The E&P editors and staff proudly present the winners of the 2014 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 monumental changes in their sectors and represented techniques and technologies that are most likely to improve geosciences, drilling, production, completions, field development, systems integration, 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. They are distinguished as the most groundbreaking in concept, design and application.

The award program recognizes new products and technologies designed by people and companies that 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 engineers and engineering managers 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 2014 awards at the Offshore Technology Conference in Houston, Texas, on May 5, as well as at Hart Energy’s DUG Permian event May 20 to May 22 in Fort Worth, Texas.

An entry form for the 2015 Special Meritorious Awards for Engineering Innovation contest is available at EPmag.com. The deadline for entries is Jan. 31, 2015.

2014 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

Lanny Schoeling, KinderMorgan

John Thorogood, Drilling GC

Scott Wehner, Chaparral Energy

Doug White, Consultant

David Zornes, Consultant

COMPLETIONS WINNER

Schlumberger | ELEMENTAL degradable alloy fracture ball

Many operators using ball drop systems for multistage stimulation have noted that their completions fail to produce as expected from logs or offset wells. After analysis, they conclude that ball failure is the likely reason.

Differential pressure across the ball seat can cause the balls to deform and get jammed in their seats; as a result, they are unable to be dislodged during flowback. Deformed and jammed balls can plug all production from beneath. The only solution is to trip into the well with coiled tubing and mill out the balls and seats.

The ELEMENTAL degradable alloy fracture ball eliminates problems related to deformed and jammed balls.

The key is its twofold degradation process. The first part involves micro-galvanic cells built within the structure of the material. Crystallographic phases electrochemically interact in the presence of an electrolyte (water), degrading the material. The second part is the engineered inability of the material to form a protective layer on the outermost surface.

The product of the degradation process is a fine powder that does not impede production and is easily circulated out during cleanup.

These degradable balls were run in a six-stage well. The pressure log showed a clear ball signature for all stages. Different fracturing profiles for the stages confirmed that each was fully isolated from the others. After treatment, the well did not flow back naturally to surface. This was expected, and coiled tubing was brought in to lift the well and recover any debris or ball residue. The coiled tubing passed through all six nipples, indicating that there was no ball residue impeding flow. The entire job was completed in just five hours.

COMPLETIONS WINNER

Schlumberger | Moment Tensor Inversion

One of the latest technological advances for hydraulic fracturing operations is Moment Tensor Inversion (MTI), a seismic processing technique that describes the inelastic deformation of the source region from which microseismic energy propagates. Operators can distinguish failure modes and analyze fracture planes and their orientation for each microseismic event in a fracturing operation.

MTI provides information on the response of a reservoir to a hydraulic fracturing treatment. It can analyze pre-existing fracture systems and those augmented through growth or created by stimulation. Operators can acquire statistics on fracture orientation, volume creation and proppant placement. Imagine how post-fracture productivity would be enhanced if the optimal spots to place perforation clusters and locate zonal isolation to deliver specific results were known. MTI analysis can be deployed on individual wells or stages and extended to field issues such as well spacing and drainage of complex reservoirs.

In mid-2013 Schlumberger introduced the first commercially available anisotropic MTI service, which was performed on a downhole multiwell monitoring microseismic job. Several additional processing steps are necessary to tune the velocity model for the anisotropy observed in the field. The results provided new information to the client on the progression of the hydraulic fracture growth and resulting mechanical deformation.

No new tools are required to add MTI to a hydraulic fracturing treatment. It is a software addition to the Petrel E&P platform. Benefits include improved completion analysis and effectiveness, better determination of well spacing and effective drainage volume, new and intuitive visualization technique for nonexperts, and characterization of all fracture networks.

COMPLETIONS WINNER

TEAM Oil Tools | ORIO XL Frac Sleeve

The majority of horizontal wells are completed with the traditional method of plug and perf. Ball-activated frack sleeve technology is an alternative option but is typically more suitable for openhole completions vs. cemented laterals. Ball-activated frack sleeves have historically used incremental ball sizes, which can limit the number of sleeves that can be run in a cemented lateral due to the geometrical constraints.

The ORIO XL Frac Sleeve’s design allows the tool to be run in large quantities, addressing the limitations of the traditional ball-activated frack sleeves, according to TEAM Oil Tools. Traditionally, the maximum number of stages that could be completed with incremental ball-activated frack sleeves is between 30 and 45. The ORIO XL allows 90 individual stages or an infinite number of cluster sleeves without ever dropping a ball smaller than 4 in. for the 5.5-in. tool.

