The E&P editors and staff proudly present the winners of the 2015 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 17 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 monumental 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 competition.

As in past years, E&P will present the 2015 awards at the Offshore Technology Conference in Houston, Texas, on May 4th, 2015, as well as at Hart Energy’s DUG Permian event May 19-21, 2015, in Fort Worth, Texas.

An entry form for the 2016 Special Meritorious Awards for Engineering Innovation contest is available at

The deadline for entries is Jan. 31, 2016.

2015 MEA Judges

Ken Arnold, K Arnold Consulting; Allen Bertagne, Consultant; Ben Bloys, Chevron; Mike Forrest, Consultant; Dick Ghiselin, Consultant; George King, Apache; Vianney Koelman, Shell; Carl Montgomery, NSI Technologies; Nelson Oliveros, Petrofac; Michael Payne, BP; Lanny Schoeling, KinderMorgan; Chris Singfield, Chevron; Eve Sprunt, Consultant; John Thorogood, Drilling GC; Scott Wehner, Consultant; Doug White, Consultant; David Zornes, Consultant


The new StingBlade conical diamond element bit from Smith Bits, a Schlumberger company, features a centrally placed diamond Stinger to more efficiently destroy rock in the low-velocity area at the center of the bit. By strategically placing a number of Stinger elements across the cutting face of StingBlade bits, engineers from Smith Bits have significantly improved footage drilled and ROP, produced higher build rates with better toolface control enhanced bit stability for bottomhole assembly shock and vibration mitigation, and provided larger cuttings for better surface formation evaluation at the rig site.
Compared with conventional polycrystalline diamond compact (PDC) cutters, Stinger elements have a much more aggressive conical shape, which enables an ultrahighconcentrated force that fractures high-compressivestrength formations more efficiently and generates larger cuttings and also drills with less torque and better steerability in directional applications.
In 250 bit runs conducted in 14 countries, StingBlade bits averaged a 55% increase in run lengths with a corresponding 30% increase in ROP. In the Browse Basin offshore northwest Australia, the operator drilled a 12¼-in. vertical section through formations comprised of interbedded hard limestone and chert with high compressive strengths.
The first StingBlade bit drilled 1,516 m (4,972 ft) at 11 m/hr (36 ft/hr). This delivered 97% more footage than the best runs with conventional PDC bits used on the closest offset well. ROP also improved 57%. The second StingBlade bit drilled the remaining section to total depth at an average ROP of 16 m/hr (52.5 ft/hr).


For many of the reservoirs discovered beneath salt zones, there is no recovery program without traversing up to 2,000 m (6,560 ft) of salt, seriously challenging drilling and cementing operations with threats of hole closure, lost circulation,
casing collapse and compromised zonal isolation due to cement contamination. Halliburton dedicated a global team of scientists to understand the cause of cement sheath failure from chemical effects of salts as well as the thermal and geomechanical loading from salt zones.
From this research, Halliburton scientists delivered the SaltShield cementing service. Even with up to 12% contamination, SaltShield cement is proven to prevent dissolution of the salts to help avoid a washed-out section, achieve competent zonal isolation and help reduce nonuniform load points that can cause casing collapse.
In the southern North Sea, the Zechstein Basin presents operators with creeping salt masses that induce cyclic loading from geomechanical and geochemical stresses due to the plastic flow of the salt zone. Two wells for one of the operators in the basin had failed shortly after being brought into production due to excessive water production and well abandonment. The salt slowly flowed unevenly around the casing, and the irregular external loading resulted in a partial casing collapse. Halliburton validated finite element analytic models to understand the plastic flow of the Zechstein salt zone and determine an optimized SaltShield cement slurry system for a new well. More than a year after beginning production, that well remains onstream without any evidence of negative effects due to salt-creep issues.


