DI G ITAL TR AN S FOR MATION
Eni pilots software
mapping emissions, fuel
use to specific activities
STEPHEN WHITFIELD, ASSOCIATE EDITOR
In drilling operations, reducing the fuel consumption of diesel
generators at the rig site has become a major focus for both
operators and drilling contractors alike, which means obtain-
ing accurate consumption and emissions data is critical to fully
understanding a rig’s carbon footprint.

Last year, Eni and Kwantis, a digital services provider , devel-
oped a greenhouse gas (GHG) software to track and map the
CO 2 -equivalent emissions associated with the fuel consump-
tion on Eni-operated rigs. The tool collects and analyzes data
from sensors placed at high-emissions points throughout the
rig and outputs the data in near-real time.

“The main purpose was to analyze the emissions per-
formance of the well construction process,” Daniele Farina,
Technology Innovation Project Engineer at Eni, said in a pre-
sentation at the 2023 Offshore Technology Conference in May.

“Let’s compare the monitoring systems for emissions that our
contractors use with this one so we can get a better overall
picture of the greenhouse gases coming from the rig and from
constructing the well. This will help us find the most emis-
sions-intense activities in our drilling operations.”
The software was installed as a module on the data analyt-
ics platform Eni uses to aggregate and analyze data from its
operated rigs. The system relies on the aggregation of high-fre-
quency data gathered daily from sensors placed on rig equip-
ment to provide an overall picture of the rig’s fuel consumption
and emissions. It collects fuel consumption data from the rig’s
engine on a given day, along with sensor data measuring power
consumption of various pieces of rig equipment, and combines
Daniele Farina, Technology Innovation Project Engineer at
Eni, talked at the 2023 OTC about a project aiming to iden-
tify the most emissions-intense activities on a rig.

Continued on page 23
22 “We need to eliminate the need
for unnecessary manual data
collection. That’s going to be big
in freeing up the rig crew to handle
more critical preventative and
corrective maintenance tasks.”
- John Dady, Seadrill
rig control system, it will automatically send a corrective work
order to the driller if it recognizes vibration patterns that align
with equipment malfunction, indicating a need to inspect the
equipment. “The sensor has been extensively deployed in other industrial
sectors, managing remote sites that necessitate the use of equip-
ment that can handle rigorous daily operations in rough environ-
ments, but they have not been used on an offshore rig,” Mr Dady
said. “We think that, because they’ve shown durability working in
different environments, they’re an ideal choice for offshore since
that environment demands robust and dependable equipment.”
The pilot project will be conducted on the West Neptune drill-
ship, which Mr Dady said was selected because of its location.

The rig is working in the US Gulf of Mexico, close to the Seadrill’s
Houston office. Installation of the sensors on the rig, as well as
any necessary ISIT (information systems and information tech-
nology) upgrades to support the sensors, is expected to be com-
plete by the end of this year.

However, that time line will depend on Seadrill’s ability to
access the primary load path drilling equipment, which includes
the drawworks, crown block, traveling block and top drive. This
can only be done during maintenance periods when the BOP
is brought to the surface between wells and changed out with
another BOP.

Once the sensors are installed, the pilot will run for three
months, during which time the vibration data gathered from the
sensors will be measured against manual measurements. If the
sensors prove reliable, Seadrill plans to install them across its rig
fleet over the course of 2024.

“The time frame we set for this project should give us an idea
of how well the sensors and system as a whole performs,” Mr
Dady said. “The sensors are giving us much more data than the
manual measurements do, with the major benefit of not having to
take time out of service and take the measurements. That said, I
believe the biggest benefit is the fact that we won’t need the rig
crew to go out and take these measurements anymore, reducing
the burden on them.”
Improving sensor material quality
Baker Hughes has multiple brands, including Druck,
Panametrics and Reuter-Stokes, devoted to designing sensors
for the tools it uses to gather and process data for the monitoring
systems its customers use in the oilfield.

