The E&P editors and staff proudly present the winners of the 2017 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 22 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 artificial lift, drillbits, drilling fluids/stimulation, drilling systems, exploration, floating systems and rigs, formation evaluation, HSE, hydraulic fracturing/pressure pumping, intelligent systems and components, IOR/ EOR/remediation, nonfracturing completions, subsea systems, and water management 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 groundbreaking 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 2017 awards at the Offshore Technology Conference in Houston.

An entry form for the 2018 Special Meritorious Awards for Engineering Innovation contest is available at The deadline for entries is Jan. 31, 2018.


An expert panel of judges has selected the top 22 industry projects that open new and better avenues to the complicated process of finding and producing hydrocarbons around the world.

  • Allen Bertagne, Consultant
  • Ben Bloys, Chevron
  • Mike Forrest, Consultant
  • Dick Ghiselin, Qittitut Consulting
  • Dave Johnston, Differential Seismic LLC
  • George King, Apache Corp.
  • Peter Lovie, Peter M. Lovie, PE LLC
  • Nelson Oliveros, Petrofac
  • Bill Pike, NETL
  • Paul Ryan, Chevron
  • Steve Sasanow, Consultant
  • Lanny Schoeling, Kinder Morgan
  • Eve Sprunt, Consultant
  • John Thorogood, Drilling GC
  • Scott Weeden, Consultant
  • Doug White, Consultant



Electric submersible pumps (ESPs) are traditionally run on jointed tubing, with rigs or heavy workover hoists pulling out the production string whenever the ESP must be replaced. The production deferment resulting from waiting for rig availability and the increase in operating expense erodes asset value and increases ownership costs.

The plug-and-play design of the ZEiTECS Shuttle Rigless ESP Replacement System enables standard ESP assemblies to be retrieved and redeployed without a rig by using wireline, coiled tubing or sucker rods.

The downhole electrical wet-connector technology allows standard ESPs to be shuttled through tubing without a rig or hoist. The system comprises two main assemblies: the retrievable ESP string and a tubing-deployed semi-permanent completion that includes a docking station.

The docking station houses three electrical wet connectors that supply power to either a standard three-phase AC induction motor or a permanent magnet motor. A landing surface bears the weight of the retrievable string and the reactive forces generated by the ESP. An offset throughbore allows reservoir access.

A seal assembly atop the retrievable string incorporates two cup-type packers to prevent recirculation between the pump intake and discharge. The assembly incorporates slips to transfer some of the ESP forces to the tubing to prevent undue compression of the pump stack. An automatic flow bypass drains the tubing upon retrieval.

The technology makes it feasible to deploy test ESPs to clean up wells and measure reservoir productivity before upgrading to a lift system optimized for well conditions.



Polycrystalline diamond compact (PDC) bits have become the dominant bit type in the oil and gas industry, drilling more than 90% of the worldwide footage. Much of this progress has come from the innovations made to PDC cutters, yet almost all of the improvements have been to the polycrystalline diamond materials, with little changes made to the cylindrical shape.

As drilling applications become more challenging, new cutting element design such as the AxeBlade ridged diamond element is needed to make step changes in performance for all formation types.

The ridged shape of Axe elements cut rock in a new way—with a combination of the shearing action of a conventional PDC cutter and the crushing action of a tungsten carbide insert in roller cone bits. This cutting method enacts a higher concentration of stress at the ridge to improve cutting efficiency and achieve at least 22% deeper penetration, removing more formation to provide higher instantaneous ROP when using the same weight on bit and rpm applied to conventional PDC cutters. The unique shape also reduces the cutting force required by about 30%, which translates to less overall torque, minimized reactive torque fluctuations and improved toolface control in directional applications.

In addition to the unique shape, the diamond table is 70% thicker than that of a conventional cutter and comprises a proprietary polycrystalline diamond-grain-size distribution. This combination gives the Axe element increased frontal impact resistance and enhanced heat dissipation.



