EPPlus September 2020 logo
The Other
Side
As the oil and gas industry
regains strength, companies
could emerge anew
Black plus
Clay Williams
Automating well completions
Cover image for Innovation Spotlight
Cover image for 2020 MEA Winners
September 2020
EPPlus September 2020 logo
The Other
Side
As the oil and gas industry
regains strength, companies
could emerge anew
Black plus
Clay Williams
Clay Williams
Cover image for Innovation Spotlight
Cover image for 2020 MEA Winners
September 2020
Slow down or accelerate?
How upstream players can decarbonize with positive returns
NOV’s CEO shares his insights on the industry’s path forward
TechnipFMC shares insights on its 2020 OTC Spotlight on Technology winning system
Exploration for clastic stratigraphic traps
Digital transformation in the oil patch’s back office
Trusting digital twins to deliver value
A compilation of the industry’s latest upstream technologies
EPPlus September 2020 Cover
Oil rig in field
Fire protection
Plus
Drilling activity around the U.S.
Drilling activity around the world
Promotions, new hires and the latest company news
Boosting productivity in an era of E&P belt tightening
Cartoon megaphone
EPPlus September 2020 Cover
Slow down or accelerate?
How upstream players can decarbonize with positive returns
Oil rig in field
NOV’s CEO shares his insights on the industry’s path forward
TechnipFMC shares insights on its 2020 OTC Spotlight on Technology winning system
Fire protection
Exploration for clastic stratigraphic traps
Digital transformation in the oil patch’s back office
Trusting digital twins to deliver value
A compilation of the industry’s latest upstream technologies
Drilling activity around the U.S.
Drilling activity around the world
Promotions, new hires and the latest company news
Boosting productivity in an era of E&P belt tightening
Cartoon megaphone
EPPlus September 2020 Cover
About The Cover: As the world recovers from the COVID-19 pandemic, energy demand is slowly picking up. Energy companies around the world are evaluating their assets and operations to ensure they emerge in the best possible position to capitalize on a new era of oil and gas production. (Cover photo courtesy of Marc Morrison/marcmorrison.com; Bottom images from left to right courtesy of National Oilwell Varco, Downing USA, TechnipFMC and Hart Energy; Cover design by Alexa Sanders)
Coming Next Month: The October issue’s cover story will focus on ESG. The Executive Q&A will feature an exclusive video interview with Baker Hughes Chairman and CEO Lorenzo Simonelli, and the Regional Report will highlight South America. As always, E&P Plus will include its exploration, drilling, completions, production and offshore features in every issue. While you’re waiting for your next copy of E&P Plus, be sure to visit HartEnergy.com for the latest news, industry updates and unique industry analysis.
E&P (ISSN 1527-4063) (PM40036185) is published monthly by Hart Energy Publishing, LP, 1616 S. Voss Road, Suite 1000, Houston, Texas 77057. Periodicals postage paid at Houston, TX, and additional mailing offices. Subscription rates: 1 year (12 issues), US $149; 2 years (24 issues), US $279. Single copies are US $18 (prepayment required). Advertising rates furnished upon request. POSTMASTER: Send address changes to E&P, P.O. Box 3001, Northbrook, IL 60065-9977. Address all non-subscriber correspondence to E&P, 1616 S. Voss Road, Suite 1000, Houston, Texas 77057; Telephone: 713-260-6442. All subscriber inquiries should be addressed to E&P, 1616 S. Voss Road, Suite 1000, Houston, TX 77057; Telephone: 713-260-6442, Fax: 713-840-1449; custserv@hartenergy.com. Copyright © Hart Energy Publishing, LP, 2020. Hart Energy Publishing, LP reserves all rights to editorial matter in this magazine. No article may be reproduced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission to photocopy is granted to users registered with Copyright Clearance Center/0164-8322/91 $3/$2. Indexed by Applied Science, Technology Index and Engineering Index Inc. Federal copyright law prohibits unauthorized reproduction by any means and imposes fines of up to $25,000 for violations.
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HartEnergy.com
Editorial Director
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Velda Addison

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Brian Walzel

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Joseph Markman

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Online Content +
Exclusives Available Only Online
Methane heat map
New methane ‘heat map’ to help oil companies reduce emissions
By Mary Holcomb, Associate Editor
A new digital tool set for release later this year by Geosite will provide the oil and gas industry with actionable satellite imagery for the detection of high-methane emissions events.
Buffalo Bills owners’ blank-check company raises $300 million
By Darren Barbee, Senior Editor
Terrence M. Pegula joins other NFL owners, most notably Dallas Cowboys owner Jerry Jones, in making large new investments during a stagnant time for the oil and gas industry.
Texas takes steps to reduce flaring in oil sector
By Velda Addison, Group Senior Editor
Changes would include reducing the amount of time an operator may get an administrative exception to flare natural gas.
Experts expect tough second half ahead for oil sector
By Velda Addison, Group Senior Editor
Oil and gas companies face continued market volatility despite an already historic year so far.
Exxon Mobil, Chevron adjust in Permian Basin amid market volatility
By Velda Addison, Group Senior Editor
The supermajors are focused on specific developments and improving efficiency in the Permian Basin as market conditions recover.
Tokyo Gas takes first majority stake in US shale producer
By Darren Barbee, Senior Editor
Tokyo Gas will pay about $620 million as it increases its ownership in Castleton Resources, a U.S. shale gas operator focused on being a consolidator of E&P assets in the Ark-La-Tex region.
HART ENERGY VIDEOS
By Jessica Morales, Director of Video Content
WPX Energy’s Clay Gaspar talks Permian outlook, ESG, tech
Clay Gaspar, president and COO at WPX Energy, provides an indepth look at the shale producer’s outlook for the Permian and Williston basins along with the importance of ESG.
WPX Energy's Clay Gaspar
Advisers coauthor book to help upstream companies process risk
Risked Revenue Energy Associates President and Founder Wayne Penello and Managing Director Andrew Furman preview their book, which was released Aug. 11.
Risked Revenue
Grant Thornton’s Bryan Benoit talks oil industry recovery
After a rough second quarter that included a historic collapse in oil prices, Bryan Benoit, a principal with Grant Thornton Financial Advisors who also leads the firm’s energy advisory practice, says he’s starting to see green shoots ahead for the industry.
ESG roundtable: Is oil and gas ready for the expectations, opportunities?
If the industry wants continued capital investment, it will have to up its game. Our virtual panel discusses what you need to know to be ready for increased scrutiny and requirements of an ESG future.
ESG Virtual Panel Roundtable
As I See It text
Slow down or
accelerate?
We are launching E&P Plus for a new era of oil and gas.
We are launching E&P Plus for a new era of oil and gas

Slow down or
accelerate?