Using deep, directional electromagnetic measurements, the GeoSphere reservoir mapping-whiledrilling service from Schlumberger reveals subsurface bedding and fluid contact details more than 30 m (100 ft) from the wellbore. This reservoir view provides a depth of investigation increased by a factor of five compared to previous bedboundary mapping services. The service bridges the resolution gap between seismic images and those created by current near-wellbore petrophysical measurements. It delineates intrinsic layering of contrasting resistivity and maps both reservoir boundaries and fluid contact levels with results rendered in real time.
Among the benefits are geohazard avoidance and accurate targeting of reservoir sweet spots while drilling coupled with the acquisition of data to update 3-D reservoir models for better field development and production decisions.Geoscientists can use GeoSphere imagery to correct time-to-depth conversions of seismic images. The service can be combined with complementary LWD tools and is applicable in any well type. In Brazil Shell was drilling a deepwater well targeting a reservoir zone that extended across two fault blocks. The objective was to steer the wellbore so it would transition from a downthrown to an upthrown block to produce from both sides while penetrating reservoir sweet spots. The complex reservoir consisted of unconfined turbidite sands characterized as amalgamated distributary channels with shale zones above and below the reservoir. Based on real-time data Shell was able to adjust well trajectory to successfully drill both blocks while avoiding penetration of a nonproductive zone.


With the E&P industry transitioning into a context-driven digital environment, a workflow-oriented user experience has become increasingly important. The new user experience within Petrel is designed to make an impact on the productivity of oil company employees and has been validated by more than 40 Schlumberger customers during the development phase.
Some of its advantages include a logical interface configuration, a focused environment, reduced mouse clicks and an emphasis on interpretation and data. It also offers user tracking and behavioral investigations. And users can choose between a conventional seismic-to-simulation workflow or make a more focused geological and geophysical assessment.
The new interface is based on Microsoft’s ribbon concept and has reduced mouse travel time by 30% and mouse clicks by 35% while allowing users to spend an average of 30% more time interacting with data and workflows. Clients have referred to the new workflow as a “step change” and have noted, “The days of hunting for a button on the margins is gone.” Other feedback indicates that the ribbon interface enables logical, sequential workflows. During trials, 70% of the customers were confident using the new interface within three days, and 98% were fluent within a week.


As the offshore industry strives to minimize operating costs and maximize production, Archer’s modular drilling rigs (MDRs), the Emerald and Topaz, are an attractive alternative to expensive fixed drilling facilities. Although the concept of MDRs is not new, environmental restrictions and platform limitations reduced the opportunities for successful deployment, particularly in harsh-environment locations. Archer was convinced that adapting modular rig systems through the integration of modern technologies would address the limitations previously set. Key challenges included reducing the size/weight of the existing modules, reducing or eliminating the large crews and improving rig up time/operational efficiency. Archer built an offshore modular drilling unit that is fully NORSOK D-001 and U.K. compliant, allowing the units to operate in the harshest environments in the world.
In 2012, the Emerald began operations offshore New Zealand. As a super-single rack and pinion rig, the Emerald combines a proven alternative method of conveyance with the latest in drilling technologies all housed in a modular package. It is equally capable of undertaking drilling, workover, and plug-and-abandonment operations. The rig recently completed a series of wells in a client’s drilling program, with the second well drilling to a depth of more than 6,100 m (20,000 ft). The third well was completed eight days ahead of schedule. The fourth well in the series was completed 30 days ahead of customer expectations


The CoreVault system combines fluid sampling with rock coring and enables fluids to be obtained from low-permeability reservoirs without escaping during coring. The system provides a more accurate volumetric snapshot of the oil and gas content of unconventional reservoir rocks. In the past, 50% to 70% of the hydrocarbons escaped as the cores depressurized. Operators had to estimate this fluid loss when building their models. By preserving 100% of the fluids within the sample, CoreVault enables an improved understanding of potential production and can significantly enhance in-place estimates.
An operator working in Ohio and West Virginia used the system to sample cores, which revealed considerably more oil and gas in place than previous estimates had indicated. The system was run in five wells and gathered 150 core samples. The tool was able to retrieve up to 10 cores per trip. Compared to the 2.2 cu. m/ton (78.2 cf/ton) estimate derived from modeling, the CoreVault system indicated an average of 5.6 cu. m/ton (196.2 cf/ton), 2.5 times more gas than
expected. The multiple samples also enabled better targeting and completion efficiency and provided better information about the most profitable zones.


