The E&P editors and staff proudly present the winners of the 2016 Special Meritorious Awards for Engineering Innovation, which recognize service and operating companies for excellence and achievement in every segment of the upstream petroleum industry. The pages that follow spotlight the 18 winners the independent team of judges picked that represent a broad range of disciplines and address a number of problems that pose roadblocks to efficient operations. Winners of each category are products that provided significant changes in their sectors and represented techniques and technologies that are most likely to improve exploration, formation evaluation, drilling, production, completions, onshore rigs, intelligent systems, remediation, water management, subsea systems, floating systems, marine construction and HSE efficiency and profitability.

This year some of the brightest minds in the industry from service and operating companies entered exceptionally innovative products and technologies that have now been measured against the world’s best to be distinguished as the most ground-breaking in concept, design and application.

The award program recognizes new products and technologies designed by people and companies who understand the need for newer, better and constantly changing technological innovation to appease the energy-hungry world.

The winners were selected by an expert panel of judges comprising geologists, geophysicists, petrophysicists and engineers from operating and consulting companies worldwide. Each judge was assigned a category that best called on his or her area of expertise. Judges whose companies have a business interest were excluded from participation. The products chosen by the judges represented the best of a long list of winners.

E&P would like to thank these distinguished judges for their efforts in selecting the winners in this year’s annual awards competition.

As in past years, E&P will present the 2016 awards at the Offshore Technology Conference in Houston.

An entry form for the 2017 Special Meritorious Awards for Engineering Innovation contest is available at The deadline for entries is Jan. 31, 2017.


  • Ken Arnold, K Arnold Consulting
  • Dick Ghiselin, Qittitut Consulting
  • Nelson Oliveros, Petrofac
  • Chris Singfield, Chevron
  • Scott Weeden, Hart Energy
  • Allen Bertagne, Consultant
  • George King, Apache
  • Michael Payne, BP
  • Eve Sprunt, Consultant
  • Doug White, Consultant
  • Ben Bloys, Chevron
  • Vianney Koelman, Shell
  • Bill Pike, NETL
  • Mark Thomas, Hart Energy
  • David Zornes, Consultant
  • Mike Forrest, Consultant
  • Carl Montgomery, NSI Technologies
  • Lanny Schoeling, Kinder Morgan
  • John Thorogood, Drilling GC


The Talon Force platform of polycrystalline diamond compact (PDC) bits were developed by Baker Hughes by designing the bit holistically, using bit behaviors and responses rather than just focusing on features to solve the most difficult drilling problems. Talon Force products incorporate multiple technologies to improve durability, boost ROP in challenging drilling environments, increase consistency from run to run and reduce bottomhole-assembly-damaging vibrations.

The product platform leverages cutter and frame enhancements to improve cutter abrasion and durability while enhancing lateral and torsional stability. Talon Force bits combine the latest cutter technology advances with application-specific cutting structures to maximize overall ROP and footage drilled.

Blade layout and hydraulic configurations contribute to increased lateral stability and improved drilling efficiency. Talon Force incorporates the latest advancements in synthetic cutters with the StaySharp 2.0 PDC offering, which use the latest HP/HT diamond synthesis technologies to deliver wear resistance, toughness and thermal stability.

The PDC bit introduces a differentiating cutter size, the 1-in. cutter, to increase drilling speed and efficiency in applications requiring high depth of cut. Coupling the StaySharp 2.0 technology with an innovative geometry modification, Stabilis cutters improve cutter durability and reduce torsional oscillations to drill longer runs at higher overall ROP. Talon Force products with Stabilis cutters deliver more footage at higher speeds in places like the Wolfcamp, where the new bits have cut drilling time 36%, improved ROP by 25% and drilled 55% farther compared to standard PDC bits with standard chamfer cutters.


The BroadBand unconventional reservoir completion services portfolio includes composite fracturing fluids with next-generation fibers and fluid additives to transport and place proppant within complex fracture networks.

