 8?-in. bit especially for this application.

“We were using three bits per hole but now get two holes per bit. We had been tripping out three times to drill the directional 4,000 ft to 5,000 ft [1,212 m to 1,515 m] of the 8?-in. interval,” Weller said. “We currently drill it in one trip in 40 to 60 rotating hours. We’re directionally drilling from surface to kickoff point in approximately six days. Save days, and dollars follow.

“It is difficult for drillers to keep up because the hammer can drill 200 ft to 500 ft [61 m to 152 m] or more per hour.” Weller said that using percussive air reduced drilling time by six days and costs in the air section by $100/ft.

New bits provide advanced cutter technology, improved ROP

Premium polycrystalline diamond compact (PDC) cutter technology resists erosion and chipping to maximize run life and penetration rate. Patented polished cutter faces reduce friction, which in turn minimizes heat buildup on the cutter face to decrease wear and improve cutting evacuation efficiency to reduce balling.

The Hughes Christensen Talon platform of PDC bits from Baker Hughes includes the Talon high-efficiency bit and the Talon 3-D vector-accurate bit. All Talon bits include Baker Hughes’ StaySharp Innovative Talon PDC cutter technology, which consists of uniquely shaped and positioned blades and nozzles, application-specific bit profiles, low-torque gauge designs, and diverging junk slots. The bits can stay in gauge longer because of a new gauge pad that uses tungsten carbide and thermally stable PDC materials to protect it. These hydraulic and mechanical efficiencies mean more energy for rock removal, less vibration, increased durability, and improved large-volume cuttings removal – boosting ROP and run life.

The bit’s short shank decreases makeup length for higher levels of directional control on conventional assemblies and increased bit side force on rotary steerable assemblies. With the ability to be specifically engineered and designed for the Baker Hughes AutoTrak Curve rotary steerable system, Talon bits can improve performance and get through laterals and into the pay zone with exceptional speed.

An operator in Oman needed to significantly reduce drilling costs and achieve more aggressive performance without sacrificing vertical control in deep exploration gas wells with long, interbedded carbonate intervals and sticky shales. Baker Hughes recommended that a 12?-in. Talon bit be added to the drillstring with the Baker Hughes AutoTrak V vertical rotary steerable system and Navi-Drill X-treme low-speed motor. The average ROP was 28% faster than the previous record for a deep gas well in the field and 64% higher than the average ROP, saving 5.6 days or 63.7% of rig time compared to plan.

Based on the success of its first run, the operator chose Talon bits for two other gas development wells and on the first well saved 2.8 days compared to plan. On the second well only two Talon bits were needed instead of the expected five, reducing the drilling time by 11.5 days and again saving significant project costs, according to Baker Hughes.

Dogleg reamer solves lateral drilling issues

As technology progressed and lateral drilling became a staple in many wells, so did the issues inherent with these extended intervals. Although the drilling of these extended lateral sections became relatively routine, well-bore quality issues such as microdoglegs and efficient hole-cleaning significantly increased operator risk and expense.

National Oilwell Varco’s Borehole Enlargement Group developed its newest premium string tool, the Dog Leg (DL) Reamer, to help avoid and solve problematic lateral drilling issues.

The DL Reamer has a slightly eccentric profile, allowing the tool to pass through a smaller restriction than its actual drill size. As a result, the tool will slide efficiently, even if the pilot bit becomes slightly under gauge. The reamer also has two distinct cutting structures: one for minimizing microdoglegs while drilling ahead and the other offering an uphole cutting structure to allow back-reaming while pulling out of the hole or while pulling up to make connections. Designed for maximum toughness, the DL Reamer has resulted in reduced trip time and proven success in shale laterals, extended-reach wells, creeping salts, and swelling shales. The tool cleans the wellbore before expandable packer completions or running production casing with added stability and protection, all while stirring cutting beds and eliminating dedicated wiper trips.

The reamer also features torque-control components, which are placed behind the primary cutting structures on each of the blades. These components have been adopted from the field-proven ReedHycalog bit technology, resulting in a maintained ROP, over-engagement of cutters in formation, controlled lateral engagement, and stability.