The proprietary design allows the tool to cycle or count while dropping the balls. Once the sleeve reaches its designated cycle position, the tool opens, allowing the stimulation job to begin. Similar to the company’s ORIO Toe Valve, the critical moving parts of the frack sleeve that perform the cycle are encapsulated within the three layers of the tool, protecting it from the frack proppant. The ability to individually stimulate through 90 sleeves vs. multiple clusters allows for new frack designs that reduce surface horsepower requirements but that also deliver fixed proppant volumes and rates into each individual frack sleeve.

These frack designs are smaller in scale but more efficient and effective. The effective rate through each sleeve is greater than what was achieved with a cluster design but uses less surface horsepower.

DRILLING OPERATIONS WINNER

Baker Hughes | SeismicTrak seismic-while-drilling service

The Baker Hughes SeismicTrak seismic-while-drilling service provides first arrival and waveform data in real time to reduce formation uncertainty, allowing operators to hit their reservoir targets under a variety of complex conditions in a safer drilling process.

Although surface seismic data have large uncertainties, especially in the high-risk, subsalt and deepwater markets, they provide the basis for the majority of wells drilled today. The SeismicTrak service allows operators to immediately update surface seismic models in real time and without impeding overall drilling operations, which reduces uncertainty by detecting important reservoir features and potential drilling hazards such as faults and pore pressure regions. The rugged service, built to withstand the rigors of deepwater drilling, proves useful when faced with velocity uncertainties, pressure transitions, challenging trajectories or nearby salt bodies.

The service has been run in a vertical ultradeepwater Gulf of Mexico deployment. The measurement objectives were to place the drillbit on the surface seismic to obtain subsurface velocity control, to reduce the depth uncertainty of the target zone while drilling and to gather a wireline equivalent dataset within an operational time window of less than 10 minutes.

The service enabled a real-time correction of the subsurface attributes without the need for any ambiguous data adjustments, giving the driller timely feedback about the bit position and the most optimal drilling path to the target. The high quality of the data eliminated the originally planned vertical seismic profiling wireline run.

DRILLING OPERATIONS WINNER

Baker Hughes | IRev infinite revolution impregnated bit

The Hughes Christensen IRev infinite revolution impregnated bit from Baker Hughes improves run life while minimizing trips and the number of bits required when drilling in hard and abrasive intervals, including sandstones or complex sections interbedded with softer shales.

IRev technology features a new cutting structure including diamond-impregnated posts that allow a more aggressive rate of rock removal and enable the bit to drill in places where polycrystalline diamond compact (PDC) bits typically cannot perform and where roller cone bearing life is a concern. The diamond-impregnated posts are manufactured to ensure uniform exposure of the diamonds as the bit drills deeper into the formation. As diamonds wear away, fresh diamonds are exposed to enhance performance and further extend bit life.

IRev technology was used in the Colombian foothills to improve bit durability while drilling through the challenging Barco and Guadalupe formations. Offset wells in these formations were previously drilled with PDC bits, tungsten carbide insert bits and outdated impregnated bits, which had difficulties getting through the section.

After drilling, the dull condition of these bits was poor, and multiple bits were needed to get through the hard and abrasive formations. After drilling, the IRev bit was in dramatically better condition compared with the other bits used on offset wells. The IRev bit exhibited even wear across the profile of the bit and maintained sharp diamonds on the surface of the matrix.

DRILLING OPERATIONS WINNER

Halliburton | FlexRite Multibranch Inflow Control System

One important goal of multilateral wells is increased oil recovery and optimized slot recovery, especially in mature subsea fields. The high cost of infrastructure and rig operations continues to drive the use of multilateral technology to maximize reservoir contact and intelligent completions to optimize production.

The FlexRite Multibranch Inflow Control (MIC) System by Halliburton is a multilateral junction and completion system that allows each lateral to be completed with sand screens, swellable packers, inflow control devices and interval control valves (ICVs) to help maximize oil production from each multilateral leg.

This system provides sand control at the junction and the ability to remotely control flow of each individual branch of a multilateral well with three or more legs without costly subsea intervention. Less well infrastructure is needed to drain larger and more varied reservoirs.

The multilateral system can deploy a single-trip completion system consisting of multiple slim-hole ICVs through stacked TAML (Technology Advancement--Multilaterals) Level 5 junctions. An unlimited number of MIC junctions can be installed, with each ICV isolated at each junction. Production or injection can be managed and controlled at each individual lateral, delaying water/gas breakthrough and optimizing production.