Designed to overcome the limitations of conventional hydraulic fracturing fluids by providing broader transport of proppant to maximize coverage in the fracture, the fracturing fluid mitigates settling to promote formation of high-conductivity flow channels across all fractures to their total length and height to connect far-field areas with the wellbore. These fluids are designed for both openhole and cased-hole completions, refracturing operations, shales, dirty carbonates, tight sands and coalbed methane reservoirs with bottomhole temperatures between 43 C and 149 C (100 F and 300 F).

Once the pumping operation ends, proppant is suspended in the fracture with degradable fibers that impede settling and promote heterogeneous distribution of proppant across each fracture. The composite fracturing fluids can be used with composite-based fluids including slick water, linear gel, viscoelastic gel and crosslinked gel.

With the addition of fiber technology, these fluids now can transport proppant great distances while pumping and suspend proppant during fracture closure.

Endeavor Energy Resources stimulated a well in the Permian Basin’s Bone Spring Formation with the BroadBand services’ composite fracturing fluid. Compared with six offset wells treated with conventional stimulation fluids and similar amounts of proppant and water, the well treated with the composite fracturing fluid delivered the best production performance.


Integrated ceramic electronics are at the heart of the Schlumberger PowerDrive ICE ultraHT rotary steerable system (RSS) and TeleScope ICE ultraHT MWD service. The ICE bottomhole assembly (BHA) is rated to 200 C (392 F). These ultrahigh-temperature (UHT) drilling services have the capability to precisely place wells deemed undrillable since the wells could not be steered to total depth in UHT reservoirs.

Laterals and deep boreholes expose BHAs to UHT environments for days or even weeks. Electronic circuitry sealed in plastic or elastomeric seals can fail when exposed to high temperatures, leading to unnecessary trips.

In a complete reengineering of key components of the PowerDrive ICE RSS and TeleScope ICE MWD service, multichip electronic circuitry was embedded in a 100% ceramic substrate that was hermetically sealed in an inert gas, resulting in a new multichip module that resists both heat and shocks. Power is supplied by a power-generating turbine within the TeleScope ICE system.

ICE UHT drilling services have been field-tested worldwide in various UHT reservoirs, saving time and money and reaching planned depths with precise well placement.

One company reported a 16% improvement in ROP while drilling compared with the previous record achieved in one field. A reduction of nine operating days was reported, amounting to $1.35 million in savings.


In a slumping market where prices and demand for oil and gas are declining, operators must make the best economic decisions possible for their wells. The effectiveness of perforated cased completions can depend on choosing the best gun system with the most suitable shaped charges as well as preparing the wellbore for the dynamic fluid and pressure responses that occur. The tests performed at Halliburton’s Jet Research Center give customers precise answers on the exact depth of penetration into the formation in different types of rock and also what the crush zone and skin value of that perforation is expected to be. These insights help identify or develop the best perforating system for any given well condition.

To maximize project economics, an operator approached Halliburton to determine the optimal gun system and perforating method for a challenging environment. The reservoir is a very weak shaly laminated sandstone. The timeline was short, and answers were needed quickly for determining well construction. The 12-shot Section IV test program compared the performance of three shaped charges in a gas-filled rock. Charges were shot into single- and dual-casing targets matching the projected well configurations. The study showed that the use of a typical perforating system without an intimate understanding of the reservoir and well construction wouldn’t provide the performance required to optimize production.


Safety on all offshore facilities is and should always be the industry’s No. 1 priority, and a crucial part of that is the fire protection systems onboard those facilities. Their performance is vital to ensure the safety of personnel, protect assets and prevent events from escalating. Trelleborg Offshore & Construction’s Firestop is a passive corrosion-free rubber-based solution that helps to provide time to evacuate people and close down critical equipment and for responders to gain control of the fire.

Rubber-based materials are becoming a more popular choice within the offshore industry due to their flexibility and durability, with the diverse material able to damp, seal and protect as well as having an extremely long lifetime. It can be used for fire and corrosion protection, mechanical protection, thermal insulation and antifouling. Examples of applications include for rigid and flexible riser protection, I-Tubes and deck protection. The coating can withstand blasts of up to 2.1 bars and jet/hydrocarbon fires for more than 2 hours.

