Oil & Gas Technology Trends to Look For in 2015

Technology has and will continue to transform the oil and gas industry in 2015.

U.S. unconventional oil and gas activity, which has transformed the United States into a potential liquefied natural gas exporter and a significant oil producer, has been made possible by innovations in hydraulic fracturing and horizontal drilling technology.

The oil and gas industry has faced a learning curve in terms of how to best produce shale oil and gas. The technology and learning curve effects that the operators, service providers and drilling contractors have put in place have achieved has substantially improved the breakeven point of shale plays, said Vance Scott, partner and leader of the Americas energy practice at global management and strategy consulting firm A.T. Kearney.

Technological advances have improved the breakeven economics on wells for both shale oil and gas wells, to the point where some companies are able to drill economic dry gas wells with break-even prices of between $2 and $2.50/Mcf. The economics have improved due to operators making better decisions on fluid choices, rigs and pressure pumping.

"It's not so much a single point technology as it is the integration of technologies and how they bring those together."

In 2015, more emphasis will be placed on technologies that reduce cost and improve efficiencies, Bill Kroger, co-chair of law firm Baker Botts' Energy Litigation Practice Group, and Jeremy Kennedy, partner in the firm's Global Projects Practice, told Rigzone.

"Energy technology companies may need to lower their prices in response to a drop in demand, which will offset some of the price declines in crude oil," Kroger and Kennedy told Rigzone. "The technology companies with strong balance sheets may see crude price declines as an opportunity to acquire companies and technologies at discounted prices."

In the exploration and production area, some parties may adopt a "wait and see" attitude in respect of some of these more expensive to develop shale plays. With well costs above $10 million in some plays, the desired rates of return are difficult for some higher-cost producers to achieve at current oil prices.

"For this reason, we may see CAPEX [capital expenditures] begin to decline until there is some stability with oil prices," said Kroger and Kennedy. "However, that will be offset somewhat by the fact that many areas have a current backlog in completed wells, and we are seeing completion (in respect of previously drilled wells) continue. We would expect that such completions will continue to help maintain cash flows."

A major focus of unconventional drilling now and in 2015 is the accuracy of where well laterals are being placed, R.T. Dukes, upstream analyst at Wood Mackenzie, told Rigzone. Measurement-while-drilling and logging-while-drilling tools are allowing oil and gas operators to better pinpoint where to place laterals – in some cases, 50 feet can make a huge difference. In plays such as the Delaware Basin in West Texas, this accuracy can make the difference between a well having a five percent return or a 40 percent return. This accuracy also is allowing companies to maximize resources in the upper and lower bench of the Eagle Ford shale play.

Technology is playing a significant role in drilling efficiency, especially in a sensitive price environment, Dukes noted. In 2015, the manufacturing approach to shale plays will evolve to a customization approach as operators seek to improve the performance of individual wells. In 2014, completion activity focused around bigger fractures. In 2015, companies will instead focus on being smarter with fractures, and seeking to understand the performance of individual stages in real-time. 

"In a tough price environment, being able to push out every bit of optimization matters."

The idea of factory drilling and feeding the "rig monster" has been in the industry for decades, but drilling and completion technology has evolved over time and, in its latest rendition, has been applied to shale. The industry's focus on the size of acreage has created the need for lots of drilling; hence the idea of factory drilling, said Mike Mueller, vice president of technology development with MicroSeismic, in an interview with Rigzone.

The factory drilling approach has been a controversial topic in the oil and gas industry, Mueller said.

"Some totally believe in factory drilling and efficiency driven by statistical production results. Others are advocating a 'data-driven' approach where you drill smart, consistently achieving top quartile production results, not statistically, and hoping to not have too many poor producers."

"The shale plays have been classic acreage plays," said Mueller. "Once the shale concept took hold, independent exploration and production companies sent their landmen out to get the biggest acreage positions ahead of their competition (and for the smallest bonus payments to mineral rights holders they could get) and ahead of the technical work. The technology implementation always chases the landman. Always has, and always will in the United States, which has private mineral ownership."