We are launching E&P Plus for a new era of oil and gas.
I

t was Independence Day in the U.S. when it hit me. Not a backyard firework, although I did have to dodge a few wayward bottle rockets. I was struck by an epiphany that the COVID-19 pandemic isn’t a time to feel sorry for ourselves; it’s a chance to embrace a future we probably already saw coming, even if it’s hard to admit sometimes.

This notion got into my head with a simple answer to a question I posed to my family. I pondered what the holiday shopping season would be like this year given crowded stores are unlikely. The answer I got from a niece was matter-of-fact and telling. “I haven’t done Christmas shopping in a store in two years,” she said.

Retail job losses are a serious problem we’re facing, but shopping has already mostly gone digital and will continue to do so. It’s a tough reality to face, but there’s opportunity in change.

Len Vermillion Headshot
Len Vermillion
Editorial Director
lvermillion@hartenergy.com
Industry Pulse
BCG’s low-carbon strategy for upstream players focuses on reducing their carbon footprint while providing financial value to companies in the low-price environment. (Source: Leonid Ikan/Shutterstock.com)
How upstream players can decarbonize with positive returns
A company’s detailed road map outlines how to design a cost-effective decarbonization strategy.
BCG’s low-carbon strategy for upstream players focuses on reducing their carbon footprint while providing financial value to companies in the low-price environment. (Source: Leonid Ikan/Shutterstock.com)
Faiza Rizvi, Associate Editor
D

espite a rebound in oil prices, resurgent waves of the COVID-19 show the industry’s recovery remains fragile. In addition to dealing with the volatility of the near-term market environment, upstream companies face a longer-term challenge of reducing emissions, with growing pressure from regulators, investors and other stakeholders. Although many upstream companies have made considerable progress in meeting climate change goals, they will have to play a bigger part going forward as stakeholder pressure and expectations continue to rise.

Boston Consulting Group (BCG) has outlined a cost-effective approach, which offers to shrink a company’s carbon footprint and strengthen its social license to operate and increase revenue growth.

“The industry is facing a challenging time. Upstream players are making spending cuts, and it is likely they will focus on core operations and avoid making additional investments,” Thomas Baker, managing director and partner with BCG, told E&P Plus. “That being said, we think there is still a role for decarbonization, and in fact, the current environment creates an important opportunity to potentially accelerate these activities. Many of these measures can be cost-effective and provide lower capex, improved output and have a financial benefit for the players.”

Executive Q&A
Q&A text
NOV’s CEO shares his insights on the industry’s path forward
Clay Williams headshot
Clay Williams
Chairman, President and CEO, NOV
Clay Williams discusses the future of onshore and offshore oil and gas development, the impact of the energy transition on oilfield service providers and more amid the challenging energy climate.
Jennifer Presley, Executive Editor

A

focus of this month’s issue of E&P Plus is on what the oil and gas industry will look like as it moves forward into a post-pandemic world. It is a world that is a little bit different than the one the predecessors for the company that would become National Oilwell Varco (NOV) witnessed more than a century ago.

Clay Williams, the chairman, president and CEO of NOV, recently provided E&P Plus with an exclusive video interview in which he shared his views on the way forward for oilfield service companies.

Innovation Spotlight
Video icon
TechnipFMC shares insights on its 2020 OTC Spotlight on New Technology winning system
Eduardo Cardoso, director of subsea processing technologies, discusses the company’s Subsea Power Distribution Station, the future of subsea power generation and more.
Jennifer Presley, Executive Editor
T

oday’s smartphones have more processing power than the computing system NASA used to put a man on the moon and bring him home more than 50 years ago. The shared similarity is that without a steady supply of electric power, each would be a useless block of assembled raw materials.

On land, at sea or on the seabed, the challenge of providing a steady supply of electrical power to thirsty industrial consumers is a global one. For the oil and gas industry, the shift from topsides operations to subsea operations is underway. Ensuring safe and reliable subsea operations requires a safe and reliable source of electrical power.

Eduardo Cardoso, director of subsea processing technologies with TechnipFMC, discusses the company’s Subsea Power Distribution Station (SPDS)—a 2020 Offshore Technology Conference Spotlight on New Technology award winner—the challenge of powering subsea systems and more in this E&P Plus inaugural “Innovation Spotlight.”

Analyst Corner
Exploration for clastic stratigraphic traps
Explorers must recognize whether they have the right tools and processes to explore effectively for commercial finds.
Explorer graphic
Graeme Bagley and Edwige Zanella, Westwood Global Energy Group
O

ver the last decade, more oil and gas was discovered in stratigraphic traps than any other trap type, and excelling in stratigraphic trap exploration is now the key to top quartile exploration performance. Historically, hydrocarbon prospects in clastic stratigraphic traps have been considered difficult to identify and high risk to explore, but success rates have been improving with better geological models and use of geophysical direct hydrocarbon indicators (DHIs).

