The E&P editors and staff proudly present the 22 winners of the 2022 Special Meritorious Awards for Engineering Innovation (MEAs), which recognize service and operating companies for excellence and achievement in every segment of the upstream petroleum industry. The following technology showcase highlights the winners.
SpeedFreq, Extract Companies
The SpeedFreq artificial lift production tool is Extract Cos.’ answer to operators and service companies looking for
efficient and cost-effective ways to adapt electric submersible pumps (ESP)—a tool originally intended for conventional secondary recovery—to meet the requirements of the unconventional reservoir.
SpeedFreq is the first ultra-high-speed, permanent-magnet-motor-powered ESP system designed specifically for unconventional production. Capable of delivering up to 400 hp at 10,000 rpm in less than a 4-in. OD package, SpeedFreq delivers higher production rates than induction systems in 5.5-in. 20# and 23# wells while consuming less power.
SpeedFreq’s number one benefit to operators is to accelerate reserves and help them realize greater year one production than they otherwise would with an induction ESP system. Additionally, by using a permanent magnet motor, SpeedFreq operates extremely efficiently, resulting in power savings that range from 20% to 35%. A Midland Basin operator experienced this firsthand, after installing the system and realizing production that outpaced every other well on the pad by at least 2x, and in most cases 3-4x. Moreover, Extract successfully quantified power savings of 35% versus induction for the operator.
SpeedFreq is a unique and disruptive technology that has captured the attention of major oil companies and large independents. It has repeatedly demonstrated an ability to accelerate reserves and show differential production performance versus typical induction ESPs. Moreover, operators view SpeedFreq as an opportunity to show tangible evidence of reducing the carbon intensity of existing production. With power consumption savings of 35% and steel/alloy footprint reduction of roughly 75% versus a typical ESP, operators can quantify the benefit for ESG reporting.
Sucker Rod Sensor, Well Innovation AS
The Sucker Rod Sensor is a downhole sensor designed by Well Innovation AS to provide a modernized and efficient method to troubleshoot rod lift system failures, replacing outdated and expensive methods that use conventional surface measurement with downhole prediction methods developed in the 1990’s for shallow vertical wells.
The Sucker Rod Sensor system provides direct measurements, enabling operators to implement a systemic engineering approach to troubleshooting problems under downhole conditions. These sensors, when placed in strategic locations throughout the rod string, measure the downhole force with the magnitude of detail required to identify and troubleshoot downhole problems that cause rod, tubing and pump failures. The system allows operators to see what is working, and what is not, in order to improve mean time between failure while optimizing production and eliminating unnecessary costs.
The Sucker Rod Sensor system can be positioned anywhere in the rod string. It collects 10 Hz measured data or 10 measurements per second for the following: pressure, temperature, torque, tension and compression and velocity and position for the 3-axis accelerometers. It is memory based with up to 400 hours of 10-Hz recordable data. It is preprogramed prior to going into the well with the ability to turn on and off to extend the number of days the tool is recording data.
The measurements provided through this system generate a “measured” Dynacard, in comparison to the conventional wave equation Dynacard. These measured cards show details about the well that are not being captured with today’s predicted models.
The current tool has a temperature rating of 135 C/275 F with a 34 MPA/5,000 psi differential pressure rating. The tensile rating is 25,000 KG/55,000 lbs. The future plan is to develop the real-time version of the Sucker Rod Sensor so that it can be fed directly into the pump-off controller.
ecoView, Kodiak Gas Services
The ecoView system from Kodiak Gas Services is a greenhouse gas emissions and real-time operations monitoring system designed to help the oil and gas industry achieve its ESG goals, as well as comply with new regulatory requirements.
The ecoView system leverages innovative software and hardware from Legend Energy Advisors, a leading provider of real-time data analytics, to provide comprehensive views of operational data. The system offers operators and technicians unprecedented access to real-time data monitoring, drastically increasing the accuracy of greenhouse gas level data. As the industry’s focus turns towards ESG initiatives, the ecoView system eliminates guesswork and improves data accuracy when reporting greenhouse gas levels.