Halliburton developed the Environmentally Distinctive Burner (EDB) to redefine what an oil burner can do and what the industry should expect from one. Traditional oil burners can handle steady-state operation wells. If the expected flow rates are achieved, a clean burn often will result, but there is no room to adjust for changes to flow conditions or control transients such as ramping up flow rates and shutdown.
The EDB has a unique nozzle design that incorporates a pneumatic piston and valve to control in real time the functional position of each of its 10 nozzles, allowing the operator to keep the burner within the ideal operating envelope for the duration of the well test.
When a nozzle is closed, the oil flow is stemmed at the entrance to the atomization chamber, and the air flow is reduced proportionally. This allows all residual oil to be atomized and efficiently burned. This is an especially important feature as the majority of oil burner fallout comes from the brief shutdown period. Burner efficiency was witnessed by a recognized certification authority to be 99.99952% fallout-free, 14.5 times less fallout than the previous industry standard.
During its first operation offshore Brazil, through varying weather, well and flow conditions, the EDB flowed in excess of 6,700 bbl, eliminating about 69.48 l (18.35 gal) of fallout. The ability to monitor burner-head data and remotely operate the burner also allowed about three days without any recorded nonproductive time.


While greater stimulation compartmentalization and increased proppant have helped improve productivity, these can also lead to deteriorating economics in typical multistage completion designs. Halliburton’s AccessFrac IntraCycle stimulation service seeks to overcome these issues by providing multicycle-per-zone fracturing methodology. Through the use of optimized pumping schedules and diversion spacers to segregate multiple proppant cycles, the service provides a solution to the complex interaction of stage configuration, cluster spacing, material volumes and number of proppant cycles. The result is technical effectiveness and financial success.
In a Bakken completion, AccessFrac set a new record for the number of isolated proppant cycles placed over a single cemented plug-and-perf lateral completion. It also achieved a 300% increase in effective stimulation compartmentalization compared to conventional designs. Three segmented injection cycles were pumped sequentially over 33 mechanically isolated zones in the well with one pressure-activated toe sleeve. Initial results include a 27% higher IP and 24% higher 72-day total-zone produced liquids than previous wells.
In an Eagle Ford refrack, the strategy was to increase proppant pumped per foot and to add more perf clusters to the lateral. The refrack placed 6.44 MMlbm of proppant over 26 cycles, resulting in a 325% production uplift.


Geothermal energy is one of the leading renewable sources of environmentally friendly power generation. Recent improvements in drilling and extraction technology have enabled the creation of geothermal power plants in areas where the thermal resources lie deep under the surface. These developments represent a challenging set of downhole conditions and reservoir characteristics, with unique problems caused by high-volume, hot water flows. Temperatures up to 315 C (600 F) and 100% aqueous environments create well completion and operating problems. The Inferno completion system was developed during a time when completion tools that could withstand extreme conditions were needed by Geodynamics, a company focused on enhanced geothermal systems, in the Cooper Basin in South Australia. Packers Plus designed, prototyped and tested production packers, liner hangers, liner hanger packers, polished bore receptacles, seal assemblies, anchor latches and float equipment for 7-in. and 95⁄8-in. casing to withstand bottomhole temperatures of 315 C and pressures of 10,000 psi.
With the successful design and delivery of the Inferno completion tools within a short time frame, Geodynamics and Packers Plus Field Operations personnel were able to work past upfront challenges involving intense heat to successfully complete the well in preparation for hydraulic stimulation. Because the limits of oil and gas completions continue to be pushed by targeting deeper and hotter formations, the Inferno tools also have applications for multistage hydraulic fracturing.


Conventionally, drillers apply drilling parameters to the drillbit such as weight on bit (WOB) and rotary speed according to their past experience or referring to parameters specified in the well drilling program and keep these parameters unchanged over a long interval regardless of what formation is being drilled. However, the formation lithology and hole geometry changes during the drilling process; keeping constant drilling parameters to drive the bit will often cause an inadequate or excessive cutting process to the rock, which can result in low cutting efficiency such as bit balling from insufficient hydraulics or cutter damage from excessive impacts.
China National Petroleum Co. developed a real-time drilling indicator called Smart Driller Indicator (SDI) that tells the driller the WOB, rotary speed and mud flow rate that are adequate for penetrating a rock to achieve a higher ROP and longer bit runs. The optimized drilling parameters are calculated and updated by a soft-closed-loop solution called NAVO, which monitors the ROP and energy input to a bit in real time. Moreover, the NAVO incorporates a real-time drillstring vibration evaluation model to determine the envelopes of bit bounce, whirl and stick-slip so that the optimum drilling parameters can minimize the drillstring vibration level and maximize the ROP.
The performance of application of NAVO in more than 20 wells in China with footage of about 9,144 m (30,000 ft) shows that there is 20% to 54% ROP improvement and longer bit life compared to conventional drilling habits, saving customers rig time and money.


