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.”

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.

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.”

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.