Difficult drilling environments such as hard and abrasive carbonates and interbedded formations often push the reliability limits of a drilling system for a bit and bottomhole assembly due to various downhole dysfunctions— this ultimately extends the time and costs of the drilling operation. The Baker Hughes Kymera XTreme (XT) hybrid drillbit was designed with these challenges in mind.

By combining advanced engineering, customized application guidelines and the industry’s most advanced hybrid bit designs, the Kymera XT delivers better drilling performance through challenging formations—with higher ROP, extended bit life and less downtime.

The hybrid bit design combines the shearing action and speed of polycrystalline diamond compact (PDC) bits with the stability control of tricone bits. This hybrid design allows the roller cone to pre-crush the rock, weakening the formation and allowing the PDC portion to improve upon shearing aggressiveness over conventional bits while minimizing vibrations with fewer downhole tool failures. The bit also is designed to minimize stick/ slip, provide efficient torque management and deliver precise steering and toolface control while drilling the curve and/or the vertical sections—all while requiring less specific energy to remove the rock.



As producing wells mature, they commonly experience a buildup of paraffin, asphaltenes, inorganic scale and emulsions in the near-wellbore area. If left unchecked, this buildup leads to formation damage, or skin, that restricts the flow of fluids and gases. The result: decreased production, increased lifting costs and, ultimately, the unavoidable choice to shut in the well.

A series of new chemicals for near-wellbore damage (CND) from Baker Hughes offers operators a viable repair alternative without the adverse side effects caused by traditional remediation methods. The CND treatments help restore wells to a healthy, productive state by removing multiple skin damage problems with a single, time-saving treatment.

The CND remediation treatments are made from specially formulated multifunctional microemulsions with ultralow interfacial tension, high oil solubilization and high water-wetting of solid surfaces.

The CND treatments can be used in conventional and unconventional mature fields, gas storage wells, production and injection wells, and disposal wells. These products also can be combined with acids used in traditional stimulation methods to protect against common side effects such as asphaltene destabilization and rigid film emulsions.



OpenPath Sequence Diversion Stimulation Service is the first in the industry to use degradable fibers to suspend degradable multimodal particles—a combination that enables the sequential stimulation of zones and intervals to maximize near-wellbore coverage.

The service relies on composite pills that combine degradable fibers and multimodal particles. Particles alone—for example, conventional rock salt and benzoic acid diverters— are not always effective in isolating fractures of various sizes, but fibers bridge the gaps and capture the multimode particles to create impermeable temporary plugs that fully dissolve after stimulation operations are completed. Because the diversion method is chemical rather than mechanical, OpenPath Sequence service is fast, easy and effective for both cased and openhole completions.

To optimize stimulation response, OpenPath Sequence service uses the optimal acid identified for a particular reservoir to sequentially stimulate targeted zones and intervals. The service is compatible with conventional acid, engineered acid designed specifically for OpenPath Sequence service and other proprietary acid systems.

The diversion technology can withstand differential pressure up to 4,500 psi for acid fracturing or matrix stimulation treatments. No specialized equipment is required, streamlining operations and reducing HSE risks as compared with conventional chemical diversion methods.

After treatment, the proprietary blend of fibers and particles fully degrades within hours or days at downhole temperatures from 54 C to 149 C (130 F to 300 F) without further intervention.



Stuck-pipe situations have traditionally been a challenge for the oil and gas industry, causing costly interruptions, mobilization wait times and uncertain recovery attempts. As typical rescue operations can take weeks on end, downtime can cost operators $10,000 to $1 million per day, resulting in millions of dollars lost. Given the current low-oil price environment and the pressing need to improve efficiency across the industry, operators are even more determined to reduce the impacts associated with stuck pipe.

Churchill Drilling Tools’ HyPR HoleSaver cuts costs significantly by enabling operators to free stuck pipe and commence operations in a few hours instead of using traditional methods, which are lengthy, costly and unreliable.

