CRITICAL ISSUES IN DRILLING & COMPLETIONS
internet system). In the Gulf of Mexico,
we can now get 10 to 50 times faster data
transfer speeds compared with conven-
tional rig satellite communications.
We have more work to do to fully uti-
lize that medium, but the speed of data
transfer is approaching a level where it
makes sense to operate things from shore.
I believe there will be a progressive move
in that direction over time.
When you get latency shrunk down,
you start approaching truly real-time
data. Is that going to be a game
changer for remote operations?
That’s right, but I think the most impor-
tant thing is not so much the remote
operation bit. It’s more about making sure
that the person who’s in charge of the
equipment can be more of a systems com-
mander than an equipment operator, that
the equipment is thinking for itself. We’ll
be using machine learning and algorithms
to make the equipment work in a sophisti-
cated manner that is not hampered by the
human’s imperfect execution ability.
Do you see that automation, in its cur-
rent state today, is bringing concrete,
quantifiable value to drilling opera-
tions? You’re definitely seeing it now.
Automatic tripping is becoming a rela-
tively common thing. We have that on
the West Saturn today, for instance. It’s
progressively making its way through the
system of work. We don’t have a fully
automated system, but we have sequences
of work where we can automate them
and have confidence in their ability to be
robust through time and deliver results
better than a human-managed process
can. However, drilling a well is a complex
series of interrelated steps, so what peo-
ple have been focusing on is doing those
repetitive steps where the removal of
human variability is most valuable.
We’re also seeing that sensors have
plummeted in cost and skyrocketed in
quality, so today’s rigs are much more
sensate than they were even five years
ago. And as the cost of these sensors gets
lower and the amount of information we
can gather with them becomes richer, the
possibilities open up for not only automat-
ing sequences of work but also automating
safety processes, things like automated
BOP control. Instead of waiting for some-
one to go to the BOP panel and close an
annular or the pipe rams, we can have
a system powered by sensors to make a
decision. In what aspects of drilling projects
have you seen more collaboration
between drilling contractors and
operators? Going forward, what are
some things that either party can do
to advance collaboration?
I think the data environment is impor-
tant. Historically, there’s been a separation
between the data that’s gathered about the
control of the equipment at surface and the
data that’s acquired subsurface.
There have been a lot of issues about
confidentiality, but to optimize what’s hap-
pening downhole, you need the informa-
tion that’s gathered from the equipment
that rotates the drill string. We can opti-
mize our rate of penetration against the
objectives of the operator if we have more
data about what’s happening downhole. I
think a commonality in terms of that data
pool has some great benefits for all parties,
not just operators and drilling contractors
but also service companies.
There are some great lessons that off-
shore can learn from the Lower 48 onshore,
in terms of how the drilling contractor has
acted as the wellsite integrator to bring
everything together into one data pool and
reduce the number of service interfaces.
I think we also need to revisit the con-
tractual bargain. There’s a lot of work to
be done around business models with
regards to alignment of purpose and allo-
cation of risk. The model that’s currently
in use today is a bit shabby, frankly, and
is worthy of some reconsideration and
re-contemplation. That will need to be
approached from both sides.
You mentioned allocation of risk. How
has that changed in contracts in
recent years, and what work do you
think needs to be done to make that fit
with the current drilling environment?
The typical allocation of risk has been
that the reservoir pollution from the well
was the operator’s concern, and pollution
from the rig, as well as the safety inci-
dents and control of our equipment, was
our problem. The problem is that, over the
years, those interfaces have been chal-
lenged and moved around due to changes
in the insurance market.
Today, the operators have very little
insurance to cover their own wellsite
risks. Instead, what they seek to do is take
the risk that they accept in a drilling con-
tract and put that on their balance sheet.
In doing so, they now have an interest
in redrawing the traditional contractual
bargain to their advantage through time
by imposing carve-outs and weakening
indemnities generally.
Through downturns, the offshore drill-
ing contractors have been forced – as a
commercial necessity – to accept worse
and worse terms. Now, we have levels
of responsibility and exposure that are
unmatched by the commercial reward
that’s on offer. You have company-killing
risks – around things like blowouts, pol-
lution events and the conduct of person-
nel – that are completely disproportionate
to the incremental revenue that we might
earn once you’ve allocated all the costs of
running a drilling rig.
There are a lot of uncertainties in off-
shore drilling, and I would argue that we’re
not fully recompensed for the risks that
our shareholders are underwriting.
Is the dayrate model an adequate
model for this economic environ-
ment? Does the industry need to move
on to something else?
It doesn’t really align the interests of
operators and drilling contractors, but the
problem has always been that no one
wants to move on to another model. The
customers want to get whatever price is in
the market. They don’t want to get caught
paying too much, but they also don’t neces-
sarily want to get caught paying too little.
I think that the dayrate model has prov-
en to be a crude but ultimately effective
measure that gives the drilling contractor
visibility in terms of an earnings profile,
but I am not sure it drives the best out-
comes at the wellsite or through time. DC
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