Westwood analyzed stratigraphic trap exploration between 2008 and 2019 in 66 basins and in 113 different plays. It found that the proportion of exploration targets reported as involving stratigraphic traps increased from 12% in 2008 to 30% in 2019. Commercial success rates (CSRs) also have increased, with the average CSR of 50% achieved between 2017 and 2019, double that of the previous nine years. Stratigraphic traps had a larger average discovery size of 280 MMboe, and a lower drilling finding cost of 0.5 $/boe, compared to other trap types during this period. The evidence shows they are not higher risk than other traps, contrary to many explorers’ preconceptions.

Cover Story:
Industry Recovery
The Other
Side
As the oil and gas industry regains strength following a tumultuous second quarter, companies could emerge anew.
As the world recovers from the COVID-19 pandemic, energy demand is slowly picking up. Energy companies around the world are evaluating their assets and operations to ensure they emerge in the best possible position to capitalize on a new era of oil and gas production. (Source: Marc Morrison/marcmorrison.com)
Velda Addison and Brian Walzel, Hart Energy
N

o one had seen anything like this.

Unlike previous downturns, no amount of bracing could save some oil companies from bankruptcy or falling into the arms of peers with stronger balance sheets.

With an oil price war between OPEC+ brewing and a pandemic spreading across the world, the oil and gas industry buckled under the pressure of slowed demand as travel came to a near halt in the spring. Oil prices nosedived. Producers shut in production. Previously trimmed budgets got even thinner, and operators and service providers alike laid off thousands.

The situation, however, appears to have improved—at least as of late summer. Stay-at-home orders intended to slow the spread of COVID-19 eased, and production cuts brought supply and demand closer to balance. Oil prices stabilized around $40/bbl after falling into negative territory.

Yet, the damage is evident, and the potential for more disruption and demand destruction exists.

Planning for the next chapter in the predictably unpredictable oil and gas sector could seem like a tall order—not knowing which direction attempts to slow the global pandemic could swing demand.

However, today’s market turmoil has not blinded executives from long-term company goals. It may have even shed more light on specific paths different types of companies are taking, evidenced by where capital is being directed.

The Other
Side
As the oil and gas industry regains strength following a tumultuous second quarter, companies could emerge anew.
Velda Addison and Brian Walzel, Hart Energy
N

o one had seen anything like this.

Unlike previous downturns, no amount of bracing could save some oil companies from bankruptcy or falling into the arms of peers with stronger balance sheets.

With an oil price war between OPEC+ brewing and a pandemic spreading across the world, the oil and gas industry buckled under the pressure of slowed demand as travel came to a near halt in the spring. Oil prices nosedived. Producers shut in production. Previously trimmed budgets got even thinner, and operators and service providers alike laid off thousands.

The situation, however, appears to have improved—at least as of late summer. Stay-at-home orders intended to slow the spread of COVID-19 eased, and production cuts brought supply and demand closer to balance. Oil prices stabilized around $40/bbl after falling into negative territory.

Yet, the damage is evident, and the potential for more disruption and demand destruction exists.

Planning for the next chapter in the predictably unpredictable oil and gas sector could seem like a tall order—not knowing which direction attempts to slow the global pandemic could swing demand.

However, today’s market turmoil has not blinded executives from long-term company goals. It may have even shed more light on specific paths different types of companies are taking, evidenced by where capital is being directed.

Image of MEA Award Medal
2020
Meritorious Awards
Image of MEA Award Medal
2020
Meritorious Awards
for Engineering Innovation
An expert panel of judges has selected the top 25 industry projects that open new and better avenues to the complicated process of finding and producing hydrocarbons around the world.
T

he E&P Plus editors and staff proudly present the winners of the 2020 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 pages that follow highlight 25 winners picked by an independent team of judges.

The winning technologies represent a broad range of disciplines and address several challenges 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, drill bits, drilling fluids/stimulation, drilling systems, exploration/geoscience, formation evaluation, HSE, hydraulic fracturing/pressure pumping, intelligent systems and components, IOR/EOR/remediation, marine construction and decommissioning, nonfracturing completions, subsea systems and water management.

Exploration
Exploration
Shearwater’s marine vibrator BASS is lowered into the water for testing. (Source: Shearwater)
Shearwater’s marine vibrator BASS is lowered into the water for testing. (Source: Shearwater)
New marine vibrator
offers a more efficient
and eco-friendly seismic source
Marine vibrators provide less environmental impact and better data.
Sara Amar, Shearwater; and Peter Hanssen, Equinor
A

ctive seismic acquisition is one of the first key steps in the exploration for new oil and gas reserves and is also fundamental in the effort to optimize the development and production of existing oil fields. It uses seismic waves emitted by sources at discrete locations, and some of that energy is reflected back from layers in the subsurface to tens of thousands of recording sensors. The data are then processed to give an image of the subsurface, which is later analyzed by geologists to identify commercial deposits of hydrocarbons.

A typical marine seismic acquisition is conducted using airgun source arrays towed behind a vessel. Such a source typically comprises about 30 single airguns of different volumes, all firing at the same time to produce a sharp acoustic peak. The principle technology of airguns has not evolved much since the 1970s when it replaced the use of dynamite, and airguns stayed inherently inflexible by nature.

Drilling
Drilling motors
reimagined with
system-focused design
A new motor helps increase power and performance to complete longer laterals faster and with greater control.
Shashi Talya, Halliburton
O

perators strive to drill faster and more reliably regardless of the drilling environment. This has increased the demand for more power generation by a mud motor. For shoe-to-shoe drilling performance and improved total well delivery, it is vital for the focus to be on the motor as a system. Historically, the focus on motors has been to improve performance of individual sub-systems or components with little focus on overall system performance. As a result, one of the trends is that the power section has outpaced the rest of the motor in terms of torque capability and horsepower.

