GEOTHERMAL DRILLING
Insulated drill pipe offers new
tool to enable efficient drilling
of ultra-deep geothermal wells
Testing in New Mexico, Utah FORGE project
illustrates pipe’s effectiveness in lowering
temperatures, protecting downhole equipment
BY STEPHEN WHITFIELD, SENIOR EDITOR
To drill the ultradeep, high-temperature
wells needed for geothermal applications,
it’s critical to make sure that downhole
tools are protected. Insulated drill pipes
(IDP) have been used in oil and gas drilling
to maintain sufficiently low temperatures
for the drilling fluid as it moves downhole,
and thanks to a recently launched effort
from Eavor Technologies, they can now
help drillers and operators better navigate
the ultra-high temperatures often seen in
geothermal wells.

“Insulation is really important when
you’re drilling hot resources,” said Alex
Vetsak, Well Construction Advisor at Eavor.

“The geothermal business requires you
to drill as hot as possible – we’re talking
temperatures downhole exceeding 500°F.

When we’re talking about these numbers,
it’s critical to be able to deliver cold drill-
ing fluid from the surface to the downhole
tools. You don’t want to burn the sensitive
electronics at the bottom, and if your fluids
are exceeding the temperature limit for
those tools, they will burn and fail.”
The temperature ratings of different
bottomhole assembly (BHA) components,
such as the measurement-while-drilling
(MWD) and rotary steerable systems (RSS),
are particularly significant limiting fac-
tors, Mr Vetsak said at the IADC Drilling
Engineers Committee’s Technology Forum
in Houston on 1 November. To address this
issue, Eavor developed its IDP as part of a
suite of tools aimed at enabling high-tem-
perature drilling. By insulating both on the
outside and inside of the pipe with several
layers of a proprietary coating solution,
the heat transfer between the drilling fluid
traveling down the drill pipe and the hot
fluid traveling up the annulus is reduced.

This results in cooler fluid being delivered
to the BHA.

When used in conjunction with Eavor’s
other technologies – the Rock-Pipe drill-
ing fluid, its turbogenerator, and its mag-
netic ranging technology – the IDP helps
create what the company calls an “Eavor-
Loop,” a closed-loop geothermal system.

An Eavor-Loop is the connection of two
vertical wells with horizontal multilateral
wellbores that create a closed-loop sys-
tem. The company’s proprietary working
fluid – the fluid used to generate heat
from a geothermal reservoir – is selected
and added at surface, then circulated to
harvest heat. Eavor-Loops can also be
directionally drilled from centralized sur-
face pads.

The company first manufactured a full
IDP string in 2022 and tested its perfor-
mance in a geothermal formation in Q3-Q4
that year at the Eavor-Deep project in
New Mexico. An 18,000-ft well was drilled,
along with a sidetrack, in a granite forma-
tion with rock temperatures of around
480°F. The project aimed to demonstrate
all the technical elements required to con-
struct a commercial Eavor-Loop system
in deep, high-temperature hard rock, and
testing focused primarily on gathering
temperature measurements from MWD
tools. In this well, the IDP was able to help
the well maintain circulating tempera-
tures below 300°F at the bottom. Compared
with the circulating temperatures from
using a standard drill pipe – which Eavor
calculated would be approximately 370°F,
according to a transient thermodynamic
drilling model – the IDP reduced downhole
circulating temperatures by as much as
194°F, with a median of 142°F. Drilling was,
therefore, enabled by keeping the tempera-
ture below the 300°F tool limit.

Alex Vetsak, Well Construction Advisor at Eavor Technologies, spoke about the test-
ing and performance of the company’s insulated drill pipe for geothermal wells at
the IADC Drilling Engineers Committee’s Technology Forum on 1 November.

38 JAN UARY/FEB RUARY 2024 • D R I LLI N G CO N T R ACTO R
“Insulated pipe”
continued on page 40




DRILLING MARKETS
Comparison of different models
for integrated services contracts
shows how cost savings fluctuate
Petronas shares its process behind identifying
the ‘lump sum cost per hole section’ model
as having the highest cost savings potential
BY STEPHEN WHITFIELD, SENIOR EDITOR
Cost optimization is a critical aspect of
any drilling operation. Humam Al
Darkazly, Senior Wells Engineer at
Petronas, estimated that drilling costs
make up between 50% and 70% of the
CAPEX for the operator’s typical develop-
ment projects. To help mitigate financial
risks and uncertainty, the company is
increasingly relying on integrated drilling
services (IDS) contracts, both to achieve
cost efficiencies and to allow for greater
adaptability to changing market condi-
tions. “We’re trying to maximize cost savings.