The ecoView system will enable Kodiak to make truly predictive maintenance a reality through future partnerships with machine learning companies, driving down costs, improving operational efficiencies and minimizing the equipment's environmental impact by reducing unplanned downtime incidents.
Kodiak plans to enhance the capabilities of ecoView by adding the ability to track leaks and other sources of greenhouse gas emissions, continuing Kodiak’s efforts to realize a future where ESG goals and financial success are synonymous.
PowerDrive Orbit G2 rotary steerable system, Schlumberger
PowerDrive Orbit G2 rotary steerable system (RSS) is a system within Schlumberger’s Transition Technology portfolio that helps customers reduce the environmental impact of their drilling operations, supporting E&P decarbonization goals by reducing CO2 during the well construction process. Like the entire Transition Technologies portfolio, its sustainability benefits are transparently quantified and aligned to the United Nations Sustainable Development Goals.
The PowerDrive Orbit G2 RSS reduces drilling time and the associated rig emissions, reducing energy consumption and emissions to minimize the well construction CO2 footprint with its ability to steer at high bottom-hole assembly rotation—350 rpm. An innovative pad design increases abrasion resistance with metal-to-metal sealing to handle aggressive drilling fluids and severe downhole conditions for longer runs—and it features a higher dogleg severity capability for rather assertive curve sections. With dual downlink options, including a continuous-circulation downlink, it fulfills all commands from the surface for any rig type, enables real-time decision making and provides excellent directional control.
The PowerDrive Orbit G2 RSS also features a self-steering autonomous capability that smooths out trajectories with minimized tortuosity. Additionally, PowerDrive Orbit G2 RSS incorporates a continuous auto-tangent capability that, together with closed-loop automation, optimizes well placement and trajectory control for smoother tangents. Early identification of zones of interest is provided by its extended gamma ray measurement. Enhanced durability for severe downhole conditions helps provide extra reliability in complex operations where stick/slip, severe shock and torque and complex hydraulic systems are significant risks. PowerDrive Orbit G2 RSS delivers higher ROP and can drill from shoe to total depth in a single run, reducing operating days, thus reducing emissions and impact.
IPA – Integrated Production Automation, ABB – ENOVATE
ABB-Enovate’s Integrated Production Automation (IPA) is a cloud native digital environment presented as digital twin configuration and optimized with artificial intelligence to empower energy providers with prescriptive decisions.
IPA’s digital twin architecture connects subsurface modeling with surface measurements for real-time validation and operational optimization windows. The program is comprised of an ultra-fast numerical simulator and a data-driven wellbore hydraulics module to simulate multi-factor, multi-scenario potential outcomes. IPA is connected to the surface production data/measurements for a fully automated end-to-end system that provides customers with the ability to avoid time consuming processes via excel for data correlation and operational understanding.
The holistic integrated view of the system enables on-the-fly optimization decision-making and drives opportunity for autonomous operations and closed loop automation. In the field, an operator achieved 40% operational time reduction to evaluate the operational conditions for the design of the depletion program and surface facility logistics. The operator validated the advanced optimization algorithm that IPA uses to calibrate models in real time and avoid data transfer from different software packages via excel. The forecast models were calibrated in real time with no human inputs and initial uncertainties were reduced as the model was fed with the production data, leading to a compressive and accurate flow rates and EUR prediction.
Reservoir management practices will evolve with IPA as the industry works towards autonomous automation and low carbon energy. The digital architecture behind IPA is customized for carbon storage and geothermal operations.
inVision Digital Valve Control, Intelligent Wellhead Systems
Intelligent Wellhead Systems’ inVision®Digital Valve Control™ technology helps mitigate the risk and improve the efficiency of hydraulic fracturing, wireline and pressure control operations. The technology integrates a wide variety of sensors, engineered safety controls and best practices to remotely operate accumulator valves using digitally enhanced standard operating procedures. With this approach to remotely operating accumulator valves, up to 24 wellhead valves can be opened or closed across multiple wells to reduce the risk of human error that can cause catastrophic failures that lead to loss of life, injury and equipment damage.