With advances in elastomer technology and power section design, the industry has developed high-performance power sections that can run at higher flow rate and higher differential pressure resulting in increased horsepower. The transmission and bearing section has now become the weaker link in the chain along with the motor connections. A true system level design requires consideration of the overall bottomhole assembly (BHA), such as motor only or motor-assisted rotary steerable system (RSS); applications (vertical only, curve and lateral, or lateral only); downhole temperatures; and drilling parameters. A clear understanding of the loads on the BHA in various applications and rig constraints in terms of flow rate, pressure and torque capability is critical to ensuring a successful drilling campaign.

Drilling
Drilling motors
reimagined with
system-focused design
A new motor helps increase power and performance to complete longer laterals faster and with greater control.
Shashi Talya, Halliburton
O

perators strive to drill faster and more reliably regardless of the drilling environment. This has increased the demand for more power generation by a mud motor. For shoe-to-shoe drilling performance and improved total well delivery, it is vital for the focus to be on the motor as a system. Historically, the focus on motors has been to improve performance of individual sub-systems or components with little focus on overall system performance. As a result, one of the trends is that the power section has outpaced the rest of the motor in terms of torque capability and horsepower.

With advances in elastomer technology and power section design, the industry has developed high-performance power sections that can run at higher flow rate and higher differential pressure resulting in increased horsepower. The transmission and bearing section has now become the weaker link in the chain along with the motor connections. A true system level design requires consideration of the overall bottomhole assembly (BHA), such as motor only or motor-assisted rotary steerable system (RSS); applications (vertical only, curve and lateral, or lateral only); downhole temperatures; and drilling parameters. A clear understanding of the loads on the BHA in various applications and rig constraints in terms of flow rate, pressure and torque capability is critical to ensuring a successful drilling campaign.

Drilling
Formation
evaluation returns
to the surface
Hybrid mud logging is a major step change in providing quantitative data in near-real time without increasing personnel.
Simon Hughes, Geoffrey Cave and David Tonner, Diversified Well Logging
F

ormation evaluation at the wellsite was initially carried out by geologists examining cuttings and formation gas collected from the mud stream and “lagged” to bit depth, a practice known as mud logging or surface logging. Over the years, technological advances and economic viability allowed ever more complex downhole measurement tools to be created and run. These MWD and LWD tools determine several formation properties and have become uniquely associated with formation evaluation.

In today’s business climate, upstream oil and gas companies are increasingly focused on capital efficiency and return on investment (ROI). Delivery of an acceptable ROI to private and public investors is currently challenging in unconventional plays. However, these challenges also apply offshore with its high cost operations, the focus on trimming budgets, reduction of nonproductive time (NPT) and risk, and getting the best data at the best price.

By reinventing mud logging through the development of robotic solutions and advanced software for the collection and analysis of drilled cuttings, including real-time geochemistry at the well site, Diversified Well Logging (DWL) is providing a tool to help operators achieve better capital efficiency and ROI. As a result, high-resolution quantitative data at low risk and cost are available for geologists and engineers, meaning that formation evaluation can return to the surface.

Drilling
Formation
evaluation returns
to the surface
Hybrid mud logging is a major step change in providing quantitative data in near-real time without increasing personnel.
Simon Hughes, Geoffrey Cave and David Tonner, Diversified Well Logging
F

ormation evaluation at the wellsite was initially carried out by geologists examining cuttings and formation gas collected from the mud stream and “lagged” to bit depth, a practice known as mud logging or surface logging. Over the years, technological advances and economic viability allowed ever more complex downhole measurement tools to be created and run. These MWD and LWD tools determine several formation properties and have become uniquely associated with formation evaluation.

In today’s business climate, upstream oil and gas companies are increasingly focused on capital efficiency and return on investment (ROI). Delivery of an acceptable ROI to private and public investors is currently challenging in unconventional plays. However, these challenges also apply offshore with its high cost operations, the focus on trimming budgets, reduction of nonproductive time (NPT) and risk, and getting the best data at the best price.

By reinventing mud logging through the development of robotic solutions and advanced software for the collection and analysis of drilled cuttings, including real-time geochemistry at the well site, Diversified Well Logging (DWL) is providing a tool to help operators achieve better capital efficiency and ROI. As a result, high-resolution quantitative data at low risk and cost are available for geologists and engineers, meaning that formation evaluation can return to the surface.

Completions
Reducing flat time
in the field
An offline cementing system saves an E&P company eight hours of cycle time and about $32,000 per well.
Brandon Dodge, Weir Oil & Gas
W

hile multiwell pad drilling offers many advantages, operators often find themselves relying on traditional methods that prevent them from experiencing the full benefits this approach can provide. New technology that reduces flat time can unlock deeper cost savings and efficiencies operators have been waiting for.

Traditional extraction methods involve drilling down vertically from a new pad into a single well. This requires a rig to be disassembled, hauled to the next pad and then reassembled—even if the new well site is just a few feet away. Relocating a rig requires several days, hundreds of thousands of dollars and constructing an entirely new drilling pad, along with all the equipment and infrastructure that goes with it, making it costly to the operator and the environment.

Multiwell pad advantages
Multiwell pad drilling enables operators to achieve economies of scale to shorten cycle time and increase rig productivity, which is why it has become the new norm in North America land operations. Instead of building multiple four-acre locations to drill, complete and produce horizontal wells, multiwell pad drilling allows operators to tap into different layers of shale at various levels of the subsurface at one time from one location, reaching multiple reservoirs and formations more efficiently. Multiwell pad drilling enables multiple wellbores to be drilled from one drilling pad, cutting down on the amount of space and the number of rigs needed for an operation, while increasing the number of wells, and potentially the amount of resources, those wells can reach.
Completions
Reducing flat time
in the field
An offline cementing system saves an E&P company eight hours of cycle time and about $32,000 per well.
Brandon Dodge, Weir Oil & Gas
W

hile multiwell pad drilling offers many advantages, operators often find themselves relying on traditional methods that prevent them from experiencing the full benefits this approach can provide. New technology that reduces flat time can unlock deeper cost savings and efficiencies operators have been waiting for.