The overall shale boom, which includes the dominant U.S. shale plays, has solidly left the exploration, access and appraisal phases and entered the development drilling phase of field/play life. The factory approach to field development is the most expensive part of the cycle. The development era could last for many years, given the huge acreage positions companies have accrued.

MORE WILLINGNESS TO INVEST IN NEW TECHNOLOGY

North America's unconventional, deepwater, tight and heavy oil resources have been the focus of much of the investment made since 2003 in oil and gas exploration and production technology, according to a recent report by Boston-based Lux Research. Since 2003, more than $7 billion has been invested in new technologies to enhance oil and gas exploration and production.

"Unlike in the past, the oil and gas industry now embraces emerging technologies from adjacent industries," said Daniel Choi, Lux research analyst and lead author of the report.

Initial investments focused on making unconventional plays more productive, such as hydraulic fracturing technology. Now, a group of companies are focused on giving operators more information on the actual production process, such as microseismic, chemical tracers, downhole fiber optic sensors and temporary insulation to bolster production recovery from wells, Choi told Rigzone in an interview.

PwC experts are seeing operators more willing to quickly introduce new technologies for shale in order to remain competitive in different oil price environments, unlike offshore conventional, where operators are more conservative about introducing new technologies. Onshore shale producers have more operational freedom in this respect due to greater number of wells and shorter life spans when compared with deepwater wells.

The next wave of investment in oil and gas technology will focus on improving recovery of tight oil production. Single-digit recovery levels are currently seen in tight oil wells, compared with recovery of between 20 to 70 percent from conventional wells, said Choi. Currently, many operators are opting to drill new wells rather than invest in currently producing wells to boost production.

"Right now, it's all about making completions more efficient and understanding completions themselves," said Choi. "It's still the Wild West in terms of technologies to understand what makes a well more productive."

The recent decline in oil prices will not slow down investment in unconventional oil and gas technology, as the breakeven price for most shale plays is an average of $60/barrel. However, lower oil prices could hurt investment in the implementation of oil sands production technology, depending on the company, Choi said.

The decline in oil prices could result in companies going either toward doubling down on efficiency imperatives or focusing on technology investment, depending on the exploration and production company's culture, talent, leadership, play circumstances, and the regulatory regime under which they operate, said Mueller. Mueller noted that the rapid production declines of shale plays, which can range from 50 to 90 percent in the first year of production with lower decline rates in following years, means that redevelopment or refracking will start much sooner in shale plays than is typical in conventional plays.

Weaker oil prices will likely facilitate the more rapid adoption of new technology, such as fit-for-purpose rigs for onshore drilling, said Mueller.

"Efficiencies have a way of moving through the industry in quicker periods of lower prices," R.T. Dukes, upstream analyst with Wood Mackenzie, told Rigzone. "Companies are developing best practices at all times and those practices get implemented faster at lower prices."

A large portion of cost savings to date have come from drilling operations and time savings.

"We expect to see significant improvements in both completion effectiveness and efficiency in the near- term," said Christopher Kopczynski, upstream analyst with Wood Mackenzie.

WATER, BIG DATA TECHNOLOGY TO REMAIN FOCUS IN 2015

Water sourcing and usage will continue to be a cost driver for operators. For this reason, new technologies for recycling and use of produced water in hydraulic fracturing could help minimize these costs and provide environmental benefits as well, said Scott Janoe, a partner in Baker Botts environmental practice.

Besides costs for acquiring water, companies also will seek technology solutions to help reduce the amount of truck traffic on roads, which causes wear and tear on roads and creates safety issues, and concerns over the environmental impact of hydraulic fracturing, such as the draining of aquifers, Keith White, CEO and CTO of Ambient Water Inc., a provider of technology for harvesting water from the atmosphere. These concerns have prompted discussions in some states about banning hydraulic fracturing. The concerns expressed by communities and environmental groups will continue to grow over time, White noted.

Oil and gas companies will continue to seek out technologies that allow them to use less or no water in hydraulic fracturing. Mueller noted that one company has been experimenting with using butane in hydraulic fracturing instead of water.