The inVision® TechnologyPlatform has helped achieve more than 50,000 incident-free stages on 1000 completions in Canada and the U.S. The latest innovation to the platform,inVision® Digital Valve Control™ technology, was introduced in February 2022 and implemented by Aethon Energy in their Haynesville wells. The new technology has continued to achieve a zero-incident performance track record with Aethon, experiencing zero cut wirelines, zero well shut-ins, zero pressure control incidents and zero injuries to date. With inVision Digital Valve Control Technology, wellsite personnel no longer must manually open or close accumulator valves. Frac, wireline, pressure control and Aethon stakeholders can now visualize wellhead valve status and control valve readiness for frac fluids or wireline tools going into and out of the well on handheld inVisionSIMOPS tablets. Safety situational awareness of operations is improved and continuous improvement in well swap and pumping times can now be enabled. inVision Digital Valve Control™ technology is helping demonstrate that digital technologies play a vital role in reducing risk in hazardous operations because humans cannot be situationally aware 100% of the time.
RigER, RigER Inc.
RigER is an operation management software for oilfield service and rental companies. From first client call to final invoice, RigER’s software deals with sales, operations, price management, field operations, maintenance, asset management, safety, invoicing and billing all in one place. As both price and volume of work continues to increase, it is essential that oilfield service companies find ways to run their companies smarter and with less people.
RigER provides an alternative to overworking a limited staff or getting stuck in the cycle of hiring and letting people go. Putting everything together into the RigER cloud-based software gives enterprises an easy way to streamline and optimize operations across multiple locations. RigER allows companies to extract precise data in real-time, letting them achieve genuine transparency as to the status of any given operation. It provides both online and offline consolidated real-time information related to job cost, daily profit and loss statements, accurate projections, days sales outstanding (DSO) reports, dynamic position operators, asset utilizations, employee turnover, HSEQ, ESG and all of the ways these impact the balance sheet. As the data is collected over time, the system is able to make formulaic projections that allow companies to pivot towards solutions before the problems even arise. Electronic invoicing and ticketing can shave weeks and even months off a company’s DSO while eliminating the need for increased staff as activity increases.
Faced with the challenge of collecting data surrounding costs, many companies report they’re unable to capture the data before it’s too late to do anything to correct and improve. RigER enables companies to funnel everything to a job seamlessly and get accurate and real-time job costing without needing any additional administrative staff.
New Horizon to Downhole Scale Management for Sustaining Wells' Productivity, Saudi Aramco
Saudi Aramco controls sulfate reducing bacteria (SRB) count in oil fields and facilities with biocide injections, which helps to reverse the souring phenomenon and regulate H2S levels. As a result, the scale precipitation associated with H2S interaction was confined to a few occurrences in the field. The formation of the downhole scale has resulted in several adverse effects including loss of production, jeopardizing wellbore accessibility and causing premature ESP failure.
To combat observed iron sulfide scales, Saudi Aramco developed a unique technique utilizing the Scale Switch formula. This newly developed chemical treatment employs specific chelating chemicals that can break the bond structure of these hard scales, allowing them to be washed away with post-flush fluid. Furthermore, as compared to previously used treatments, this formula has a high pH, which prevents H2S gas release and scale re-precipitation.
Saudi Aramco performed extensive laboratory testing to evaluate the efficiency of this suggested recipe prior to field task execution. Using this newly created formula, four wells were chosen for de-scaling procedures. The operations were completed with a 2.0" CT and a high-pressure jetting tool for increased pumping capacity. As a result, the cost of a workover rig to remove such difficult scale deposits was avoided, ESP integrity was preserved, wellbore accessibility was restored and 4% of crude was unlocked.
The implementation of the Scale Switch formula has realized the following results in the field: unlocked 4% of available crude in the field; the requirement for costly workover operations to replace the ESP was eliminated; restored wellbore accessibility and facilitated conducting subsequent logging; avoided resorting to corrosive scale removal that negatively impacts the sweet nature of the reservoir.