During the testing phase in extended Bakken shale applications, the DL Reamer proved extremely successful in cleaning the wellbore and eliminating dedicated post-well reamer runs. No problems running expandable packer assemblies or production casing have been experienced. The reamer has been successfully deployed in Wyoming, Oklahoma, and Latin America and is available for pilot bit sizes ranging from 5? in. through 12? in.

New tool offers solution for wide array of multistage stimulation challenges

As multistage sliding-sleeve systems have become common completion methods, the focus has moved to increasing the efficiencies and performance of these technologies. Operators more than ever are in need of methods that will allow them to maximize stimulated reservoir volume through increased stage counts and pump rates while minimizing the cost and time required.

Currently, a major limitation experienced during the stimulation phase of completions is the restricted pump rate for toe stages, which is caused by the small ID of sliding-sleeve ball seats. To overcome this challenge, Peak Completions’ new Super-Port technology brings a reduction in ball-seat increments that allows operators to run the same number of stages at a larger ball-seat ID.

The Super-Port comes with a standard 10,000-psi differential rating, while the HP/HT version is capable of withstanding differential pressures of 15,000 psi. The system can be designed for several different applications, including both openhole and cemented multistage completions. In openhole applications operators have numerous choices for zonal isolation, including the hydraulically set Predator packer and the SwellShark swellable packer. When run in a cemented application, the first stage is initiated with precision burst disk technology, resulting in a completely rigless solution.

The system allows a continuous pumping operation for the stimulation treatment, eliminating downtime between stages. A 30-stage system can save the operator up to 12 days of completion time compared to the plug and perf method. In addition, the system provides a significant reduction in water requirements, equipment on location, and operational risks. Several deep shale wells have been successfully completed in southeastern New Mexico using the Super-Port system. In one example the maximum rate pumped was 51.3 bbl/min with a treating pressure of 6,482 psi staying within the frac design parameters. However, the maximum allowable pump rate for the system is much higher depending on the well design. The rates were consistent from the toe-to-heel stages as a result of design elements that reduce the pressure drop across the system. This provides operators with the key advantage of reaching higher rates at the toe stages than are normally possible and achieving an improved hydraulic fracturing treatment.

The system is applicable to unconventional plays such as the Bakken, Bone Spring, Cline, Woodbine, Avalon, Wolfberry, Eagle Ford, and Utica.

Enhancing annular circulation with RFID technology

As operators drill deeper, hole integrity and mud condition become more and more essential. Circulation subs are designed to circulate fluid in the annulus for wellbore cleaning and efficient drilling.

Traditional circulation subs are ball-activated tools that have restrictions due to limitations in the activation and deactivation. A steel ball is dropped from surface level down to the tool. The ball is then housed inside a ball catcher. Once full, an extra trip is required to exchange the tool for additional activation and deactivation.

Mechanical components also restrict the ID, limiting the number of tools that can be run in the string. More trips are required to run more tools.

In some instances specific well sections need cleaning. Zone selection with mechanically activated subs can be difficult since a complicated actuation sequence may be required.

Radio-frequency identification (RFID) technology enables tracking of everyday applications, including toll collecting and personnel identification. The same technology is applied to Weatherford International’s RFID drilling circulation sub to overcome industry challenges and facilitate hole cleanup operations.

A surface-level RFID tag, rather than a ball, is dropped and circulated through the sub to move it to the open, closed, or diverted position. The tag’s signal is read by the sub’s antenna, and a motor operates a pump, which moves the valve to the desired position.

The sub enables limitless on-demand actuations to extend time downhole. While the battery lasts, no switch-out trips are needed; minimizing the number of trips saves time and increases efficiency.

The design eliminates the ball seat, so there is no mechanical restriction or ID reduction. Wireline and electric-line tools are allowed full access, and multiple tools can be run in the string or BHA to reduce trips.

When running these subs or other RFID-operated tools in a series, selective actuation of each is possible. Activation may be in any order and simultaneous. This increased control facilitates zone selection to enhance annular flow for optimal wellbore cleaning.