The world’s first TAML Level 5 multilateral well with remote individual inflow control of three laterals was completed from a semisubmersible rig on the Troll Field in the North Sea. The 10¾-in. MIC system was installed with three inflow control valves, and all are operating successfully.

The offshore field had primarily been a gas field with the oil previously deemed uneconomical to produce with thin oil-bearing layers overlaid by a thick gas cap. It was important to use a multilateral system that provided sand control at the junction.

DRILLING OPERATIONS WINNER

Lloyd’s Register | BOP risk model

When faced with BOP pull or no-pull decisions, the BOP risk model gives operators the answers they need to quickly and consistently make decisions on the best course of action. Using engineering principles, the BOP risk model, combined with RiskSpectrum software and the RiskWatcher operator interface, assists with these critical decisions.

Each risk model is custom-built using the piping and instrumentation diagrams and original equipment manufacturer manuals for a specific BOP through extensive step-by-step failure modes and effects analyses. The BOP risk models can include, per risk model, more than 730 components modeled, 1,300 failure modes modeled and more than 450 fault trees. Each risk model employs regional regulations, specifications and operational procedures to consistently and accurately assess and render a pre-considered, risk-based decision much quicker than traditional methods, saving operators time and money.

The risk model was used for the first time in 2013 in the Gulf of Mexico. In its first use, the BOP risk model saved the drilling contractor an estimated 2.5 days of nonproductive time (NPT) and kept it from needlessly bringing the BOP to the surface for further inspection. This dramatically reduced the number of days of NPT normally associated with this task and provided a complete return on investment the first time it was used. Based upon this success, two more risk models were ordered and were scheduled for delivery to the same drilling contractor in January 2014.

DRILLING OPERATIONS WINNER

Smith Bits, a Schlumberger company | ONYX 360 rolling PDC cutter

The ONYX 360 rolling polycrystalline diamond compact (PDC) cutter from Smith Bits represents an advance in cutter technology. The ONYX 360 cutters are free to rotate 360 degrees during drilling. Unlike a conventional fixed cutter, this continually presents a fresh cutting surface to the rock, extending every performance parameter by an average of 50%. The ONYX 360 provides multiple benefits, including increased bit life, greater ROP and reduced cutter wear.

One of the toughest areas to drill is the Granite Wash Formation. An operator was challenged to drill 61/8-in. lateral gas well sections through the abrasive sandstone that characterizes Texas Panhandle Granite Wash reservoirs. The PDC bits being used were experiencing worn, chipped and broken cutters. Beyond these dull characteristics, damage to the bits’ cutting structures quickly reduced ROP to unacceptable levels. In extreme cases, bit replacement trips were required every 20 m (65 ft).

Smith Bits design engineers used Schlumberger’s IDEAS drillbit design platform to design an MSiR613 61/8-in PDC bit with an ONYX 360 cutter strategically located at each of the seven highest-wear positions indicated by the computer program.

The operator drilled 476 m (1,562 ft) of a 1,558-m (5,113-ft) lateral gas well section at a rate of 7.6 m/hr (25 ft/hr) using the ONYX 360 equipped bit. ROP was increased by 44%, and footage drilled increased 57%. In comparison with the best previous performance with a PDC fixed-only cutter bit in the same formation, the ONYX 360 equipped bit dull graded 3:1 while the conventional bit graded 6:3.

DRILLING OPERATIONS WINNER

Schlumberger | MicroScope HD

Operators that have gone into old wells with modern logging services have discovered millions of barrels of bypassed reserves. The logging instruments available when the well was drilled lacked the resolution to detect, much less evaluate, thin beds, complex mineralogy and low-contrast pay.

The new MicroScope HD high-definition imaging-while-drilling service provides 360-degree imaging for reservoir description with a resolution of 16 mm (0.4 in.) for fracture characterization, structural modeling, sedimentology analysis and completion optimization. The imaging technique employed is a high-definition laterolog-type measurement. The tool also features four azimuthally focused resistivity measurements taken at four depths of investigation plus two nonazimuthal resistivity measurements. These are combined with an azimuthal gamma ray and sensors that acquire continuous borehole inclination, bit resistivity and mud resistivity. In Oman, an operator had to drill through a complex siliciclastic reservoir with a trajectory that crossed several faults and a dense fracture network.