On Maersk’s Ngujima-Yin FPSO vessel on the Vincent Field offshore Western Australia, the facility’s existing carbon steel seawater deluge system had corroded over the two years since its installation, requiring constant maintenance, cleaning and testing. Trelleborg was awarded a contract to supply its high-performance Elastopipe corrosion-free fire safety deluge system to replace the existing carbon steel pipework on seven of the vessel’s modules while the FPSO unit remained in production. The system required 1,687 m (5,535 ft) of pipe work in diameters ranging from 25 mm (1 in.) to 200 mm (8 in.), and associated fittings and accessories.


The R550-D jackup drilling rig is capable of drilling in up to 122 m (400 ft) of water and is the first of its kind. Built, tested and jacked up at the CSSC shipyard in China, the lightweight rig is able to be built at significantly lower cost than comparable units and has a high operational variable deck load (11,000 kips) that gives it excellent operational efficiency. Three categories lead to higher utilization and improved drilling efficiency for operators:

  • Safety: Jacking with full preload can be done, greatly enhancing safety in “punch through” situations. Preload tanks can be filled in less than 7 hours and are designed to ensure an even fill. The superior movement-carrying capacity of the legs provides enhanced safety during rig moves. The patented locking device, Zenlock, also guarantees disengagement from the leg racks due to an innovative gap designed into the engaging lock that provides enhanced safety.
  • Construction cost and efficiency: The lightweight design of the R550-D along with large deck space means more equipment on board and less boat runs, which leads to higher utilization and improved drilling efficiency.
  • Operational efficiency: The R550-D design has the longest cantilever reach of equivalent rigs of 24 m (80 ft), allowing more wells to be drilled and a high return on investment for the operator. Its bracing-to-leg-chord design, large-diameter high-strength steel braces and optimized truss pattern for higher stiffness along with the carrying capacity allows moving the rig to location in higher sea states (3-m to 3.6-m [10-ft to 12-ft] waves in varying soil conditions).


The ability to evaluate formation pressures pays dividends at various stages of a field’s life cycle. The field operator can use precise pressure data obtained during logging runs to determine fluid contact, fluid properties, reservoir pressures during exploration and development and, ultimately, the production potential of the reservoir. However, traditional wireline-deployed pressure testing services require significant manual operation and measurements, which are prone to longer testing times and raise the risk of inaccurate or incomplete data and inconsistent test outcomes. The Baker Hughes FTeX advanced wireline formation pressure testing service was designed to deliver reliable and accurate pressure data through a combination of downhole automation and real-time control. The service replaces human operator control from the surface with an intelligent downhole platform that reduces the possibility of human error by automating pressure measurements and significantly minimizes testing time by optimizing the operating sequence. This, in turn, minimizes the time the tool is in contact with the formation, reducing the risk of differential sticking, which can ultimately result in costly fishing operations. The data, which include pressure profiles, fluid contact and mobility information, can be obtained as early as the first logging run to significantly reduce overall logging time. This feature affords reservoir engineers and petrophysicists the opportunity to make earlier decisions about how to best proceed with their formation evaluation objectives.


Wellbore integrity and zonal isolation provided by cement placed between casing and formation rock are of utmost importance to safe and productive oilfield operations. Operators rely on the accuracy of cement-bond logs to make critical decisions that can affect long-term well integrity and the environment. While cement compressive strength has typically been used as a key indicator of cement quality, today’s challenging environments require more detailed assessment. The Baker Hughes Integrity eXplorer cement evaluation provides a new foundation for cement integrity evaluation of all types of cement slurries in oil and gas wells. The electromagnetic-acoustic transducer technology that forms the basis for the service allows operators to directly assess the integrity of cement bonds in any current wellbore environment or cement mixture.