The ability of oil and gas companies to align their water stewardship and business growth strategies will be critical moving forward, with a projected 40 percent average shortfall in global water supply versus demand expected by 2030 and the World Economic Forum in January 2014 ranking water scarcity as number three out of the top 10 trends in terms of impact likelihood. By comparison, food scarcity was ranked number eight, said Deloitte officials at the Deloitte Oil & Gas Conference in Houston in November. The fact that water already is scarce is some regions will drive the need for innovation and collaboration in the oil and gas industry.

The oil and gas industry will continue to delve into Big Data as a means of gaining greater value out of the massive amounts of data generated in oil and gas operations. The digital oil field was really one of the first places that Fast Data started to appear, but now it's in refineries, pipelines and transportation, right the way downstream to the trader and the gas station forecourt, said Steve Farr, senior manager of product marketing at TIBCO, in a statement to Rigzone.

"Let's take machine reliability – and that could be a rig upstream, a pump at the garage, a pressurized vessel at the refinery or even a truck," said Farr. "Sensors on that machine allow us to see everything that is happening – motion, vibration, current, pressures, temperatures etc.  Now, using all this data, combined with historical records we can build a pretty picture of how reliable the machine is in given circumstances – how often it fails and what conditions cause it to fail more or less often."

This means that more robust maintenance strategies can be designed, but it's still essentially descriptive and doesn't help us when one of those conditions changes right now: there's a power surge, a temperature rise etc.

"So what we are now able to do is to monitor the stream of sensor data in real time and compare it to the reliability model we have built. And there have been some stunning results, we expect to see much more of this in 2015."

The Internet of Things (IoT) will gain a strong foothold across the industry, changing how companies utilize labor and allowing for more effective utilization of resources.

"The proliferation of sensors is going to keep exploding as we go forward. Infrastructures will need to grow to support the growth in data, both wired and wireless," Serhii Konovalow, global oil & gas and energy vertical lead with Cisco, told Rigzone in a statement.

Konovalow noted that 2015 will be a year of Industrial Mobility – finally, it will all came together: Wi-Fi technology and applications, strong business case and execution.

"We see major shifts as oil and gas is looking to decrease unproductive time, decrease cycle time and keep safety at top level – Industrial Mobility brings it all for upstream production and processing facilities as well as for refineries in downstream." 

With the onset of additional IoT-enabled technologies and the growth of Industrial Mobility, cybersecurity will become as important to the industry as physical security. As more processes come online and become automated, the attack surface for oil and gas companies grows. Organizations will need to change their approach to security.

Leading operators and service companies will begin truly exploring potential of the emerging computing paradigm, Fog Computing, said Konovalow.

"As it brings new tools to manage growing amount of data at the edge of the infrastructure and deploy analytics applications at the remote site to improve speed of decisions and accuracy, oil and gas industry and suppliers are in the process of testing and crafting strategy on leveraging Fog Computing phenomena to bring new applications and capabilities faster and to build a great competitive advantage in processing data in Big Data age."  

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Calibrating Fracture Gradient with Acoustic Radial Profiling Where Leakoff and Minifrac Tests Unavailable

Stress estimates from Sonic Scanner platform measurements refine the mud-weight program for drilling deep overpressured reservoirs, Malay basin

Challenge: In the absence of leakoff and minifrac tests, resolve uncertainty in the fracture gradient and mud-weight window required for the drilling design to a deeper targeted reservoir.

Solution: Run the Sonic Scanner acoustic scanning platform, which measures sonic velocities at multiple depths of investigation to provide a full 3D characterization from which stress magnitudes and the stress regime can be calculated for direct input to the drilling design and model calibration.

Result: Accurately specified mud weights for different hole sections and offset well locations based on continuous elastic properties and a calibrated mechanical earth model (MEM) calculated with increased confidence by using a fracture gradient profile based on stress estimations from Sonic Scanner platform measurements.

High uncertainty in stress magnitudes in the shallow overburden

An operator with two appraisal wells in the North Malay basin was concerned about wellbore stability. The shallow formations, at 2,000 to 4,000 ft, are characterized by weak, soft sediments in which leakoff tests did not return reliable data for calibrating the fracture gradient and determining the casing point for reaching the deeper reservoir targets. The pore pressure significantly ramps up to the deep overpressured reservoirs below 8,000 ft, which require mud weights up to 7 lbm/galUS higher than for a normal pressure environment.