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DI G ITAL TR AN S FOR MATION
Continued from page 22
Honeywell’s Searchline Excel Plus gas detector is designed to
identify leaks of combustible and volatile hydrocarbon gases,
which can negatively impact safety on the rig.

Through its Reuter-Stokes division, the company has devel-
oped gamma ray sensors that provide greater light output, energy
resolution and sensitivity compared with previous models. These
sensors, along with third-party sensors, are used to collect and
feed data into Baker Hughes’ automation solutions, wireline log-
ging tools and intelligent production systems. They can also aid
in directional drilling, which requires powerful detection systems
that can withstand high temperatures, shock and vibration.

“Our drilling services require high-precision sensors for a
comprehensive understanding of downhole environments and
formation characteristics. The better our sensors are, the more
we can help our clients optimize their processes, maintain critical
margins and see noticeable time and cost savings in their opera-
tions,” said Ricardo Tirado, IPS Product Line Director.

As drillers and operators seek to drill deeper, faster wells while
achieving precise wellbore placement, the limitations of these
sensors have become more apparent. To improve sensor quality,
Baker Hughes has looked to improving their material .

Sodium iodide crystals are commonly used in gamma ray sen-
sors. The crystals absorb gamma radiation and emit a burst of
light, which is collected and turned into a signal by a photomul-
tiplier tube. The detector’s electronics then grab that signal and
store it for transmission. However, sodium iodide gamma sensors
increase light loss and slow pulse response times when operating
in elevated temperatures.

them with daily drilling report (DDR) data input by rig crews.

This allows the system to correlate the fuel usage and power
consumption with a given operation listed on the DDR.

This combination of DDR data, equipment power usage and
fuel consumption data trains the software to automatically
discriminate between different operations, such as tripping,
drilling, circulating and reaming. Effectively, the system associ-
ates fuel consumption and equipment power usage with a given
operation, allowing it to identify the rig state in real time. This
data is displayed on an interface along with the power con-
sumption and fuel usage. An algorithm built within the software
converts the fuel consumption to GHG emissions, and the sys-
tem can then associate the emissions to given equipment and
activity on the rig. The emissions calculation is also displayed
in real time.

In 2021, Eni and Kwantis conducted a field trial covering 12
wells from seven workover rigs and two wells from two land
drilling rigs operated by Eni. The average GHG emissions of each
well was measured and compared against baseline averages
using historical data for the same rigs in 2020. The two sets of
values matched closely enough to confirm the consistency of the
tool in assessing emissions coming from operated rig activities.

A second field trial was conducted on a jackup in the US
Gulf of Mexico in 2022. For this trial, the companies sought to
test the tool’s accuracy in allocating GHG emissions to a given
activity. Six categories of activities were devised – drilling,
drilling connection, reaming/washing, casing run, tripping and
other – and combined rig sensor data with power metering to
calculate the amount of energy required during each activity
category. These values were compared against emissions and
fuel consumption estimates provided by the drilling contractor.

The data gathered from the emissions tool in the second field
trial showed a 4.8% increase in GHG emissions compared with
the drilling contractor estimates, which Mr Farina said was a
“reasonable” discrepancy and confirmed the consistency of the
emissions tool. The tool also showed that tripping operations
accounted for around 75% of the overall emissions, even though
only 40% of this trial period was spent on tripping activities. Mr
Farina said this was mainly due to several weather-induced
operational stops, which impacted tripping at restarts.

Eni and Kwantis are currently evaluating the results of the
field tests and determining how to move forward with incor-
porating the tool into Eni’s operations. Mr Farina said the
companies are looking to increase the frequency with which
it can acquire fuel consumption data – the sensors used in the
field tests processed fuel usage in 5-second intervals – as well
as algorithms that can connect the types of fuel blends used for
engines with emissions.

“This is continuous work that we’re doing on this system
today,” he said. “Our focus right now is on trying to improve
the system so we can improve the quality of the operation
itself.” DC
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