The system consists of a robust full-strength sub, which offers exceptional strength in both tension and compression with absolutely no pre-installed weak points and is strategically positioned in the drillstring for maximum effectiveness. When a stuck-pipe situation occurs, the tool is activated by pumping down a HyPR HoleSaver dart that directs a precise and powerful milling jet at velocities more than 91 m/s (300 ft/s) to sever the HyPR HoleSaver sub. The dart takes only a few minutes to arrive, and with about two hours of pumping, the sub will part easily, simultaneously producing a perfect fish-neck for subsequent operations.



The Schlumberger PowerDrive Orbit Rotary Steerable System (RSS) was designed to make major improvements in drilling efficiency and steering precision. The objective of the design was twofold. The first was to develop a tool capable of operating in challenging environments. The second was expanding the operating window to enable drilling to total depth in a single trip. The PowerDrive Orbit RSS successfully met these objectives in both conventional and complex environments across the globe.

The noticeable visual difference with the PowerDrive Orbit RSS is the reengineered actuation pads arrayed around the bottom portion of the tool. These improve steerability by maintaining a controlled steering force in the desired direction and inclination. The metal-to-metal sealing tolerates the most complex drilling fluids and challenging hydraulics. The technology’s motorized configuration achieves and maintains rotation speeds up to 350 rpm for a better drilling performance while still maintaining directional control and consistent steerability. This represents a 59% increase in rotation speed. Additionally, six-axis roll stabilized continuous azimuth and inclination data deliver multi-axial trajectory control.

The PowerDrive Orbit RSS is programmable to follow any designed trajectory while still allowing operator adjustments in reaction to real-time measurements during drilling. The Power- Drive Orbit RSS contains its own near-bit extended range gamma ray measurements to provide additional well-positioning data for real-time decision-making.



Managing reservoir development requires precise knowledge of the formation structure. Operators use seismic surveys with their large depth of investigation to map entire fields, but such data lack vertical resolution. Seismic images can be complemented with borehole imaging logs, which have much higher resolution. However, borehole imaging is limited to mere fractions of an inch near the borehole wall.

The Baker Hughes Deep Shear Wave Imaging (DSWI) processing service helps resolve some of this ambiguity. This acoustic acquisition and processing method uses body waves generated by an acoustic dipole source to map sub-seismic faults and fractures that would otherwise be invisible with conventional borehole imaging and surface seismic techniques. The service enables operators to gain critical insight of the reservoir structure, with high-resolution images of formation features located up to 30.5 m (100 ft) away from the borehole.

The DSWI service provides an image of the reflective feature, its distance away from the borehole, its magnitude of reflection and its strike orientation. These features can then be easily integrated into the reservoir model. The processing workflow is optimized to reduce the amount of manual input for interpretation, which subsequently reduces turnaround time—in some cases, down to as little as 48 hours.

The DSWI processing relies on the XMAC F1 acoustic service. The XMAC F1 service’s dipole source operates at roughly two orders higher frequency than surface seismic. Shear waves generated by the dipole source respond to smaller scale features that are typically missed with seismic services.



Since the introduction of 3-D seismic data for hydrocarbon exploration, geoscientists have looked to create robust reservoir models from seismic. “Seismic inversion” evolved to realize this goal, but results often were unreliable.

It was realized that rock physics relationships, typically different per rock type, were not used adequately in existing methods. A collaboration between Ikon Science Ltd., Tullow Oil Plc and CSIRO successfully addressed these limitations. Using a geology-centric approach, RokDoc Ji-Fi integrates regional geological prior information in the inversion of seismic data. The result: quantitative predictions of rocks and fluids, a step change in delivered value.

Designing an algorithm that delivers both rock properties and rock type while handling seismic noise and other imperfections is complex. To best approach this, Ikon Science linked up with CSIRO to develop the mathematical and computational methods required for this new seismic inversion algorithm and partnered with Tullow Oil to sponsor, guide and test this R&D project over a two-year period on real development and production projects.