TETRA Advanced Displacement System (TADS), TETRA Technologies
The TETRA Advanced Displacement System (TADS) by TETRA Technologies is a 3-phase drilling-fluid displacement system designed for optimal wellbore cleanout. Engineered to remove solids and render all metal surfaces water-wet, the system is designed for direct and indirect displacement of water-based, diesel-oil-based and synthetic-oil-based drilling fluids. Depending on the application, the TADS is a tailored blend of low- or high-density halide brines and TETRAClean 900-series chemicals.
Fluid displacement systems have been used for decades to remove oil and water-based drilling muds and replace them with solids-free completion fluids. Over the past few years the industry has shifted from water- and oil-based drilling fluid systems to synthetic-based systems. Additionally, advances in drilling, completion, and production technologies for ultra-deepwater operations have brought new challenges for clear-brine displacement systems. TADS was developed to meet these challenges.
TADS is engineered as a conventional or hydraulically balanced system that provides direct displacement of zinc-based and zinc-free completions fluids. It yields cleanout of tubular components with minimal fluid interface, leaving metal surfaces water-wet while enhancing filtration and solids removal—all without exceeding equivalent circulating density or rig pump limits.
TADS is custom-formulated for the specific well conditions using a variety of carefully engineered, innovative cleaning, wetting and flocculating agents. It works with a wide range of mud and brine systems. Yielding cleanup efficiency of 98% or greater with a much smaller concentration of chemical additives (3?4% vs. 7–8%), the system removes wellbore solids, enhancing filtration quality and extending diatomaceous-earth filtration cycles.
TADS is customizable to yield optimal results in diverse applications, reduces waste and contamination and reduces rig time and costs. Given the environmental restrictions on completion fluids and the need for reliable products in deepwater environments, TADS represents a game-changing technological breakthrough.
iCruise X™ Intelligent Rotary Steerable System, Halliburton
Halliburton’s iCruise X™ intelligent rotary steerable system (RSS) platform is targeted at longer, harsher applications to deliver precise well placement and reduced well time.
Halliburton built the RSS around a robust mechanical design and the latest metallurgy with higher strength materials and new connections for optimal performance in geologically complex wells, high-temperature environments or in applications with variable drilling fluid conditions.
The RSS has a new steering head design that optimizes flow paths to minimize the impact of high frequency torsional oscillations. The sealing system has been changed to advanced metal-to-metal seals to withstand higher internal pressures, deliver more force for the same pressure and increase tolerance to varying drilling fluid parameters. The extra force available for steering delivers curves faster and provides a stiffer assembly for straight well sections.
Halliburton has mobilized the iCruise X™ RSS in the Middle East where it solves some of the most complex drilling challenges. In one case, an operator needed to drill a curve section through tough interbedded formations while maximizing the ROP. The RSS was mobilized to drill two curve sections in an 8 3/8” hole. Both curves were records for the area with the second drilling a total footage of 2,600 feet in 79 hours with an average ROP 65% higher than the authority for expenditure (AFE) expectation. This curve beat the AFE time by more than 50% and was a record for the area, beating the previous record by 30%. Both curves were drilled shoe to shoe, delivering a smooth well bore to the operator with no damage to the drilling assembly.
Wellgrab ERFT, Welltec
Wellgrab™ ERFT is a fully surface-controllable electric release fishing tool. Introduced to Welltec’s intervention portfolio in 2021, the solution incorporates a Well Stroker® to deliver up to 100,000 lbs. of force, as well as provide digital, real-time communication with the fishing tool. Wellgrab ERFT facilitates an informed method of conducting fishing operations that would otherwise be carried out somewhat blind, with operators relying upon the experience of the crew and low-level feedback provided by the tools in use.
Wellgrab ERFT is designed to improve and simplify fishing operations, providing a reliable disconnect of fishing strings and the ability to relocate the fish in the well. The required grapple type, either external or internal, can be easily assembled on the tool by only changing a few parts. This provides operators with the ability to latch, release and then re-engage without the need to trip out of hole to reset the tool. Keys or slips on the tool can be retracted to aid in engaging on or into a catch profile. Electrical disconnect can be activated at any time when required.