We want to ensure profitability regardless
of any volatility we may see in oil price,
ensure financial stability and minimize
risk,” Mr Al Darkazly said at the 2023
ADIPEC on 3 October.

However, there is no one-size-fits-all
contracting model that can guarantee the
most cost savings. So, Petronas utilizes
three cost models in its tendering process
for IDS contracts: lump sum cost per well,
lump sum cost per meter drilled (as deter-
mined by the estimated total depth of the
well), and lump sum cost per hole section.

In his presentation, Mr Al Darkazly com-
pared the advantages and disadvantages
of each model based on an evaluation the
operator conducted on IDS contracts in the
Middle East.

As part of the evaluation, the operator
compared contract terms for the drilling
of various wells in an unnamed Middle
East reservoir drilled in 2022. For the
evaluation, three separate land rigs that
possessed identical specifications were
contracted, which Mr Al Darkazly said
ensured “consistency and comparability.”
Each well employed an identical casing
design. Petronas provided the necessary
casing, tubing and wellhead, while the
drilling contractor was responsible for all
other materials and services required for
the drilling operation.

Of the three models, Petronas noted the
most cost savings was achieved under
the cost model structured by hole sec-
tion drilled – in fact, savings were up to
50% more than the other two cost mod-
els. The calculated percentage of saving
was based on the prices specified in the
awarded contracts, and Mr Al Darkazly
said savings from the hole section model
were due to the effective categorization of
hole section prices based on well inclina-
tion. Under the hole section model, the drill-
ing contractor has the opportunity to pro-
pose lower costs for wells with lower
inclinations. This is primarily because,
with these types of contracts, the total
number of meters drilled is typically less
compared with higher-inclination wells.

As a result, the contractor can allocate
fewer resources while reducing drilling
and tripping times, leading to less equip-
ment usage, manpower and associated
expenses. Additionally, lower inclination
wells generally entail reduced drilling
complexities and risks compared with
wells with higher inclinations. The con-
tractor is then able to offer more competi-
tive pricing for these wells.

The other two models – cost per drilled
well and cost per meter drilled – do not
incorporate well inclination as a factor,
since well inclination is only useful for
determining the lengths of a given hole
section. However, although well inclina-
tion does not have a direct impact on the
number of wells drilled or the total depth
of a given well, it does mean that the drill-
ing contractor assumes the maximum
risk regardless of the well’s inclination
and are likely to incorporate that into their
bid. In such cases, the contractor must
account for the possibility of drilling more
meters and encountering more challeng-
ing conditions downhole, resulting in a
higher proposed price to compensate for
the added risks.

By integrating well inclination into the
hole section model, the contractor can
assess and evaluate drilling conditions
more precisely, allowing for more opti-
mized bids based on the specific complexi-
ties and risks associated with each well’s
inclination. This approach ultimately
leads to the additional cost savings com-
pared with the other two models.

Even though Petronas saw greater
cost savings overall with the hole sec-
tion model, Mr Al Darkazly noted that the
specific savings Petronas saw in a given
well depended on external factors. Such
factors could make the other two models
more palatable to other operators utilizing
IDS contracts.

For instance, while a contract utilizing
the drilled wells model has a fixed budget
dependent on the number of wells to be
drilled, the hole section model is based on
fixed drilling targets, and changes to the
well target by reservoir engineers can neg-
atively impact the budget estimation. Also,
S-shaped wells may increase costs for the
hole section model due to increased well
inclination, though some operators may
opt for shallower kick-off points and high-
er doglegs to reduce inclination and lower
costs. Well inclination has no impact on
well cost for the drilled wells and meters
drilled models because it was not incor-
porated into either model, so if the inclina-
tion category is not specified, the operator
may prefer to use one of those models.

The drilled wells and hole section mod-
els also provide easier invoice processing
than the meters drilled model because
they are fixed costs. More auditing is
required to process invoices in the meters
drilled model, as the operator must check
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39