To measure the minimum horizontal stress for determining the fracture gradient, a wireline formation tester was deployed in dual-packer configuration to conduct a minifrac test in a clean water-bearing sand. Measurement of the stress required to break down the formation would be used to calibrate log and core measurements. But even with pump pressure as high as 4,500 psi—the limit of the packers—the formation did not break down. Without sufficient stress data from the leakoff and minifrac tests, the MEM could not be calibrated to be certain of the minimum horizontal stress or fracture gradient.

Advanced acoustic measurements for informed modeling

The Sonic Scanner acoustic scanning platform uses multiple monopole and dipole transmitters to accurately measure at multiple depths of investigation. In addition to conventional compressional and shear slownesses, the Sonic Scanner platform obtains axial, radial, and azimuthal waveforms for characterizing both the near-wellbore and far-field formation volumes. For relatively soft rocks, such as the shallow reservoirs in the North Malay basin, near-wellbore stress concentrations cause deformation that is noticeable in the compressional and shear measurements. By combining the nearwellbore and far-field radial profiles with a nonlinear elastic wellbore stress model, the horizontal stress regime can be estimated for zones that are sensitive to stress.

Answers for drilling design and pressure management

The stress magnitudes determined with the Sonic Scanner platform's measurements in a stress-sensitive sand formation were calibrated to core measurements to explain why the minifrac and leakoff test pressures had not reached breakdown pressure. The fracture initiation pressure was recalculated to be 5,500 psi, nearly 40% higher than the existing estimate and 1,000 psi higher than the pressure applied during the minifrac test.

Beyond the essential pore pressure and fracture gradient calculations, calibrated rock strength and elastic properties were constructed with data from the Sonic Scanner platform, petrophysical logging, and core measurements. Based on this accurate, continuous dataset, the MEM can be used to predict wellbore stability at different well deviations for calculating the safe mud-weight window in drilling both these initial wells and subsequent wells, as production depletes the reservoir pressure. This predictive modeling for shallow reservoir pressure management is essential for successfully reaching deeper reservoir targets.

Download: Calibrating Fracture Gradient with Acoustic Radial Profiling Where Leakoff and Minifrac Tests Unavailable (0.54 MB PDF)

PDVSA Optimizes Surface Well Testing Operations with Fit-For-Purpose Mobile Production Testing Units

Operator deploys compact units to increase efficiency of dynamic well cleanup campaign, onshore Venezuela

Challenge: Obtain accurate and reliable production testing measurements during cleanup operations, in a timely manner, from more than 120 oil wells onshore Venezuela.

Solution:

• Deploy Schlumberger mobile production testing technologies and personnel, including a fit-for-purpose trailer-mounted surface well testing unit containing a separator, choke manifold, and emergency shutdown (ESD) system ideal for the dynamic operation.
• Integrate with Schlumberger CT technologies and services to consolidate resources and minimize third-party rental accessory costs.

Result:

• Increased production testing efficiency and reduced footprint by employing robust modular technologies.
• Enhanced operational safety with fit-forpurpose equipment designed to the highest safety standards.
• Enabled rapid response times for project execution.

High-volume well cleanup campaign necessitates efficiency

For a campaign of more than 120 oil wells in the Furial and Punta de Mata fields of eastern Venezuela, PDVSA sought a compact production testing solution that would save space at the wellsite during the well cleanup phase. A package of standardized technologies and services would help optimize cleanup and surface well testing activities on such a vast spread of wells. With technologies and a standard operating procedure best suited for the environment, PDVSA could apply the same operational efficiency to multiple wells in the region with equipment and personnel committed specifically to its projects.

Standard operating procedure eases transition between multiple wellsites

The lean design of Schlumberger mobile production testing units enabled PDVSA to successfully test a greater number of wells per day, while maintaining a reduced wellsite footprint. A smaller manifold and separator were both introduced with no negative affect on the operating parameter envelope. The ease of transporting the mobile units enabled PDVSA to rapidly transport dedicated technologies and personnel from one wellsite to another.