The Wellgrab ERFT was developed by Autentik in close collaboration with Welltec, combining technologies from each company to create a unique value offering and opening up a new dimension to downhole fishing on electric wireline. By having access to a lightweight and easily deployed fishing solution with high-level accuracy and high force capability, operators can derive significant time and cost benefits by minimizing the impact of downhole fish on planned operations and avoiding unnecessary non-productive time.
Workover Rig Inspection, Chesapeake Energy Corp.
Chesapeake is driven to prevent high potential incidents from occurring within their program and have engaged in a process looking at industry best management practices, standards and implemented software to provide the boots on the ground with the ability to review and understand these requirements in the field.
Using new software, Chesapeake was able to break down workover operations into sections and allow their team (operations, HSE, and vendors) the ability to complete inspections from their mobile devices. In addition to mobile functionality, the new resource and process allowed them to gather this data, identify trends, and communicate to all levels of the business.
Team member buy-in and ownership with operations and vendors helped to make the roll out of this software a success for Chesapeake. Their HSE team was able to coordinate work with all parties understanding and in alignment on what the end goal was: everyone going home safe and reducing incidents.
The checklist is on a mobile platform that can be accessed offline. It breaks down the workover operations into 17 different inspections. The software enables operators to send these inspections to all necessary parties, allowing the team to better communicate from one rig to the next. Additionally, action items can be assigned within the inspections to ensure the deficiencies are corrected.
This program has allowed Chesapeake to reduce their high potential incidents in a short amount of time through clear communication and outlining expectations on all levels.
Oxy’s Audio, Visual, Olfactory Inspection and Detection (AVOID) device is a remote emissions detection option designed to improve environmental and operational surveillance while optimizing field technicians’ time. This engineered, cost-effective technology addresses unique surveillance issues found in low-producing wells and their facilities, especially in remote locations.
Production technicians historically have been the main component of onsite surveillance, relying on their senses of smell, sight and hearing to survey the location, but they are only on a respective location for a short period of time. The AVOID monitor performs some of the same functions as a technician but is on location 24/7, enhancing surveillance. AVOID captures and transmits pictures (or video), audio files and methane readings over a cellular connection or through existing field communication infrastructure.
When AVOID detects a deviation or abnormal condition, personnel are dispatched to the location to address the issue.
AVOID is uniquely capable of detecting an emission event in three distinct ways: audio, images and multiple point-based methane sensors deployed throughout the location that record methane readings. With multiple sensors, leaks are identified quickly, autonomously and effectively.
AVOID has the potential to reduce emissions through early or timely detection of a spill or leak. It is engineered to have very low maintenance costs and has demonstrated high reliability through extended field tests in various weather conditions. AVOID development began in late Q1 of 2021. Initially, it tried to answer the question, “Can methane be economically detected?” By developing a low-cost, reliable solution, AVOID hopes to answer that question by improving field technicians’ productivity and further reducing emissions.
HYDRAULIC FRACTURING/PRESSURE PUMPING:
Titan Natural Gas-Powered Direct Drive Turbine Hydraulic Fracturing Technology, BJ Energy Solutions
The key component of the BJ Energy Solutions’ TITAN® direct drive turbine technology is its 5,000 hp dual shaft direct-drive natural gas-fired turbines that are capable of delivering one of the most efficient power to pump combinations available. The technology was developed to support the industry’s transition into low carbon practices while maintaining operational efficiency and economics.
Fueled by natural gas, the TITAN supports the reduction of greenhouse gas emissions, reduced costs, improved mobility and reliable operations while meeting the most stringent noise reduction requirements across North America. TITAN enables a wide variety of fuel options including field gas, LNG, CNG and even diesel when gas options are not available.
The TITAN’s power train consists of a highly versatile turbine and a robust single speed reduction gear box which connects to a 5,000 hp continuous duty power end to deliver fracturing fluid and materials to the reservoir. Such arrangement provides TITAN with the highest efficiency in mechanical to hydraulic horsepower transfer resulting in lower fuel consumption and greenhouse gas emissions.