The Integrity eXplorer service incorporates proprietary electromagnetic-acoustic transducer technology to generate a shear acoustic mode—not possible with conventional acoustic transducers—to accurately evaluate these types of cements. The acoustic waves used to assess the cement bond are generated and transmitted directly to the casing. The shear acoustic mode provides a new foundation for cement evaluation by responding to the cement shear modulus, which is a true indicator
of solid cement behind the casing. This allows operators to directly assess the integrity of cement bonds in any current wellbore fluid environment and in any current cement mixture.


The statistics speak for themselves—35% of all injuries companywide at Weatherford are handand finger-related. The company had tried several approaches to tackle this issue in the past, but nothing achieved the desired result, which was to send every employee home safely at the end of the day. With this goal in mind, the company set out to create a new Hand and Finger Injury Prevention Program. Teams worked together to produce training collateral including an analysis of the most common types of hand injuries; a detailed instructor presentation; posters; and a supplemental reference booklet and video content featuring controlled demonstrations of proper vs. improper hand placement, a key contributor to injuries.

The program incorporated compelling content that got employees thinking about their life outside of work. It also incorporated interactive activities. Employees were asked to try doing daily activities such as tying their shoes or unbuttoning a button with just one hand. This exercise got the participants moving and engaged in the training session. Another exercise walked employees through scenarios based on past incidents and asked them to use the Hierarchy of Control to identify ways of preventing similar incidents from occurring in the future. Finally, the program encouraged employees to conduct a hazard hunt at their workplace to identify areas where the Hierarchy of Control could be used to prevent future hand and finger incidents.


A number of products have been developed to establish a flow path from the casing inside diameter (ID) to the annulus in cemented plug-and-perf completions so perforating guns can be pumped downhole on wireline in lieu of being deployed on coiled tubing (CT) for stage-one stimulation. This saves the operator valuable time and money by eliminating requirements for CT equipment and personnel on location during this initial phase. However, the vast majority of these tools preclude the ability to perform a valid casing integrity test (CIT) prior to the commencement of stimulation operations since they are activated only after the recorded test pressure has been exceeded.

The PosiFrac Toe Sleeve (PTS) is the industry’s only flow-path initiation and stage-one stimulation tool that is actuated during the final bleed-down cycle following one or more successful CITs. A field-proven valve design leveraged from an array of other TAM products enables operators to test the casing to maximum values for as long as necessary and subsequently establish communication with the reservoir without ever exceeding the validated CIT values or incorporating ancillary tools, which add unnecessary cost and complexity.

Once open, the sleeve is held in place by a mechanical locking feature and via hydraulic forces, preventing it from closing at any time post-actuation. The PTS also has an extremely large ID, which enables the utilization of a variety of industry-standard wiper plugs (as validated by a series of flowloop tests). A number of other products have reduced IDs requiring extremely costly specialized plug sets and landing collars to ensure adequate wiping efficiency is achieved.


As “easy oil” has declined, complex and extended-reach wells, multilaterals and deepwater operations are now commonplace in hydrocarbon recovery. However, gaps in completion technology have historically limited the operators’ ability to obtain comprehensive sandface measurements for making informed decisions and developing control mechanisms.

To overcome that limitation, Saudi Aramco and Schlumberger developed the Manara Production and Reservoir Management System. It is the industry’s first intelligent completion system that provides simultaneous and continuous real-time control and monitoring of multiple zones across multiple well sections through the entire wellbore using a single electric line. This expanded capability improves recovery while reducing drilling, production logging and intervention costs.

Providing a simpler way to improve monitoring and control across the sandface and enable deployment capabilities in the mother bore and associated laterals, the system provides real-time status of the well’s performance, updates reservoir and production models and recommends adjustments to keep wells on production and continuously optimize recovery. The system uses metal-enclosed inductive couplers to provide bidirectional power and telemetry in up to 60 compartments across an unlimited number of lateral junctions.