NOV’s Drilling Automation System and Optimization Service provides rig crews with a toolkit that offers more accurate control systems, improved real-time decision-making and enhanced analytical capabilities. The service has five main components:
• High-frequency downhole data acquisition tools;
• An IntelliServ high-speed telemetry network;
• Drilling applications and software;
• Optimization personnel; and
• Visualization and reporting.
The primary impact of the system stems from the integration of these five elements and has achieved several firsts, including the world’s first closed-loop control of slide drilling, the world’s first high-speed survey and toolface with 2-sec updates, the world’s first high-speed real-time drilling dynamics vibration data and real-time annular pressure measurements from the bottomhole assembly and two other locations in the tool string.
The service was deployed in two phases on a 10-well project in the Eagle Ford Shale. In the first phase wells 1 through 4 were drilled without wired pipe but with downhole sensor packages to establish a statistically relevant benchmark. In the second phase wells 5 through 10 were drilled with the full system. Since the project took place in an established field, the client expected a 10% reduction in spud-to-total depth (TD) time. However, the client actually realized a 43% reduction in spud-to-TD. This was attributable to increased ROP as well as longer tool life and saved the customer more than $800,000 in operating costs compared to Phase 1.


SmartCen is a supervisory computer system designed for custody transfer and allocation metering. The system comprises functionalities such as monitoring and control, reporting, log book, asset management, alarms, and trending. It also includes advanced functions for custody transfer metering applications such as virtual flow computers, integrated validation, mismeasurement management, online uncertainty calculation and metering diagnostic functions.
SmartCen ensures measurement integrity of custody transfer metering calculation and activity by adopting various international measurement standards into the modules. Real-time verification assures the operator that calculation accuracy is at its highest level and at the same time enables quick detection of abnormalities. Verifications done in real time significantly minimize human error and improve integrity. One significant function of SmartCen is mismeasurement management, which enables the system to calculate an alternative billing report if a mismeasurement event takes place, such as the failure of a device. As Smart-Cen consolidates critical data at minimum intervals of five minutes, it is able to correct recalculated billings based on the available prioritized data.
SmartCen can be deployed in both greenfield and brownfield facilities. In one installation the SmartCen system was installed at a brownfield facility to resolve issues caused by an existing conventional computer system. A comparative study was made on the measurement efficiency of both the systems. SmartCen recalculated the volume transferred based on the flow computer raw data and immediately alerted the user on a discrepancy in the existing flow computer calculation, resulting in a cost savings of $7 million per year.


Unconventional oil wells have experienced a boom in drilling and production activity. Since these wells are often horizontally drilled, the horizontal lateral length can exceed the vertical depth. The kick-off point and radius required to reach the production zones vary widely in these wells. One of the issues these drilling practices create is limiting the installation of electrical submersible pumping (ESP) systems. A severe buildup rate in the curve section of the well can prevent safely landing an ESP at the deepest possible setting depth. Because industry guidelines recommend not installing an ESP system through a buildup rate greater than 6°/30 m (100 ft), systems are typically placed in the vertical section of the wellbore, which can adversely impact production.
The CENesis Curve tight-radius ESP system from Baker Hughes overcomes this challenge, allowing operators to land the ESP system closer to the pay zone to maximize production and reserve recovery. A new design of the connections between ESP system components allows the system to reliably pass through buildup rates in excess of 15°/30 m.
During installation, the mechanical stresses on the connections can make them the most vulnerable part of the system. The CENesis Curve threaded connection is able to withstand greater mechanical stresses than the standard bolted
flange design, minimizing reliability issues. This innovative new system can reduce rig time, and its threaded connection helps avoid the risk of dropping bolts or tools downhole during installation.