One well was drilled close to the top of the Shuaiba formation to access attic oil. Despite several uncertainties regarding the structure of the formation boundaries, lateral facies changes within the reservoir, multiple fault-crossings close to the formation top, target depth and thickness, images were used to guide the borehole trajectory that allowed drilling of 1,279 m (4,195 ft) of drain hole within the reservoir.

FIELD DEVELOPMENT WINNER

Schlumberger | InSitu Viscosity

Schlumberger introduced a new downhole sensor for a wireline formation tester tool to measure the viscosity of hydrocarbons. The conventional methods for obtaining formation fluid viscosity are laboratory analysis at surface and pressure-volume-temperature correlations. However, deducing viscosity from correlations introduces uncertainties. Surface viscosity measurement may be affected by alteration of the sampled fluid through pressure and temperature changes.

The new sensor uses a vibrating-wire (VW) viscosity measurement method that meets requirements not only for measurement performance but also for operations in downhole applications.

Sampling and downhole fluid analysis (DFA) including the VW viscosity measurements were performed in a light oil reservoir in deepwater Gulf of Mexico wells. The examples showed the applications of the in situ viscosity integrated with other DFA measurements and petrophysical and geological logs for reservoir connectivity, compositional grading and other major field decisions.

In the first well, the in situ viscosity results were integrated with other DFA measurements such as density and gas/oil ratio in all the DFA stations and petrophysical and geological logs. The analysis showed consistent compositional variation across the reservoir. Advanced equation-of-state modeling was performed and confirmed that the fluid is in equilibrium and most likely connected.

After the wireline job in the second well, detailed laboratory analysis was performed. The comparison to the viscosity results showed good agreement.

GEOSCIENCES WINNER

PGS | Towed Streamer EM

Towed-streamer electromagnetics (EM) will enable the industry to record seismic and EM data simultaneously. Conventional controlled-source EM (CSEM) is based on recording nodes emplaced on the seafloor. The vessel then sails back and forth emitting a constant signal until sufficient signal-to-noise (S/N) is assumed to have been achieved. This involves slow and costly deployment and collection of the receiver stations, and the acquisition is performed without insight into the quality of the recorded data.

With the towed-streamer EM system, the source and receivers are towed in an acquisition layout and methodology that is very similar to a 2-D seismic survey, and the system is indeed combinable for simultaneous acquisition of 2-D seismic. The main problem with the system is the noise generated when the receiver dipoles are moving in relation to the Earth’s magnetic field in the conductive seawater, but the system now produces data with a similar S/N level as the conventional node-based CSEM systems.

To get the best value out of towed-streamer EM data, it needs to be combined with 3-D seismic data. The method outlined here is referred to as seismic-guided EM inversion, where a sparse-layer depth model defined by seismic is used to suggest resistivity boundaries without rigid constraints. The inversion workflow was applied to a complex geological region where the heavy oil fields known as Bressay and Bentley are located in the North Sea. The data quality is good with a low noise level, and the overall uncertainties in the data are in the order of about 5%.

HSE WINNER

Baker Hughes | Bifuel fracturing service

Baker Hughes’ Rhino Bifuel hydraulic fracturing pumps burn a mixture of natural gas and diesel to reduce diesel use by up to 70% with no loss in hydraulic horsepower generation.

The bifuel service substitutes natural gas for a significant percentage of diesel in a retrofitted diesel engine. The bifuel-powered frack pumps meet all U.S. Environmental Protection Agency emissions standards. The service also can help ensure fracturing operations comply with Tier 2 regulations for nitrogen oxide and nonmethane hydrocarbon emissions. In addition, the bifuel service offers the possibility of reducing flaring activities on the job site since it can use field gas as a source of power.

At a 50% substitution rate, the bifuel pumps can operate twice as long as engines running solely on diesel and can nearly eliminate hot fueling, which minimizes risks for spills. Reducing fueling demands during operations also reduces fuel transportation costs and the hazards resulting from large trucks traveling long hours to remote operations. When fueling a frack operation with diesel alone, the supply chain can be complex, with costs added at every step along the way. Baker Hughes’ bifuel service can tap into a wellhead or line gas in the field to simplify logistics and maximize operational efficiency.

The company converted its first hydraulic fracturing units to bifuel during fall 2012 to conduct one of the first bifuel pumping jobs in the Eagle Ford Shale. The operator used the technology to cut diesel consumption and reduce emissions. From November 2012 to present, Baker Hughes has rapidly accelerated the deployment of its bifuel service throughout North America and expects to have the largest number of bifuel fleets available to the market throughout 2014.