In a recent deepwater application in the GoM, the sub was deployed as part of the drillstring to clean the borehole and subsea BOP. At least three to four trips were eliminated compared with traditional circulation subs to save time and money.

Drillable reaming system takes liner to total depth

Two conventional attempts to run a 7-in. liner to total depth (TD) were unsuccessful in a Statoil-operated Gullfaks’ satellite well, resulting in the liner hanging up hundreds of meters from TD. The problem was caused by borehole instability and severe washout in the weak shales, coals, and notorious paleosols of the area. Deep Casing Tools deployed its Turbocaser Express, a high-speed drillable reaming system that enables drilling teams to land casings and intermediate liners at target depth during the first time.

Deep Casing Tools was able to solve the problem for Statoil and completed its first operation in the Norwegian North Sea with a successful 21-hour reaming run.

The Gullfaks’ team drilled a sidetrack using low-energy drilling operations principles and ran the liner with the Turbocaser Express as a contingency against wellbore obstructions.

The operator considered two benefits: The tool would significantly increase the chance of getting the liner to TD, and, if hole conditions proved too severe, the fullbore, rapid drill-through capability of the tool would still allow the remaining reservoir to be accessed.

The 7-in. liner was run and, as predicted, stood up with 10 metric tons at 4,117 m (13,586 ft), 1,260 m (4,158 ft) from TD, where the liner could not be rotated or run deeper. Circulation was established, and the Turbocaser Express was used to clear the obstruction. The next obstruction was at 4,378 m (14,447 ft), where the tool was again used to ream at 60 m/hr (198 ft/hr).

“The Turbocaser Express functioned well, and we believe it was a contributing factor to getting the liner down successfully. We are likely to use it again in the future,” said Michael Mountford, Statoil’s senior engineer, drilling operations.

Deep Casing Tools CEO Lance Davis added, “It is a significant achievement to provide new technology to Statoil. Statoil chose the Turbocaser Express to land its liner, which also allowed it to drill ahead if needed.”

High-resolution LWD images used to adjust drilling parameters

Wellbore stability problems are one of the largest causes of NPT during the drilling process. How the rock is reacting to the drilling process can be seen immediately when using real-time images. These directly identify drilling-induced fractures, breakouts, sheer plane failures, and other drilling hazards such as ledges.

For real-time and post-drilling formation evaluation capabilities, Baker Hughes’ StarTrak service offers high-resolution LWD electrical imaging in a platform tailored for today’s varied and challenging drilling environments. The service helps geoscientists, completion engineers, and drillers provide a higher level of confidence to make the critical decisions that are required in today’s competitive business climate.

As a key component of the real-time LWD tool kit, the StarTrak imaging service is designed for subsurface exploration and development teams that need highly detailed sedimentary and structural information for drilling optimization, wellbore placement, completion design, and geological modeling. The service was designed to be transparent to the drilling operation and delivers high-quality image logs at ROPs up to 45 m/hr (150 ft/hr) while experiencing moderate levels of stick/slip.

With this knowledge, drilling parameters can often be adjusted to reduce or eliminate the problem, avoiding a stuck pipe incident.

Precise wellbore placement is crucial for lowering costs and maximizing recovery, especially in mature fields. The high-definition electrical images provided by StarTrak provide important input into the reservoir navigation process, particularly when determining if the well is going up-section or down-section.

The service has proven to be of great value in unconventional plays. The high-resolution images show fracture type and density in detail and allow operators to optimize their completion and hydraulic stimulation program. By selecting completion stages based on the information in the image log, operators have realized approximately 20% more production compared to using regularly spaced intervals, according to Baker Hughes.

The more unknown elements in a downhole environment, the greater the risk. There is the risk of slowing or stopping drilling schedules to accommodate evaluation – particularly when well trajectories make coring or wireline difficult or even impossible. Also, there is the risk that the wellbore conditions will deteriorate over time and the risk of imprecise or failed wellbore placement. The StarTrak service mitigates these risks, providing high-quality data in real time and memory logs for immediate evaluation and decisions, the company added.