With the current economic climate, many operators are revisiting their strategies for their mature fields. Operators are looking to lower their cost per barrel through the use of technology that will increase efficiency and lower cost. Various EOR techniques have been explored to increase reserves—wells are being strategically redrilled to accommodate a desired injection flood pattern, laterals are sidetracked from existing wellbores to maximize the drainage area and long extension horizontal wells are being drilled, all with the aim of maximizing the pay zone for production or injection.

However, controlling numerous laterals from the main bore or the numerous segments in a horizontal wellbore can be challenging and expensive. The SmartPlex downhole control intelligent completion system enables operators to remotely control up to 12 laterals or segments in an extended-horizontal reach wellbore with three control lines, allowing maximum efficiency in reservoir drainage and management.

On a 7,620-m (25,000-ft) deep well, more than 15% (four-zone) or more than 40% (12-zone) cost savings can be achieved when compared to completing with direct hydraulics. There also is added cost savings of capex and opex gained through drilling and completing fewer wells, reduced installation and operational time (fewer terminations compared to direct hydraulics). The ability to accelerate production through controlled commingling and to isolate a watered out segment or lateral
are other benefits.


The swivel stack is a vital part of an FPSO vessel, and avoiding production downtime to carry out repairs is a major advantage. Trelleborg Sealing Solutions’ unique SealWelding technology repairs leaking swivels and turrets in situ, avoiding that downtime. The solution allows seal replacement and repair without the vessel heading to port, a major benefit in terms of operational efficiency and costs.

It involves bonding the ends of a cut seal offshore while other swivel stacks are still in production. The technology comprises self-contained portable seal welding equipment that is loaded onto a ship with Trelleborg employees to perform the intervention. SealWelding starts in the company’s plant, where the seal is manufactured and then cut. It is then shipped to the FPSO unit and installed onto the Weld Head Enclosure, which is part of the welding machine, and pressurized so welding can take place.

In one case an FPSO operator used the SealWelding technology to repair a leak on its swivel stack containing seals 3 m (10 ft) in diameter. If the FPSO unit had gone to port for repairs, the docking rate would have averaged $500,000 per day, and the repair typically would have taken two weeks, constituting a minimum $7 million cost plus the loss of produced oil and gas. Overall, the estimated cost to the operator of the leaking seals would have been about $14 million. By fixing it on location, the repair was done in one week, with the operator avoiding having to move the FPSO unit or disconnecting from the subsea flowlines.


By integrating energy storage in the form of batteries and/or capacitors, advanced power conversion, and proprietary controls with rig power systems, FlexGen Solid State Generators (SSG) have shown to significantly reduce fuel consumption, engine maintenance and emissions while improving rig reliability and reducing downtime.

FlexGen Power Systems has developed and fielded hybrid power systems that can change the way the oil and gas industry provides power to the electrical power system requirements of the land drilling industry.

Current rig power systems are oversized to handle peak and transient loads while only using their fully rated power 15% to 20% of the time. By pairing a FlexGen SSG with any diesel, dual-fuel or natural gas power system, operators can reduce the size and number of generator sets needed as well as increase the substitution rate for dual-fuel systems.

This increases total available power, increases reliability through improved power quality, saves fuel costs, reduces maintenance costs and lowers overall operating costs.

The FlexGen SSG ties directly into the 600-volt AC bus of any AC or silicon-controlled rectifier rig. By monitoring voltage, frequency and other critical power quality metrics, the system responds to any transient or peak load spikes with full power (1.2 MW) in less than 20 ms. Several operators have shown 15% to 25% reduction in fuel costs, 35% to 45% reduction in maintenance costs and significant reduction in emissions.

FlexGen is backed by Altira Group, General Electric and Caterpillar.


Being small and fleet-footed can sometimes be exactly what is required in marine environments. The use of quickly deployed portable equipment is becoming increasingly applicable for inspection tasks in shallow water on offshore facilities, vessel hulls and infrastructure, where costs need to be kept low.

ROVs have long been recognized for their role in making offshore operations safer—for example, avoiding the need to use divers for inspection tasks—as well as more efficient. But traditional ROVs have been relatively costly and difficult to manage for certain tasks. Canadian company Deep Trekker Inc.’s DTG2 solution is a mini-ROV that is 100% case portable with onboard batteries lasting 6 to 8 hours on a single charge.