In a four-basin emission study which included Haynesville, the Permian, Eagle Ford and Montney/Duvernay, TITAN demonstrated some of the best greenhouse gas emission profiles, based on testing results from a EPA certified third-party laboratory on a commercial unit. This despite the negative impacts of higher temperatures and altitudes as in the Permian. The average reduction in emission ranged from 8% to 40%.
ONEplug™, Lonestar Completion Tools
The Lonestar Completion Tools’ ONEplug™ is the only frac plug on the market made from one continuous piece of material. Innovative manufacturing techniques allow Lonestar to machine their plug from one tube so that the cone, slips and gage/setting ring are integrally fastened to the main body of the plug. This combats costly operator downtime often caused with traditional frac plugs that consist of separate components that can move, become loose or break during deployment.
Since ONEplug™ is only one piece or component, the external components cannot move or break and do not become separate functional components until the setting operation commences and each discrete component is sheared away from the main plug body. It is this feature along with the bottom set design that eliminates issues associated with sticking or presetting of plugs during deployment. Bottom set plugs typically fasten to the setting tool at the lower most gage/setting ring of the plug. This allows any impact or casing contact with the plug to be transferred directly into the setting tool, further eliminating the risk of sticking or presetting.
In addition to deployment risk mitigation, the ONEplug™ design also delivers overall savings on raw materials, pump down fluids and machining hours. The compact one-piece design uses up to 40% less composite material than standard plugs, which directly correlates to less time for machining and assembly. This also allows for a smaller and more compact wireline adapter kit (WLAK), resulting in a reduced amount of steel needed to adapt to the wireline setting tool. All of this adds up to a lighter plug and WLAK, allowing the operator to pump down faster and more efficiently.
SPM™ Simplified Frac Iron System, SPM Oil & Gas, a Caterpillar Company
The new, more streamlined SPM™ Simplified Frac Iron System is an important advance for hydraulic fracturing. The reimagined, field-proven Simplified Frac Iron System transforms the typically disjointed process inherent with conventional ground iron.
Traditional frac operations involve hundreds of moving parts and small-bore iron strings to manage extremely high pressures. Such a complex arrangement creates substantial nonproductive time (NPT) due to lengthy set up, assembly and connection requirements. Additionally, every connection represents a potential leak path and must be checked continuously.
SPM Oil & Gas was a pioneer of the simplified frac iron concept and its innovative, continuously evolving design has proven superior in the field. The newly enhanced SPM Simplified Frac Iron System radically reduces the footprint and amount of iron required for fracing operations, ultimately increasing frac site operational efficiency. This results in fewer lines, connections and components—in addition to fewer potential leak paths and less NPT.
In the field, an operator in the Eagle Ford Shale sought to significantly reduce the associated time and cost of maintaining the complex maze of multiple iron strings and numerous twists, turns and connections of their traditional frac site. The company implemented the SPM Simplified Frac Iron System to reduce costs and NPT. With the system, rig-up only required two to three employees working three to four hours—versus the 10 to 12 employees working eight to 12 hours—achieving significant efficiencies in time and costs while creating a safer work environment.
After running more than a year with around a billion pounds of sand going through it, the SPM Simplified Frac Iron System only required routine maintenance.
Expansion Charge Technology, W. T. Bell International
W.T. Bell International’s Expansion Charge Technology can stop seepages behind casing for permanent well repair by expanding pipe and densifying cement.
Sealing leaks without squeeze jobs or section milling is accomplished with this innovative technology in onshore or offshore, low- or high-value wells. Specialized explosive charges deploy into the wellbore with or without a rig on wireling-, CT- or slickline-conveyed tools. Operations last less than two days by repairing leakages through small channels in the cement or micro-annuli by plastically deforming the casing and densifying the cement, sealing off leak paths.
Pipe expansion across multiple annuli can be achieved without rupture because explosive loads required for pipe expansion are tested prior to the job at WTBI’s Performance Test Center. Expansion Charge Technology expands 3.5- to 7-inch pipe with a shaped charge tool and 7.625- to 20-inch pipe with a Duel End Fired (DEF) tool and is compatible with small running clearances and ID restrictions.