Traditional extraction methods involve drilling down vertically from a new pad into a single well. This requires a rig to be disassembled, hauled to the next pad and then reassembled—even if the new well site is just a few feet away. Relocating a rig requires several days, hundreds of thousands of dollars and constructing an entirely new drilling pad, along with all the equipment and infrastructure that goes with it, making it costly to the operator and the environment.

Multiwell pad advantages
Multiwell pad drilling enables operators to achieve economies of scale to shorten cycle time and increase rig productivity, which is why it has become the new norm in North America land operations. Instead of building multiple four-acre locations to drill, complete and produce horizontal wells, multiwell pad drilling allows operators to tap into different layers of shale at various levels of the subsurface at one time from one location, reaching multiple reservoirs and formations more efficiently. Multiwell pad drilling enables multiple wellbores to be drilled from one drilling pad, cutting down on the amount of space and the number of rigs needed for an operation, while increasing the number of wells, and potentially the amount of resources, those wells can reach.
Completions
Automating
well completions
A new system reduces stage-to-stage transition time from 45 minutes to less than 3 minutes while ensuring the safety of personnel.
Tim Marvel and Austin Johnson, Downing USA
T

he plug-and-perf (PNP) technique is the most prevalent completion method in North America’s shale and tight oil plays. The method provides the ability to pinpoint fracture locations with perforating guns, adjust stage spacing during the completion, achieve zonal isolation between stages and complete 100 or more stages in a horizontal well.

While preferred versus the sliding sleeve method, the traditional PNP method is highly inefficient and requires personnel to work at height in the red zone. Traditional wireline tool deployment requires three steps.

First, the working valve on the frac tree is shut down manually by a red zone operator. The wireline operator picks up the gun assembly and suspends it over the frac head and the red zone operator. Next, the red zone operator installs the wireline lubricator, which is pressurized using a backside pump. The frac iron is then pressure tested. If successful, the working valve is opened and the wireline tools can be lowered into the well. If the test is unsuccessful, more time is required to find and repair leaks in the iron. Using conventional methods, this entire process takes up to 45 minutes. The use of a latch or wellhead connection unit might reduce the time by 25 minutes.

Removing the wireline string after perforating and transitioning to fracturing the next stage is equally time-consuming, again taking up to 45 minutes depending on the efficiency tools employed. The process begins with the red zone operator closing the working valve manually, releasing the lubricator and bleeding off the pressure. At this step, closing the valve accidentally on the wireline can cut the wireline, resulting in a costly fishing job of at least a day of nonproductive time (NPT). If a ball is to be dropped, the red zone operator drops it onto the swab valve and then installs the frac head cap. The frac iron is then pressure tested. If successful, the red zone operator manually opens the swab valve, releasing the ball down the wellbore until its seat onto the frac plug, at which point pressure pumping begins.

FSCS can help improve frac efficiencies, increase completion rates and reduce costs per well. (Source: Downing USA)
Completions
FSCS can help improve frac efficiencies, increase completion rates and reduce costs per well. (Source: Downing USA)
Automating
well completions
A new system reduces stage-to-stage transition time from 45 minutes to less than 3 minutes while ensuring the safety of personnel.
Tim Marvel and Austin Johnson, Downing USA
T

he plug-and-perf (PNP) technique is the most prevalent completion method in North America’s shale and tight oil plays. The method provides the ability to pinpoint fracture locations with perforating guns, adjust stage spacing during the completion, achieve zonal isolation between stages and complete 100 or more stages in a horizontal well.

While preferred versus the sliding sleeve method, the traditional PNP method is highly inefficient and requires personnel to work at height in the red zone. Traditional wireline tool deployment requires three steps.

First, the working valve on the frac tree is shut down manually by a red zone operator. The wireline operator picks up the gun assembly and suspends it over the frac head and the red zone operator. Next, the red zone operator installs the wireline lubricator, which is pressurized using a backside pump. The frac iron is then pressure tested. If successful, the working valve is opened and the wireline tools can be lowered into the well. If the test is unsuccessful, more time is required to find and repair leaks in the iron. Using conventional methods, this entire process takes up to 45 minutes. The use of a latch or wellhead connection unit might reduce the time by 25 minutes.

Removing the wireline string after perforating and transitioning to fracturing the next stage is equally time-consuming, again taking up to 45 minutes depending on the efficiency tools employed. The process begins with the red zone operator closing the working valve manually, releasing the lubricator and bleeding off the pressure. At this step, closing the valve accidentally on the wireline can cut the wireline, resulting in a costly fishing job of at least a day of nonproductive time (NPT). If a ball is to be dropped, the red zone operator drops it onto the swab valve and then installs the frac head cap. The frac iron is then pressure tested. If successful, the red zone operator manually opens the swab valve, releasing the ball down the wellbore until its seat onto the frac plug, at which point pressure pumping begins.

Completions
Completions
A technician opens a valve at the end of fracturing operations on a Midland Basin well. (Photo by Tom Fox, courtesy of Oil and Gas Investor)
A technician opens a valve at the end of fracturing operations on a Midland Basin well. (Photo by Tom Fox, courtesy of Oil and Gas Investor)
Managing negative fracture
interactions with far-field
diverters and liquid
chemical tracers
The effectiveness of far-field diverters was evaluated by a Permian Basin operator using tracers.
Sudiptya Banerjee, Tracerco
F

or operators developing shale reserves, determining an optimal infill well strategy can be technically challenging and plagued by multiple sources of uncertainty. Even under the best circumstances, multiple reservoir properties combine to create a complex blend of matrix permeability, natural faults and fractures, and landing interval properties that make ideal placement highly variable from pad to pad—especially within stacked reservoirs.

While heterogeneity in the reservoir cannot be controlled, multiple strategies have been created to mitigate the risk of placing infill wells close enough for negative fracture interactions, instances where overlapping stimulated areas between wells undermines the economic value of one or both assets. These mitigation techniques almost exclusively focus on preventing fracture linkage, either by limiting fracture growth or by controlling the direction of propagation.