Mobile production testing units integrate seamlessly with wellsite operations

To effectively obtain measurements during cleanup from wellsites with limited space, PDVSA worked with Schlumberger to select efficient, fit-for-purpose mobile production testing units to meet surface well testing objectives. The modular mobile units were outfitted specifically for PDVSA's operations and ensured the availability of technologies and experienced personnel best suited for the multiwell project. With a large number of wells requiring testing across the region, the mobile production testing units offer PDVSA operating efficiency beyond that of traditional nonmobile options.

The design of the mobile units took into consideration Venezuelan restrictions on imports and equipment on wheels without sacrificing efficiency. An onboard separator handles both high and low gas flow rates, while a 10,000-psi choke manifold and ESD system help ensure proper well control. With an agreed-upon design Schlumberger can rapidly mobilize additional units and spare parts to supply the high volume of PDVSA activity. And, with other Schlumberger resources readily available, CT or wireline operations can be easily integrated with existing surface well testing operations.

Download: PDVSA Optimizes Surface Well Testing Operations with Fit-For-Purpose Mobile Production Testing Units (1.55 MB PDF)

Case Study: Innovative Completion Design and Job Execution Result in 100% Gravel Pack in 136° Fishhook Well

Operator overcomes challenges posed by shallow offshore well with steep trajectory drilled from onshore

Challenge: Find an efficient way to develop offshore hydrocarbon prospects and control sand production in shallow-water fishhook well from onshore drilling location.

Solution: Design a gravel-pack system specially suited for wells with fishhook trajectories with the following technologies:

• OptiPac Alternate Path openhole gravel-pack screen
• Hornet skid-mounted gravel-pack blender
• ClearPAC polymer-free gravel-pack fluid
• fast-acting oil-swellable packers
• pressure-activated diverter valves
• antiswab washdown service tool.

Result: Achieved a full annular gravel pack in the inverted-angle well with zero sand production; successfully met production and injection targets.

Fishhook trajectory poses specific challenges for sand control completion

An operator was developing a field along the coastline offshore Southeast Asia. Targeting this marginal oil required drilling into multiple hydrocarbon prospects with stacked shale and water zones. Drilling the wells from offshore was deemed uneconomical. Accessing the oil from land wells that tied into existing onshore infrastructure would be more efficient and allow immediate production.

The company planned an openhole "fishhook" well with an upward trajectory of up to 136°. The openhole interval was to be more than 700 m long and have six zones. Gravel packing had to be accomplished at the steep angle without exceeding the fracture pressure. The upward trajectory would make it difficult to keep the proppant from sliding and bridging in the wellbore, which would prevent a full annular pack.

Innovative gravel-pack design minimizes friction pressure, ensures full gravel pack

To mitigate the bridging and promote heel-to-toe packing, Schlumberger recommended an innovative gravel-packing system that would minimize friction pressure during the operation and help ensure a full annular gravel pack in the challenging environment.

A screen completion string, designed to accommodate six zones, included five oil-swellable packers to isolate the zones in the openhole interval. A sixth oil-swellable packer was placed inside the casing above the top of the screen to provide a bottom for the pack and to encourage heel-to-toe packing from inside the casing shoe. These fast-acting swellable packers were soaked in a diesel oil that allowed the elastomer to swell against the openhole rock before the zones were gravel packed, isolating the zones and preventing the pack from sliding downhill during gravel packing.

Pressure-activated diverter valves incorporated into the internal service string were evenly spaced along the openhole section to minimize the circulating pressure exerted on the formation during the packing operation. These valves short-circuited the washpipe at various locations, shortening the length of the washpipe through which the returning gravel-pack carrier fluid had to travel.

The system included the OptiPac Alternate Path openhole gravel-pack screen, which has shunt tubes to prevent bridging. The shunts diverted slurry accumulations into the zones between the packers until the annulus was fully packed. Transport and packing tubes delivered slurry to the area between the screens and the wellbore. This design reduced slurry dehydration inside the shunts, eliminating the risk of bridging into the tubes and extending the potential length of the gravel-pack interval.