HSE WINNER

Schlumberger | CoilScan real-time coiled tubing pipe inspection system

The CoilScan real-time coiled tubing (CT) pipe inspection system enables users to predict the effective service life of CT using actual metallurgical measurements rather than only empirical data.

CoilScan makes real-time dimensional measurements, including wall thickness and diameter, depth, and defect detections. It provides noninvasive real-time monitoring of CT pipe condition before, during and after jobs, eliminating costly problems during CT interventions.

CoilScan has the potential to eliminate up to 83% of failures by accurately predicting them before the pipe enters the well, Schlumberger said.

In an extremely harsh environment of a large sour gasfield development in the Middle East, an operator expected exacerbated effects of fatigue cycles imposed as the CT was deployed into and out of the wells due to the combination of the high temperature, H2S and CO2 concentrations, and corrosive stimulation chemicals.

A quasi-4-D inspection technique was used to quantify the adverse corrosion effects. Additional defects detected between runs could provide a proxy for the corrosion rate, allowing engineers to predict the risk of failure before a catastrophe occurred. CoilScan was used to acquire and analyze real-time metallurgical data and evaluate the health of the pipe as it was used.

Actual real-time monitoring results were compared with predictions and benchmarked by the periodic lab testing of pipe samples so the risk evaluation could be reassessed. The results observed so far have led to a more rigorous approach to CT pipe management and the establishment of a baseline for development of a more balanced risk mitigation process and subsequent optimized tubing usage.

HSE WINNER

Det-Tronics | FlexSonic Acoustic Gas Leak Detector

The FlexSonic acoustic gas leak detector introduced by Det-Tronics offers protection against gas leaks in E&P operations. This technology has an advantage over conventional, noncontact gas leak detectors, which rely on the gas concentration from a leak to make contact with the gas detector and can be compromised by environmental conditions.

Unlike other acoustic gas leak detectors that are based on sound metering, FlexSonic operates on the principle of sound analysis of both amplitude and frequency across the full sound spectrum, measuring and analyzing acoustic sounds to differentiate gas leaks from normal background sounds.

Software within FlexSonic measures and marks a site-specific noise “signature,” discerning between gas leaks and background sounds.

In large fin-fan operations within gas compressor stations, flanges secure and seal connections between the gas inlet and outlet pipes to the fin-fan cooler. Because the gas is carried through these pipes under high pressure, a flange could potentially fail, causing a breach in the seal or a pipe rupture. If the high-pressure gas leak were to come into contact with an ignition source, there is potential for an explosion. Therefore, this area requires gas detection.

In a gas compressor station in Thailand, the process site included pressurized gas. The onsite engineering team confirmed that FlexSonic would provide optimal protection when installed along the side of the fin-fan cooler.

Acoustic technology detects the ultrasonic sound signature of a gas leak at the leak source. In this application, air movement increased the dispersion of gas to potential levels that conventional fixed gas technology could not detect, while FlexSonic responded only to the leak source.

PRODUCTION OPERATIONS WINNER

GARP Services LLP | Gas-assisted rod pump

Gas-assisted rod pump (GARP) is a patented artificial lift method designed to recover reserves currently being abandoned due to inadequacies in conventional artificial lift design for pressure depletion-drive horizontal and deviated wellbores.

One version of GARP uses a dual-tubing arrangement and combines rod pump and gas artificial lift. GARP prevents gas interference in the pump and allows more reserves to be produced than conventional methods. Another version of GARP provides artificial lift for smaller casing wells and also has applications for vertical wells that are too deep to rod-pump or that have extended perforated intervals.

In a recent case study, a horizontal Austin Chalk completion located in Grimes County, Texas, was drilled in September 1994 with 75/8-in. casing. It produced 194 Mbbl of oil and 150 MMcm (5.3 Bcf) of gas until August 2009, when it was shut in due to liquid loading and marginal economics. GARP was installed in May 2013, and the well began producing approximately 100 bbl/d of water for more than a month before beginning to produce hydrocarbons. As of September 2013, the well was averaging 5.4 Mcm/d (190 Mcf/d), 4.5 bbl/d of oil and 75 bbl/d of water. If the well follows the established and predicted decline curve, it will produce an additional 31 Mbbl and 61.5 MMcm (2,172 MMcf), representing a 36% increase from the pre-GARP cumulative production on a boe basis.