RokDoc Ji-Fi results provide better models of rock properties and rock types, minimizing subsurface risk (especially in exploration) and maximizing reward from accurately defined oil accumulations (most relevant to production and exploitation).



Multiphysics joint inversion with seismic represents one of the most promising areas of interdisciplinary investigation in geophysics, capable of providing important breakthroughs in the future for enhancing velocity discrimination in complex geology exploration and better fluid discrimination in reservoir characterization and monitoring. The Multi-Physics group of Saudi Aramco has developed joint inversion applications with electromagnetics (EM) and gravity for subsalt imaging and salt overburden velocity discrimination as well as stunning resolution in near-surface velocity model building. A range of applications was used for subsalt exploration in the Red Sea to provide high-resolution velocity mapping of the near surface through helicopter-borne transient EM (TEM) in joint inversion with seismic. The helicopter TEM seismic joint inversion results, in particular, have attracted attention from the industry players as the first EM method showing resolution comparable or superior to seismic reflectivity. The integration of the EM with seismic through joint inversion provided sharp velocity models able to enhance the seismic data and achieve higher resolution of faults and structures after depth migration. The method is particularly effective for the exploration of complex geology where seismic data are noisy and unable to provide a robust velocity model building.



In the development of remote offshore oil or gas fields with minimal or no infrastructure, an FPSO vessel is the preferred option. The FPSO unit has the advantage of providing the required storage in the hull and direct offloading to tankers of opportunity.

Steel catenary risers are the preferred option in wet-tree applications due to their simplicity, robustness and low capex and opex compared to other riser options. However, due to its relatively high dynamic motions, an FPSO unit is not a feasible host for steel catenary risers in most environments.

The sail area of the conventional ship-shaped FPSO unit in relatively harsh and multidirectional environments mandates the use of a turret system to help facilitate the mooring system design. The turret cost is normally $300 million to $700 million.

The LM-FPSO design was developed to maintain the advantages of the conventional FPSO units while offering superior motion response suitable for steel catenary risers and top-tensioned risers in very harsh environments. The shape of the LM-FPSO hull allows the use of a conventional spread-mooring system and eliminates the need for the expensive turret and swivel system and their associated opex.

As a byproduct of the motion response, the LM-FPSO offers improved process safety, helicopter operability and onboard habitability. The LM-FPSO also offers significantly improved stability, lessening its sensitivity to weight and vertical center of gravity variation. Such variations have historically been one of the highest risk elements to a project’s execution cost and schedule.



In the oil industry there is a critical need for deep interwell rock/fluid characterization with the objective to maximize production by identifying potentially bypassed hydrocarbon accumulations. This is critical in the case of fractured carbonate reservoirs and in any instance where the sweep efficiency is likely to be uneven due to heterogeneities of petrophysical properties, particularly in the permeability field.

Saudi Aramco and Schlumberger joined forces in an R&D collaboration to boost the advancements of an emerging electromagnetic (EM) technology and apply a first-of-its-kind field survey to map saturation in the interwell volumes of widely spaced horizontal wells. Crosswell EM is a technology that provides the interwell resistivity distribution applied in widely spaced horizontal wells in Saudi Arabia for mapping reservoir saturation.

This project deployed the DeepLook-EM system simultaneously in two horizontal wells using coiled tubing conveyance and established performance records for the tool measurements spacing and logging interval and recorded the first 3-D resistivity image from crosswell EM data.

Collected resistivity data are interpreted together with wellbore logs to provide interwell comprehensive reservoir water saturation with the objective to evaluate sweep efficiency and ultimately maximize oil production and recovery.



Chemical and radioactive tracers have been used for decades in the oil industry to track injected fluids as passive (to map interwell permeable paths) and active (by detecting residual oil saturation tracers). These conventional tracers have many drawbacks, including:

  • High cost (about $3,000/kg);
  • Time-consuming sample collection with high safety hazards for both collection and transportation; and
  • Lengthy laboratory analysis (about eight weeks), which often can mean loss of data integrity.