The innovative Rig-Free technologies offered by Weatherford, specifically the Rig-Free light-duty pulling and jacking unit (PJU), have great potential to improve efficiency and limit the expense of intervention and abandonment operations. The Rig-Free unit eliminates the need to employ costly jackup and workover rigs for offshore intervention and abandonment campaigns. It is especially well suited for pulling conductors on platforms with downgraded structural capacities and in situations where space is limited. The unit’s jacking system, telescoping mast and power swivel offer a pulling capacity of 35,000 lb in 13.4-m (44-ft) increments and a jacking capacity of 1 MMlb in 1.5-m (5-ft) increments. The Rig-Free light-duty PJU also is highly mobile and adaptable.
A major operator was embarking on a well abandonment project encompassing six wells in the Gulf of Mexico. Limited area was available for pulling and jacking operations, and pipelines, seabed debris and dissimilar spud-can patterns presented potential issues for a jackup rig. The Weatherford team recommended using the Rig-Free light-duty PJU. The project consisted of cutting and pulling various tubulars at depths up to 2,135 m (7,000 ft). Because the unit has minimal reliance on the platform crane, the operator was able to perform wireline and coiled tubing operations simultaneously. The project was completed in 1,545 hours, including mobilization, demobilization and all operations. The nonproductive time associated with the Weatherford team’s services was only 11 hours, less than 1% of the overall time.


The North American shale revolution has demonstrated that pad drilling and extended-reach horizontal wells can deliver operational cost efficiencies and excellent production results. However, extended-reach horizontal wells can challenge the casing run-in operations. The lateral section can cause friction and drag forces that exceed the hook weight of the rig or the buckling capacity of the casing and prevent casing from reaching the planned depth. The casing flotation method involves trapping air or a lighter fluid in a chamber at the lower end of the casing string to help buoy the weight of the string so that it is not fully resting on the wellbore in the horizontal section, thus reducing casing drag. While hook load is not the primary concern when running casing in shale wells, casing buckling is. Smaller casing sizes are prone to buckling in horizontal wells, which can cause casing to miss the planned depth by hundreds or thousands of feet.
Halliburton’s Buoyancy Assisted Casing Equipment (BACE) assembly helps reduce the run-in force required in the lateral section, alleviating the drag force that can induce buckling. With the BACE assembly, a single rigup is used for both the pump line and the return line to the mud pit. The single line facilitates a modified operation involving measured displacement with a volume of mud equal to the buoyant chamber volume. The BACE assembly evacuation process establishes circulation in 45 minutes on average, providing an 85% efficiency improvement over the conventional evacuation method.


Water detection and tracking are crucial to offshore operators. Many subsea wells only gather flow and water-cut information at the manifold where production fluid from multiple wells is commingled. This does not allow monitoring of water-cut data from individual wells. The Weatherford Red Eye subsea water-cut meter is a probe-style sensor that gives operators a well surveillance tool that enables them to know when water production starts, where water flow originates and what the relative concentration of hydrate inhibitor is in the line.
These data enable operators to more accurately track water production and thereby optimize flow assurance and reservoir management. The tool can be installed anywhere in a subsea production system and can operate in full threephase flowstreams at any gas-volume fraction. The Red Eye meter is the first standalone subsea meter capable of measuring water cut in a multiphase line. This is also the first subsea sensor capable of detecting early water onset in gas wells at the level of 0.25 bbl of water per 28,300 cu. m (1 MMcf) of gas. With minimal power and communication requirements, the meter enables operators to track the water production of each well. It is rated at 15,000 psi and suitable
for installation at a depth of 3,048 m (10,000 ft). This tool can be applied to any type of subsea production system, including HP/HT wells. The Red Eye subsea water-cut meter is based on the topside Red Eye watercut meter. A thorough qualification program was started in 2012 and completed in early 2014.


Produced water represents by far the largest waste stream in oil and gas production operations. Optimized produced water treatment solutions that feature greater capacity and performance have become increasingly necessary to adhere
to admissible disposal regulations while maintaining desired oil production rates. Newbuild offshore production facilities in particular require a process solution for produced water that meets the highest standards of oil removal while simultaneously minimizing operator interference requirements. The new Schlumberger EPCON Dual compact flotation unit (CFU) technology introduces an engineered internal design that incorporates residual flotation gas in a secondary separation stage, increasing oil-in-water removal efficiency while fully degassing the clean water outlet. Pilot testing in an onshore controlled environment resulted in 75% greater oil removal efficiency compared with conventional technologies. Due to its compact simplified design, the system achieves optimal water treatment in 50% of the footprint of a conventional system, saving rig space and streamlining operations. One single-pressure EPCON Dual CFU can accommodate flow rates between 500 bbl/d and 150,000 bbl/d. The technology was deployed on a Statoil installation in the Norwegian sector of the North Sea. Post-treatment outlet oil concentration was measured to be 10
ppm, down from more than 25 ppm before treatment. The results also verified 27% better separation rates compared to conventional technologies.