The Hornet skid-mounted gravel-pack blender was used to optimize delivery. The ClearPAC fluid was chosen as the optimal gravel carrier fluid because of its capabilities to reduce friction and suspend the gravel at low shear rates. The viscoelastic gel also helped control leakoff through the nozzles of the packing tubes.

The antiswab washdown service tool stabilized the hydrostatic pressure in the open hole, eliminating the swabbing effects of hardware movement and ensuring filtercake integrity before gravel placement. After the excess gravel was screened out and reversed, the service tool allowed spotting of filtercake removal treatments, eliminating a dedicated cleanup run.

Completion design and job execution ensure 100% gravel pack

The combination of technologies resulted in a 100% gravel pack below the fracture pressure of the well. Accessing the well from an onshore location enabled the operator to reduce the costs and risks related to offshore operations. As a result of this success, 10 additional fishhook wells, both injectors and producers, were completed along the shore. This new completion design provides an alternative method for gravel packing fishhook wells with narrow frac/pore-pressure windows and developing hydrocarbon prospects in shallow waters from onshore drilling locations.

Download: Innovative Completion Design and Job Execution Result in 100% Gravel Pack in 136° Fishhook Well (0.27 MB PDF)

Related services and products

	Openhole Sand Control Services
	Sand Control Pumping Equipment
	ClearPAC Polymer-Free Fluid for Gravel Packs

Suspension trauma - harness hang syndrome (HHS)

How long can an individual stay in a static vertical suspension e.g. after a fall arrest has occurred?

Your question seems to be about HHS or Suspension Trauma.

This is an important post-fall risk and many in oil industry are not aware of it so this is a good question to ask to let many more aware of it.

One should read the research on it to completely understand this part. On internet it is available at http://www.hse.gov.uk/research/crr_pdf/2002/crr02451.pdf

An human can faint and die if left hanging because of less supply of oxygen to his brain.

As per research the person hanging from harness will feel Harness Hang Syndrome even after "few minutes" depending on person's pre fall state (diet, health etc.)

1. But I guess the oil and gas checklist requires that person should be rescued in less than 15 minutes.

Checklist: "How will rescue be assured within 15 minutes of the occurrence of a fall to minimize the risk of further injury or death due to suspension trauma?"

2. Experiments have shown that people can start loosing consciousness in less than 10 minutes. 

"So what are the symptoms of HHS? The FFS testing showed that HHS symptoms
appeared in no more than 10 minutes with healthy subjects. Brinkley's research showed
that 6 minutes was the normal onset time."

3. The research done has showed that person hanging from a harness can start feeling HHS even in 3 minutes. 

Further emphasizing risks of suspension phase - 

"The fall and the arrest of it are only part of the story, and not necessarily the most dangerous. After the fall and its arrest comes the suspension phase, when the casualty either rescues him or herself, if capable, or awaits rescue by another person or persons. After a fall, the body is likely to be in a state of shock. If the casualty is badly injured or unconscious, there is unlikely to be any movement of the legs and there can be serious consequences. The orientation of the body and the comfort of the suspended person, determined to a large extent by the design of the harness and the position of its attachment point to the system, also play their part in the outcome. "

Definition of HHS on Wikipedia.

"Suspension trauma (Syn. "orthostatic shock while suspended"), also known as harness hang syndrome (HHS), or orthostatic intolerance, is an effect which occurs when the human body is held upright without any movement for a period of time. If the person is strapped into a harness or tied to an upright object they will eventually suffer the central ischaemic response (commonly known asfainting). If one faints but remains vertical, one risks death due to one's brain not receiving the oxygen it requires.[1]" 

References

1. http://en.wikipedia.org/wiki/Suspension_trauma

2. http://www.hse.gov.uk/work-at-height/index.htm

3. http://www.elcosh.org/document/1662/d000568/Will%2BYour%2BSafety%2BHarness%2BKill%2BYou%253F.html?show_text=1

4. http://www.outdoorswa.org/files/Harness%20Hang%20Syndrome.pdf