All of these drawbacks can be successfully eliminated by using Multi-Functional Nano-Tracers (MFNTs) with realtime in situ detection. These MFNTs can be “bar coded” by functionalization to 100 or more unique tracer types and can be detected in situ directly from a wellhead or from multiple tracer-injected commingled wells simultaneously. The MFNTs show low reservoir retention, are inexpensive and environmentally friendly, pose zero safety hazards, and can be detected with no sample preparation in situ in the parts per quadrillion range, making simultaneous unique tracer detection from multiple commingled wells immediate and effective. With these qualities, the MFNTs turn the above drawbacks into a highly advantageous and profitable enterprise.

Upon its completion, the MFNT project will provide a reservoir tracer revolution with respect to cost, time and efficiency. Every well in a reservoir could effectively be traced with limited cost and immediate data analysis onsite. Saudi Aramco is the first oil industry company to use nanotechnology to completely modernize the practice of oil well tracers, making it not only cost-effective but efficient, safe and easy.



Halliburton has developed the ExpressKinect manifold and the ExpressKinect wellhead connection unit (WCU), creating a step change in rigup efficiency and safety on site.

The ExpressKinect manifold incorporates a simple yet reliable design, eliminating 75% of the pumping unit connections. This drastically reduces HSE exposure, the time required for rigup and rigdown and the number of potential leak points. In addition, the system provides inherent lift assistance, reducing the lifting requirement by 77% down to just 70 lb per pump.

The ExpressKinect WCU features a single treating line, which connects to the wellhead by a hammerless hydraulic remote connector. This eliminates the need for numerous separate lines and connection points, making rigup much faster and safer and removing multiple potential leak points. This unit is rated for 100 bbl/min and 15,000 psi. The system features an integral knuckle-boom crane to easily manipulate the high-pressure manifold arm.

During multiwell operations, the ExpressKinect WCU single line manifold is efficiently swapped from one well to the next in minutes. The wellhead adapter is compatible with wireline units, eliminating the need for expensive and complex zipper manifolds. The ExpressKinect WCU eliminates more than 30 hammer connections and 10 overhead lifts for each wellhead, enabling a safer, more efficient operation at the well site. A conventional two-well 100-bbl/min stimulation job requires 170 connections, with 12 of those at an elevated height. The ExpressKinect WCU reduces the total connections to 36, with no elevated height connections.



AvantGuard Advanced Flowback Services optimize well performance from post-stimulation operations through production. Ongoing, real-time monitoring ensures the well is performing within a secure operating envelope (SOE)—protecting both the hydraulic fractures and return on investment during the lifetime of the well.

AvantGuard services are based on the application of the SOE, which is a combination of operational parameters that preserve the connection between hydraulic fractures and the wellbore. Operational parameters are defined from real-time pressure and production data, including solids production monitoring.

Damage to the well and the formation is actively prevented by tailoring a predictive flowback design strategy with a defined SOE—compared with conventional rate transient analysis used for identifying post-fracture impairment.

Changes in production rates are measured using the Vx Spectra surface multiphase flowmeter, which accurately captures multiphase flow dynamics in any flow regime for all fluid and solid types. Ongoing monitoring with real-time analysis minimizes proppant flowback and solids production.

Application of AvantGuard services for predictive flowback design during the transition to production protects and stabilizes hydraulic fractures to efficiently enable all the clusters in each zone to produce without productivity impairment.



Evolution Well Services is a pressure pumping company with a focus on hydraulic fracturing that uses 100% electrically powered process equipment. The electric power is generated by burning natural gas through a customized-for-purpose GE TM2500+ turbine system that has significant economic and environmental benefits.

The ability to use multiple fuel types such as field gas offers the highest amount of fracturing cost reduction potential.

For primary equipment, Evolution Well Services uses a blender with ambidextrous suction/discharge capability with rate capacity of up to 240 bbl/min on dual 120 bbl/min sides. The hydration unit is designed for 200-bbl capacity with compartmentalized sections for maximum mixing energy and dual gel pumps.