With a deployment time of less than three minutes, it is particularly suited when eyes are quickly needed in the water for operations taking place in sensitive areas such as environmental sites, where potential occurrences such as a generator leak could be detrimental to operations and the surroundings.

The DTG2 range has been used in the Norwegian Arctic, for example, for under-ice inspections. It also has a patented pitching system, which means it can fly horizontally and vertically with only two thrusters, providing increased maneuverability.


Mounting concerns about freshwater deficits plus environmental concerns and regulations, droughts in water-scarce areas, and growing transportation costs are driving demand to reduce the volumes of freshwater required for hydraulic fracturing and, instead, reuse produced water for subsequent fracturing operations.

As part of its efforts to make unconventional resources more sustainable, Baker Hughes developed the BrineCare family of fracturing fluid systems that transforms former waste streams into cost-saving alternatives to freshwater systems. While the solution sounds simple, the reality is more complex. The challenge is to reuse water to create fracturing fluids that have the properties necessary to maximize production across a well’s or field’s life cycle and that also can address operators’ short- and
long-term environmental and economic needs.

BrineCare provides an effective solution that delivers predictable performance by incorporating produced water containing high total dissolved solids (TDS) as part of the fracturing fluid solution. Fluid treatment composition is tailored to each well’s TDS levels and temperature profiles by first conducting a quick and comprehensive analysis of a produced water sample. This fast and efficient screening process also identifies whether any treatment of the produced water, such as filtering, is required prior to application to deliver a minimally treated fluid solution that strikes the ideal balance between high-quality fracturing treatments and the most cost-effective water reuse program.


Water usage accounts for up to 25% of the total cost in hydraulic fracturing operations. Freshwater sourcing, transportation, treatment, storage and disposal of produced water negatively impact field economics and raise significant safety and environmental concerns. Developed to mitigate water management challenges, the xWATER Integrated Water-Flexible Fracturing Fluid Delivery Service from Schlumberger allows operators to reuse up to 100% of produced water, thereby reducing or eliminating costs associated with water acquisition, conveyance, treatment and disposal. The xWATER service provides a customized fracturing fluid solution specifically engineered to enable the use of any available water rather than synthetically derived water that attempts to match the reservoir characteristics. This flexibility allows operators to use flowback or produced water from previous hydraulic fracturing jobs or nearby water sources, including brackish groundwater or seawater. The ability to reuse produced water by adding tailored fluids improves reservoir integrity and maximizes production as compared to freshwater.

The xWATER service is made possible by the latest advances in fluid chemistry, including salt-tolerant polymers and chemicals, scale prediction and mitigation, targeted water treatment technologies, and hardness-immune components compatible with saline matrices. Reusing produced water in tailored fluids reduces reservoir damage and can improve production as compared to freshwater. Preserving the fluids’ natural ability to stabilize clay also maximizes production. The xWATER service delivers significant savings (40%) in total water management cycle costs.


Integrating technology and operational knowledge creates opportunities for substantial improvements in water management. These systems allow operators to have real-time visibility of water assets while reducing labor, storage and drive time. Automation and tracking also provides users the ability to more closely control water quality and can result in meaningful operational cost savings and reduced management overhead. The AquaView system is a technology and service platform that improves communication between water resource teams and the completion program. With declining rig counts and low-priced oil, E&P companies are looking for opportunities to extract the most value from every capital dollar.

With variable expenses such as raw water costs, water transfer rates, loss of water from evaporation and damage from overflowing pits, it is crucial to have accurate water volumes prior to the completion. Not only will operators invest in an asset they will not utilize, if regulations stipulate that a breach of containment is considered a spill, costs will increase significantly. Conversely, underfilling prior to a fracture will add considerable expense due to service company downtime until sufficient water is procured. There are many challenges in obtaining, managing and transferring large quantities of water for fracture completions.