Production
Production
Managing H2S recovery
using analytics
Reduce emissions by improving sulfur recovery unit performance with self-service industrial analytics.
Julian Pereira, TrendMiner
O

il and gas (O&G) companies are continuously striving to optimize overall equipment effectiveness, performance and profitability within a highly volatile and regulated environment. Several of those regulations are coming from an increasing industry effort toward the reduction of emissions that affect both health and the environment. Initiatives are growing from industry and governmental groups. For example, O&G companies that operate in the U.K. Continental Shelf are stepping up to reduce carbon emissions to net zero by 2050 in the U.K. Another example is the decarbonization efforts led by the European Commission, which aims to initiate the transition toward “a climate neutral economy” by 2050. This will require the active involvement and investment of different industry, technology and governmental sectors for mid- and long-term solutions.

To start getting results today, it is key to take advantage of underutilized data in combination with process expertise that is already in place. Aim to improve process workflows to have a better and more efficient emissions control and reduction.

Production
Production
A VFD controls a rod pump. (Source: SPOC Automation)
A VFD controls a rod pump. (Source: SPOC Automation)
Innovative evolution of
variable frequency drives
Can new variable frequency drives restore profitability to oil and gas production?
Bobby Mason and Ted Wilke, SPOC Automation
A

t the start of the year, few predicted the turmoil that 2020 would inflict on the oil and gas industry. Oversupply and the collapse of demand created historic stresses on oil and gas prices. Long-term predictions for oil prices remain decidedly unoptimistic, and this low-price environment is the industry’s foreseeable future.

In response, producers are looking to squeeze every dollar from their budgets in both capex and LOE. Everyone it seems, producers as well as suppliers, are in a fight to survive.

Extraordinary cost of production
It requires an enormous amount of energy to extract and move a barrel of oil or gas from the ground. In fact, energy costs are a huge percentage of most producers’ LOE. According to the U.S. Energy Information Administration, the oil and gas business consumes 2.5% of all distilled petroleum products. Anything that can lower those costs directly impacts the bottom line.
Offshore
Image of The Weatherford
FIGURE 1. The Weatherford MOST Plus tool provides safe, single-trip wellhead recovery operations with minimal damage. (Source: Weatherford)
Advances made
in P&A of
subsea wells
A subsea wellhead retrieval tool delivers quick wellhead recovery, minimizes opex and reduces rig time
Jeffrey Toulouse, Weatherford
W

ell abandonment is a crucial and inevitable stage in the life cycle of all wells. While many in the industry have historically viewed decommissioning as an expenditure without financial return, this view is rapidly changing due to progressively stringent regulatory requirements and heightened ESG awareness. The higher operational costs and risk associated with offshore operations makes the permanent abandonment of subsea wells a worthy challenge, especially when the full scope of project logistics, vessel day rates, costs associated with the number of personnel on board and full suite of services is factored in.

As an increasing number of fields reach the end of their productive lives, and countries impose stringent regulations aimed at restoring the seabed to an undisturbed condition, subsea plug and abandonment (P&A) technologies are gaining traction. Time spent on subsea wellhead recovery is often the biggest determinant of the cost of an abandonment campaign, and hence the rightful area of focus for a value hungry industry.

There are two different approaches to well abandonment and wellhead recovery in the subsea environment, and both involve internal cutting of the surface and conductor casings, followed by recovery of the wellhead by internal or external latching.

Wellhead recovery systems evolution
First developed in 1992, the MOST (mechanical, outside-latch, single-trip) tool represents the world’s first one-trip subsea wellhead cut and recovery system. This field-proven system has performed more than 1,600 successful wellhead recoveries across every offshore basin in the world in water depths ranging from 26 m to 3,031 m. Featuring an external latching system, the system protects the internal surfaces of valuable recovered wellheads to preserve them for possible future use. The rugged versatility of the system has also enabled its use in a rigless P&A campaign through umbilical deployment and pairing with an abrasive jet cutting head.

The newly released second-generation MOST Plus system includes several technologies that improve tool capabilities and performance. This latest release packages a newly designed tension-cut mandrel, nonrotating flexible stabilizer (NRFS), large-diameter cutter and high-angle knives to provide pulling capabilities up to 1 MMlb, and record-breaking rotary cutting depths of 600 m. Deeper cutting depths are achievable by adding a precision mud motor.

The system latches and releases to inspect the cutting knives and confirm the cut without the need for tripping. The external latch protects the internal wellhead sealing profiles from damage, while also providing superior lateral support for the wellhead assembly to eliminate any lateral whipping that might impede cutting. An additional fail-safe feature enables releasing the outside latch by ROV, if required. Swarf buildup is prevented through a design that allows for a much larger flow area within the wellhead (Figures 1 and 2).

Offshore
Advances made
in P&A of
subsea wells
A subsea wellhead retrieval tool delivers quick wellhead recovery, minimizes opex and reduces rig time
Jeffrey Toulouse, Weatherford
W

ell abandonment is a crucial and inevitable stage in the life cycle of all wells. While many in the industry have historically viewed decommissioning as an expenditure without financial return, this view is rapidly changing due to progressively stringent regulatory requirements and heightened ESG awareness. The higher operational costs and risk associated with offshore operations makes the permanent abandonment of subsea wells a worthy challenge, especially when the full scope of project logistics, vessel day rates, costs associated with the number of personnel on board and full suite of services is factored in.

As an increasing number of fields reach the end of their productive lives, and countries impose stringent regulations aimed at restoring the seabed to an undisturbed condition, subsea plug and abandonment (P&A) technologies are gaining traction. Time spent on subsea wellhead recovery is often the biggest determinant of the cost of an abandonment campaign, and hence the rightful area of focus for a value hungry industry.

There are two different approaches to well abandonment and wellhead recovery in the subsea environment, and both involve internal cutting of the surface and conductor casings, followed by recovery of the wellhead by internal or external latching.