The chemical additive system uses low- and high-rate pumps and flowmeters for accurate monitoring and control. Fracturing pumps are mounted with dual pumps on each trailer capable of delivering up to 5,000 hhp per trailer while also offering a 40% to 50% reduced location footprint.

Strategically placed remote-controlled cameras monitor equipment and allow the removal of all personnel from high-pressure areas, exposure to chemical hazards and silica dust. With fewer needs for personnel, Evolution Well Services is able to reduce the amount of onsite personnel by 60% vs. conventional fracturing fleets.



Determining the representative composition of saturates, aromatics, resins and asphaltenes (SARA) is necessary for field development planning—from the reservoir to the wellbore to the pipeline. With many critical decisions relying on these data, it is important to determine the composition accurately the first time and every time. Even slight variances in the accuracy of SARA measurements can cause detrimental damage across the life of a field and incur significant cost and nonproductive time.

With the launch of Maze Microfluidic SARA Analysis, operators can achieve highly accurate measurements on every oil sample, across all laboratories, with a smaller environmental footprint. This new technology is powered by the oil and gas industry’s first commercial application of microfluidic chip technology, which has been accepted by ASTM International Standard D7996 as the best test procedure for measuring asphaltenes.

Conventional technology for SARA analysis is cumbersome (requiring substantial laboratory space and apparatus), time-consuming (taking nearly a week to complete) and highly dependent on technician subjectivity (causing laboratory-to-laboratory variability in the results). The process is demanding on the laboratory technical staff and equipment without providing consistent data.

Maze analysis removes the previous analytical and operational barriers, improving precision and reducing turnaround time by more than 85%.



Excessive undesired fluid production is a widespread problem that can detrimentally affect the profitability of hydrocarbon- producing reservoirs and limit their economic lives. A variety of chemical technologies have been implemented for controlling unwanted fluid production with some degree of success.

However, when these types of treatments are applied to horizontal or highly deviated wells, placement control becomes a critical factor. Depending on fluid density differences and wellbore deviation, conventional conformance treatments might slump or rise along horizontal sections, compromising the placement accuracy and overall treatment success.

EquiSeal Conformance Service is a custom sealant system designed to help control unwanted fluid production in horizontal or highly deviated wellbores. The stressdependent rheological properties of the EquiSeal service provide rapid viscosity increase during placement, allowing the treatment to remain in place until in situ crosslinking occurs at a predicted time. This helps provide a competent and precise seal across the targeted area.

EquiSeal service can be placed in the wellbore by bullheading or using a coiled tubing unit. For wellbore cleanout, the service can be washed out of the wellbore as compared to cement, which must be drilled out. The system provides a wide application temperature range and is resistant to hydrogen sulfide, CO2 and acid environments.

Once it is placed into the zone to be shut off, in situ gelation is activated by the reservoir temperature, plugging the permeability of the treated area and limiting undesired fluid flow. This system can be formulated to allow penetration into the formation matrix or to bridge off at the formation face for limited leakoff.



The GelBlock temporary annular isolation system provides a strong but temporary cement-like barrier for short-term economical isolation during enhanced hydrocarbon recovery. The barrier is produced with refracturing and recompletion operations and allows more of the reservoir to be accessed while leaving existing flow paths connected.

The water-based GelBlock system is engineered and pumped as a viscous slurry. The system uses Baker Hughes’ patented guar-based chemistry and can be applied at temperatures ranging from 52 C to 121 C (125 F to 250 F).

Setup time is engineered based on bottomhole temperature. Shortly after exposure to downhole temperatures, the slurry hardens into a solid that can be used to temporarily isolate a zone. After the refracturing operation, a fast-acting breaker dissolves the hardened material into a low-viscosity liquid that is easily circulated out with production flow.

Formation isolation and coverage is more operationally efficient and less costly than cement or mechanical means.