Good candidates for GARP include pressure depletion-drive reservoirs in horizontal, deviated or vertical wells with 41/2-in. or larger casing strings and a cumulative production in excess of 100 Mboe that have no permanent obstructions in the wellbores and show evidence of liquid loading, even with existing artificial lift equipment.

PRODUCTION OPERATIONS WINNER

Schlumberger | PIPESIM steady-state multiphase flow simulator

PIPESIM steady-state multiphase flow simulator is used to model well performance, conduct nodal analysis, design artificial lift systems, model pipeline networks and facilities, and develop field production plans.

The software allows petroleum, production, pipeline and facilities engineers to design, simulate, analyze and optimize well and network hydraulics, flow assurance and field development plans. The program fits strategically with other Schlumberger software applications programs, workflows and solutions such as the Petrel E&P software platform.

PIPESIM was recently used by the Amal Petroleum Co. (AMAPETCO) to optimize its subsea network flow and overcome a number of issues that were preventing it from producing its reservoirs to full potential. Existing capacity was challenged by varied reservoir pressures, while flow assurance was often compromised by hydrates, slug flow, erosion and bottlenecks. Schlumberger proposed a three-step solution: first, gather varied network data; second, create a robust model using PIPESIM software and undertake history matching; and third, perform simulations to test different flow assurance scenarios.

Using the PIPESIM steady-state multiphase simulator, a comprehensive network model was generated. After history matching, applicable horizontal and vertical flow correlations were evaluated. The best combinations were selected to show the smallest difference between simulated and actual surface pressure measurements.

The new history-matched PIPESIM network model allowed AMAPETCO to run multiple flow assurance scenarios and select optimum pipeline designs as well as increase network capacity to match the production potential of its multiple reservoirs. An added benefit was reduced pipe costs and the ability to determine ideal pipe coating, type, thickness and application technique.

SYSTEMS INTEGRATION WINNER

Baker Hughes | WellLink Vision mobile application

The WellLink Vision mobile application allows users to access important data on their smartphone or tablet. Operators can use this tool to monitor producing wells and to optimize production and prolong equipment run life. The mobile application is an extension of the WellLink Vision platform that can be used on the go.

Features include real-time data access, manual data entry, memos and the ability to demand a data poll. Capable of issuing two-way commands to the field controller, alarms can be quickly visualized and responded to within the application.

For one independent operator, most of its well information was communicated and updated within the WellLink Vision program, but the operator chose to use manual gauges to gather the tubing and casing pressures. This resulted in daily trips to the sites to manually collect those values and an additional data entry step at the office to upload information to the WellLink Vision program. Using the application, technicians began using their mobile devices to actively monitor well conditions and receive notifications while in the field. Access to the real-time well information allowed the technicians to proactively address the problematic wells based on live information.

This process allowed the technicians to work more efficiently and reduced overall travel time by more than 40%. The technicians also began using their mobile devices to enter well data while at the well sites, making it accessible in real time to the operator.

SYSTEMS INTEGRATION WINNER

Liquid Robotics Oil and Gas | Wave Glider

The Wave Glider, a remotely piloted, renewably powered autonomous marine vehicle from Liquid Robotics Oil and Gas, a joint venture between Schlumberger and Liquid Robotics Inc., is addressing the challenges of continuously obtaining various offshore datasets in the face of increasing costs and safety concerns for personnel and vessels. The technology offers data delivery services without reliance on vessels, offshore manpower or even favorable weather conditions in which to operate.

The Wave Glider can be configured into distinct models that target particular oil and gas needs. The METOC Wave Glider is designed as a pilotable and mobile metocean vehicle that delivers data to oil companies and oilfield service information to reservoir engineers by integrating an acoustic transceiver that communicates from the vehicle to a subsea-mounted acoustic data logger. Further Wave Glider models have been fitted with turbidity sensors that consistently monitor seaborne particulate matter during dredging operations, providing real-time information in sensitive environment zones.

The METOC Wave Glider has been successfully deployed to mitigate risks with seismic streamer surveys conducted around obstructions in the Gulf of Mexico. Wave Gliders equipped with acoustic Doppler current profilers were deployed across each of the obstructions. Data were sent directly to the seismic survey vessel via a secure Internet service and could be viewed at other locations. This operation was done in a cost-effective manner, and the gliders replaced systems usually mounted on chase vessels, which were deployed for other important navigational challenges on the operation.