With over 150 successful expansion tests in the lab and over 90 well applications verified by multifinger caliper measurements, Expansion Charges are proven to achieve maximum expansion of pipe without rupture to remediate annulus leaks in plug-and-abandonment or live well operations. No restrictions, obstructions or leak paths are introduced by the expansion, allowing full wellbore access post intervention.
The efficient rigless operation remediates annulus leaks in two days or less and reduces costs up to 82% with less greenhouse gas emissions. Extensive lab testing and application in two wells demonstrate that DEF Expansion Charge technology can reliably expand up to 21-inch long sections of pipe to seal leaks.
WireFLATE, Well Robotic
The Well Robotic WireFLATE® inflatable setting system represents the first wireline setting system for inflatables, demonstrating the performance and reliability required to position wireline as the preferred deployment method for inflatable setting. This reliability is achieved by overcoming issues around tolerance to wellbore gas and debris, ease-of-use, rapid onsite maintenance and reconfiguration.
The system may be run in two modes: well-fluid mode and reservoir mode. Simple operation and push-button control enable the operator to monitor the inflation process in real?time and confirm proper and successful deployment of the inflatable plug. In well-fluid mode, the system is deployed in the wellbore and intakes the wellbore fluid as the inflation fluid which is provided to the inflatable.
A key distinguishing feature from previously existing technology is the ability for the WireFLATE® to self-prime and self-vent. No priming is required prior to deployment. The system has the ability to vent the gas and continue the operation when encountering wellbore gas, drastically increasing reliability over existing systems. It is significantly debris resistant, with the option to run it in reservoir mode in extremely debris-ridden or fully dry gas wells.
Traditional setting tool fluid-carry reservoir systems are cumbersome to handle, require through-wiring and in all cases, effectively increase the diameter of the tool string. The WireFLATE® fluid carry reservoirs are tool sections filled with fresh water at surface prior to deployment and positioned in the tool string below the setting tool and above the inflatable—the first of its kind.
Previous technology requires significant redress after each run-in hole. The WireFLATE® requires none, and may be immediately re-run in the wellbore for successive and multiple runs as demonstrated operationally.
Historical assumptions in the industry have held that proppant and fluid flow uniformly through wells, however GEODynamics®’ primary research utilizing surface tests with six U.S.-based operators demonstrates this is untrue and can negatively impact well stimulation. Based on these findings, GEODynamics® developed StageCoach™, a data analytics modeling solution, to address this challenge and accurately model proppant transport, distribution and erosion across clusters. StageCoach™ accurately models proppant transport, distribution and erosion across clusters. This allows operators to be more deliberate when selecting hole size and/or charge type, enabling them to achieve the assumed distribution without cost variances. It also empowers operators with the foresight to know when and where to invest to maximize returns.
The StageCoach™ analytics package integrates computational fluid dynamics modeling of proppant slurry movement with full-scale proppant transport surface test results into an engineering model that optimizes job parameters to ensure more uniform proppant distribution from cluster to cluster. As the model provides accurate data rooted in facts rather than interpretation, frac designs are more robust and reliable, preventing the superclusters that can cause well-to-well contact.
The StageCoach™ model accurately predicted how proppant and fluid will flow through wells to measurably improve well productivity by 10-15%. Such insights have the potential to dramatically improve overall frac design and well productivity.
The model not only accounts for a host of factors such as pump schedules, proppant loading, charge selection, perf spacing and phasing and stress shadowing, but also provides access to GEODynamics®’ strategic projects team of leading industry technical advisors with more than 150 years of perforation and frac design experience combined to coach companies to achieve optimal stage design.
Subsea Live data-driven performance service, OneSubsea®, a Schlumberger Company
OneSubsea® redefines subsea asset performance with data-driven actionable insights through their Subsea Live data-driven performance service, bringing new speed and certainty to decision making. By integrating original equipment manufacturer expertise with automation, physics-based simulation and artificial intelligence to extract actionable insights in a secure, collaborative digital solution, Subsea Live service enables operators to transition from reactive to proactive operations and to optimize asset performance.