Wellhead recovery systems evolution
First developed in 1992, the MOST (mechanical, outside-latch, single-trip) tool represents the world’s first one-trip subsea wellhead cut and recovery system. This field-proven system has performed more than 1,600 successful wellhead recoveries across every offshore basin in the world in water depths ranging from 26 m to 3,031 m. Featuring an external latching system, the system protects the internal surfaces of valuable recovered wellheads to preserve them for possible future use. The rugged versatility of the system has also enabled its use in a rigless P&A campaign through umbilical deployment and pairing with an abrasive jet cutting head.

The newly released second-generation MOST Plus system includes several technologies that improve tool capabilities and performance. This latest release packages a newly designed tension-cut mandrel, nonrotating flexible stabilizer (NRFS), large-diameter cutter and high-angle knives to provide pulling capabilities up to 1 MMlb, and record-breaking rotary cutting depths of 600 m. Deeper cutting depths are achievable by adding a precision mud motor.

The system latches and releases to inspect the cutting knives and confirm the cut without the need for tripping. The external latch protects the internal wellhead sealing profiles from damage, while also providing superior lateral support for the wellhead assembly to eliminate any lateral whipping that might impede cutting. An additional fail-safe feature enables releasing the outside latch by ROV, if required. Swarf buildup is prevented through a design that allows for a much larger flow area within the wellhead (Figures 1 and 2).

Offshore
Trelleborg Firenut jet fire protection for bolted connections is subjected to fire testing. (Source: Trelleborg Offshore)
Fire protection and safety
Offshore
Trelleborg Firenut jet fire protection for bolted connections is subjected to fire testing. (Source: Trelleborg Offshore)
Fire protection and safety
for offshore topside structures
Passive fire protection will be key to mitigating the risk effects of fire, saving lives and assets.
Tony Westerlund and Isabelle Strømme, Trelleborg Offshore
A

s the offshore industry continues to push the limits when it comes to extending the life of assets and supporting operation in increasingly harsh conditions, the need for reliable and durable solutions that deliver proven performance has never been greater.

The focus on technical safety in oil and gas production is continuously increasing, with an expectation that all products and solutions are tested, qualified and certified to relevant regulations and standards. Companies need to be committed to designing high-performance, robust and reliable solutions that will improve safety and protect people, equipment, critical components and structures in the most demanding environments.

Fires in offshore or onshore installations can lead to immense destruction, making the uses and understanding of the properties of passive fire protection (PFP) materials crucial. PFP is typically used in defined areas highlighted in project-specific design accidental load specifications and is required to meet blast and fire requirements.

Digital Solutions
Digital transformation in the oil patch’s back office
Streamlining the billing processes can help companies thrive in tough times.
Image of Digital Transformation
Marcus Wagner, AcctTwo
W

ith the perfect storm of the COVID-19 pandemic and the recent collapse in oil prices, the pressure has never been higher for oil companies to cut costs to survive. Though these past few years the industry has seen rapid advances in tech innovation and application in drilling and services, the adoption of new technologies in the back office has lagged due to risk aversion and failure of many finance leaders to understand the benefits of modern technology, specifically true cloud accounting. With the accelerating waves of the retirement of the older generation and the emergence of younger leaders who grew up in the digital age, service companies are beginning to see that full-scale digital transformation has gone from optional to urgent.

An example of this trend can be seen at Silvertip Completions, a Midland-based provider of wireline and pumping solutions to the Permian Basin. When CFO Kyle Kirk joined the company three years ago, he had a vision that challenged traditional thinking about how finance operations should be set up. Having entered the labor force in 2000, he started his career at the same time software first began moving to the cloud.

Tech Watch
FIGURE 1. The digital twin is a virtual image of an asset, maintained throughout the life cycle and easily accessible at any time. (Source: DNV GL)
FIGURE 1. The digital twin is a virtual image of an asset, maintained throughout the life cycle and easily accessible at any time. (Source: DNV GL)
Trusting digital twins to deliver value
Digital twins are a rapidly developing technology widely expected to become a significant contributor to the future management of major industrial sites.
Kjell Eriksson, DNV GL – Oil & Gas
T

he concept of what many understand today as a digital twin has been around for several years under many guises, from model-based optimization to structural reanalysis systems. Recent developments in digital technology have enabled these virtual depictions of systems or physical assets to be used in decision-making processes and other activities that had not been possible in the past.

While the definition of what a digital twin is and what it is not is relatively wide, the consensus is that it allows system information to be available to predict performance through integrated models with the purpose of providing decision support.

Rather than think of a digital twin as a monolith, DNV GL believes it should be considered a collection of elements or components, of various levels of sophistication, each with their own distinct role and function (Figure 1).

Tech Trends
Digital service delivers real-time operational data and insights

Schlumberger has released its Performance Live digitally connected service that optimizes remote wellsite operations control while improving safety, efficiency and footprint. The service includes technology and domain expertise within a digital ecosystem, leveraging cloud-based applications and automated data workflows through a secure and robust data network. The Performance Live service provides customers with instant access to data and collaboration with domain experts, enabling faster, more informed decision-making for directional drilling, well logging, formation testing and other oil and gas operations. Automated end-to-end workflows simplify tasks that eliminate redundancy and deliver consistent service.

Contact tracing tool to ensure worker safety

Blackline Safety Corp. has released a new contact-tracing tool for industrial businesses, which makes it easy to proactively monitor a business’ social distancing effectiveness and trace person-to-person contacts if an employee tests positive for COVID-19. Such active measures help to improve employee confidence and morale, knowing that the business has further control over the health and wellbeing of every worker. Blackline has launched its new Close Contact report, which is immediately available to all current and future customers in its cloud-hosted Blackline Analytics software. This new report supports users of G7 safety wearables during work hours, to map the close interactions between employees. After hours and off the worksite, Blackline’s Loner Mobile smartphone app is available to provide complete tracing coverage for businesses and their personnel. Blackline’s Close Contact report and other contact tracing tools comply with the strictest privacy regulations and allow businesses to respect the privacy of the employee while keeping them safe.