Unlike mechanical isolation methods, GelBlock has expandable liners. Its simplicity and lack of reliance on pipe can reduce average overall cost by at least 30% and cover longer laterals than what is currently feasible with mechanical isolation options. Additionally, less equipment on location lowers environmental footprint. Reliability and risk mitigation are improved because there is no threat of overlapping pipes or pipe gaps.

GelBlock’s temporary isolation allows access to new and existing zones of the reservoir for increased ultimate recovery. Its flexibility also makes it a key component, with other Baker Hughes refracturing technologies, of valuable integrated solutions.



Halliburton’s Endurance Hydraulic Screen offers an alternative to traditional methods of compliant sand control such as gravel packing and mechanically expanded screens.

With the Endurance Hydraulic Screen, openhole compliant sand control has been achieved using hydraulic technology, which is activated by surface-applied pressure that takes no more than one hour of rig time. The screen enables operators the opportunity to complete sand-plagued wells more efficiently by reducing completion time, complexity, cost and risk compared to traditional methods.

When compared to expandable sand screen systems, hydraulic activation achieves wellbore compliance without the need for an expansion trip to mechanically yield the screen basepipe. A reservoir isolation barrier also can be run in the same trip when expandable sand screens require an additional intermediate completion trip.

The Endurance Hydraulic Screens are manufactured with industry standard solid tubular basepipe, retaining the original geometry and strength after the screen filter media is activated against the borehole. This helps provide the capability to withstand high depletion and geomechanical loading scenarios.

Early deployments have proven single-trip capability and integration of standard equipment, including openhole isolation packers and reservoir isolation barriers. The basepipe geometry is unaffected post-activation and is well-equipped to accommodate reservoir inflow and management using intelligent completion equipment.



Stricter BOP testing protocols promise to help detect potential problems before they present a danger to rig workers or the environment. However, depending on the depth of a well, BOP testing takes on average between 24 and 60 hours each time the test is conducted. That means that every 14 days a rig experiences two days or more of idle time while the operator continues to pay the daily rental rates for equipment and crews. Those fees can run into the thousands of dollars if not hundreds of thousands of dollars, every day.

Nearly two years ago, R&D company Samoco Oil Tools partnered with a major in the offshore industry to create a tool designed to cut tripping time in half during BOP testing. The result was the OneTrip BOP testing tool.

OneTrip’s cost is comparable to competitors’ BOP testing tools, and the low-torque, high-pressure design ensures a resilient downhole seal that can withstand the harshest subsea conditions. OneTrip is designed and validated to withstand 25,000 psi and is verified to sustain a load up to 1.2 million pounds. In addition, OneTrip’s technology allows the tool to remain downhole until BOP test results are confirmed satisfactory, and if for any reason initial results are not satisfactory, the tool is positioned to immediately retest the BOP.



High-density polyethylene (HDPE) pipe’s low cost, ease of installation and resistance to corrosion and decay makes it an ideal choice in the installation of aboveground field production as well as buried distribution systems. Fusion has long been the standard joining method for HDPE pipe, but Victaulic’s new Refuse-to-Fuse HDPE Joining System for plain end and grooved HDPE pipe is designed to provide a faster, simpler joining method for HDPE without sacrificing performance.

This newly engineered HDPE joining system eliminates the need for fusing, helping reduce labor costs and schedule times. There’s no equipment setup or prep time, which eliminates the need for costly equipment rentals and additional power costs, and joint completion time doesn’t depend on atmospheric conditions such as rain or freezing. Visual verification of a successful joint can be made, and the couplings also meet or exceed the performance capabilities of HDPE pipe, including working pressure, end pull load specifications and minimum bend radius requirements. This means the pipe can be pushed, dragged and subjected to temperature and pressure swings without concerns that the joints will disengage. The couplings also can be easily installed in vertical orientations as well as in tight spaces and reused from site to site, which is ideal for hydraulic fracturing wastewater treatment systems in shale pad drilling.