As offshore oil and gas targets and their development rapidly become more complex, operators are pressured to reduce costs and produce hydrocarbons more sustainably. These challenges can be met by efficiently making early decisions, but the typical low-tech reactive approach that is not fully informed by contextual data analysis prevents that. The secure, collaborative digital solution provided by Subsea Live service extracts the full value of the data to deliver actionable insights for equipment health, operational performance and production optimization across their subsea asset.
Subsea Live service continuously analyzes performance data from subsea meters, boosting and compression systems, production systems and risers and flowlines in real time. This automated process begins with setting a historical data baseline, which is of value whether equipment is performing effectively and efficiently or not. Moving forward from the baseline with subsequent real-time data, Subsea Live service fully accounts for the dynamic nature of production, in which gas/water/oil proportions are always in flux.
The complex picture of what’s happening in real time is coherently and inclusively resolved by Subsea Live service. As operators use Subsea Live service to optimize their subsea asset performance across equipment, system and field levels, they not only maximize operational uptime but also control costs.
PARETO – DOE’s Produced Water Optimization Program, DOE's National Energy Technology Laboratory and Lawrence Berkeley National Laboratory
PARETO is an optimization framework for onshore produced water management that is meant to empower practitioners, researchers and policymakers to identify cost-effective and environmentally sustainable ways to manage, treat and beneficially reuse, when possible, produced water from oil and gas operations. Given user-provided water production, demand and transportation data, PARETO can help determine where and how to build out produced water infrastructure while simultaneously improving the coordination of water deliveries over time. The framework is innately designed to help organizations recognize opportunities for minimizing fresh and brackish water consumption by maximizing produced water reuse in active oil and gas development areas.
In 2021, the U.S. Department of Energy (DOE) launched PARETO to encourage energy companies to leverage optimization technology for produced water management practices. The program can help the oil and gas industry and other industries such as agriculture or mining and regulatory agencies make better and faster decisions.
PARETO is an optimization-based decision-support application that can provide users with specific and actionable recommendations on subjects to include: where to build water pipelines and how to size them; how produced water deliveries should be coordinated; which treatment technologies to select; which beneficial reuse options to consider; and how to distribute treated produced water and/or concentrated brine to end users. It can also able to provide insight regarding environmental concerns.
PARETO is a free and open-source software tool that is meant to become a trusted and value-adding decision-support platform for the entire produced water community. It is Python-based and is publicly available via GitHub.
FloBoost, Locus Bio-Energy Solutions
Locus Bio-Energy Solutions has developed a range of biosurfactant-based saltwater disposal (SWD) management additives that outperform traditional injectivity aids to reduce costs and increase efficiency of SWD wells. FloBoost additives can address the biggest SWD challenges that come with the growing industry’s need to store more and more saltwater in fewer SWDs.
Maximum allowable injection pressure in SWD wells is generally regulated. Typically, SWD operators are injecting at pressures at or near these limits. Produced saltwater contains solids like iron and other scales, organic matter, paraffin and asphaltenes that build up on the reservoir rock surface or precipitate in the wellbore. The buildup or precipitation of these solids reduce water flow and may cause increased injection pressure and reduced injection volumes.
FloBoost injectivity aids address this by keeping these solids dispersed and suspended in the water. The additives increase flow through the formation by reducing interfacial tension and surface tension, ensuring maximum injection volumes to be achieved for a given maximum allowable injection pressure. Reducing injection pressure minimizes power required to operate injection pumps, offering significant savings to SWD operators.
In addition to reducing the solid deposition, FloBoost can dissolve and penetrate existing filter cakes, and increase effective permeability through these deposits—increasing the injection rates.
Finally, by combining surface tension reduction, interfacial tension reduction and water wetting the rock surface, FloBoost additives reduce capillary pressure, alter wettability and promote water flow into the pore space, resulting in deeper penetration into the rock, reducing injection pressures and maximizing injection volumes.
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