US Highlights
Us Highlights Map
1
Alaska

A Prudhoe Bay, Alaska, recompletion was reported by bp Plc. The 03-27A Prudhoe Bay Unit is in Section 11-10n-15e in Umiat Meridian. The discovery was tested flowing 839 bbl of oil, 6.952 MMcf of gas and 7,693 bbl of water per day from Sadlerochit perforations at 10,375 ft to 13,000 ft. It was drilled to 13,133 ft (8,794 ft true vertical depth).

2
Wyoming

EOG Resource Inc. announced a Mowry and a Niobrara completion at a Johnson County, Wyo., drillpad in Section 12-47n-78w. The 53-1201H Orbit flowed 889 bbl of 51°API condensate, 2.712 MMcf of gas and 1,777 bbl of water daily from Mowry. It was drilled to 20,684 ft (11,368 ft true vertical) and is producing from a perforated zone at 11,654 ft to 20,592 ft. Gauged on a 32/64-inch choke, the shut-in casing pressure was 1,733 psi. About 40 ft to the west, 61-1201H Orbit initially flowed 803 bbl of 45.4°API oil, 749,000 of gas and 777 bbl of water daily from Niobrara. Drilled to 19,115 ft (9,929 ft true vertical depth), production is from perforations at 10,252 ft to 19,058 ft, and it was tested on a 26/64-inch choke with a flowing casing pressure of 1,182 psi.

3
New Mexico

Three Red Tank Field discoveries were announced in Lea County, N.M., by Oxy USA. The Bone Spring producers were drilled from a pad in Section 30-22s-33e. The Avogato 30-31 State Com 032H was drilled to 22,125 ft (11,948 ft true vertical depth). It initially flowed 4,742 bbl of oil, 7.824 MMcf of gas and 8,256 bbl of water per day from perforations at 11,850 ft to 22,031 ft after 51-stage fracturing. The Avogato 30 31 State Com 024H was drilled to 21,078 ft (10,961 ft true vertical depth). It was tested flowing 1,492 bbl of oil, 1.704 MMcf of gas and 1,190 bbl of water per day from fractured perforations at 10,610 ft to 20,985 ft. The Avogato 30 31 State Com 025H was drilled to 20,988 ft (10,785 ft true vertical depth), and it produced 2,127 bbl of oil, 2.664 MMcf of gas and 9,976 bbl of water daily from perforations at 10,572 ft to 20,896 ft.

International Highlights
International Highlights
1
Mexico

Pemex has received a permit to drill an exploratory test at appraisal well 2DEL-Quesqu in onshore Tabasco. The appraisal well be drilled in an ‘S’ trajectory toward an Upper Jurassic Kimmeridge (JSK) play, and the planned depth is 6,730 m. The well site is in AE-0053-4M-Mezcalapa-03 within the Cuencas del Sureste. Pemex expects to encounter gas and condensate in total resources of 62 MMboe.

2
UK

UK Oil & Gas has received a permit to drill and test the Loxley-1 Portland gas exploration/appraisal well in the PEDL234 license area. A sidetrack well, Loxley-1z, also has been permitted. The company plans to appraise the Portland gas accumulation, which was originally discovered in 1982 by ConocoPhillips about 8 km to the west at Godley-1 Bridge.

3
Norway

Neptune Energy made a hydrocarbon discovery in the Norwegian sector of the North Sea in PL882 at exploration well Dugong-1. Depending on testing results, a sidetrack may be drilled to further define the extent of the discovery. Area water depth is 330 m, and production is from a zone at 3,250 m to 3,400 m. Neptune Energy is the operator of PL882, Block 34/4 and Dugong-1.

On The Move
Illustration of person moving up in clouds
Illustration of person moving up in clouds
PEOPLE
Kjetel Digre has been appointed CEO of Aker Solutions.
Sistrunk headshot
Sistrunk
Aera Energy LLC’s President and CEO Christina Sistrunk has elected to retire, effective Oct. 1. Succeeding Sistrunk will be Erik Bartsch, currently the vice president of Safety and Environment, Integrated Gas and New Energies with Shell. As part of his transition into Aera, Bartsch will initially assume the role of COO and CEO designee. On Oct. 1, he will become Aera’s fourth president and CEO.
McDermott International Ltd. has appointed Tareq Kawash senior vice president for its Europe, Middle East and Africa region.
Thillerup headshot
Thillerup
Xodus Group has appointed Alexander Thillerup U.S. renewables vice president. He will head up a new office in Boston as the company looks to grow its offshore wind services across North America. Thillerup will be supported by Jamie MacDonald, who is relocating from Xodus’ headquarters in Aberdeen, U.K., to take up the position of director of operations.
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Publisher
darrin west

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Last Word
Businessman shouting into a megaphone
Boosting productivity in an era of E&P belt tightening
E&P companies must resist the urge to retreat from innovative technologies.
Businessman shouting into a megaphone
David Zahn, Ambyint
T

oday’s economic climate is punishing those who are operationally or capital inefficient. The 226 bankruptcies from January 2015 to May 2020 lays this truth to bare. The focus for those seeking to avoid a similar fate and survive an extended period of tight capital markets and low, volatile oil prices is on improving cash flow. At the heart of most E&P efforts is strengthening margins through production optimization and other cost reduction opportunities—in many cases through headcount reductions.

Prior to today’s economic climate, there were already too many wells and too few people to manage them. Operations groups are now stretched even thinner as they focus on ensuring production goals are met. A day filled with data analysis and fighting fires, unfortunately, does not allow much time for other important activities, such as production optimization. The challenge for E&P companies then becomes how to get more out of their existing workforce.

EPPlus September 2020 logo
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