In June 2023
ExxonMobil CEO Darren Woods reported at the Bernstein Strategic Decisions
conference that Exxon was planning to improve fracking efficiency by getting
more oil out than currently. He stated that with current methods as little as 10%
of oil was being liberated in some fields and that improvements in both
drilling and hydraulic fracturing could liberate more oil. There is less of a
problem in natural gas wells since the methane molecule is much smaller than
the “heavy” hydrocarbons that make up oil. He noted that Exxon was working in
two specific areas to increase oil recovery efficiency: 1) more precision with
fracking along the wellbore and 2) keeping the cracks or induced fractures forced
open by water pressure open longer. Sand is pumped down to keep the fractures
open. He did not elaborate about any specific techniques. He simply notes that
those are the two areas where new promising technologies are happening. Increasing
fracking precision along the wellbore suggests things like perforation cluster
spacing or targeted perforations. Keeping fractures open longer suggests different
frac sand sizes and types or better sand emplacement in the induced fractures.
Oil and gas
production increases in recent years involved adjustments to hydraulic
fracturing such as closer spaced frac stages, more proppant per stage, and
higher pumping rates. In addition to that better wellbore targeting and target zone
maintenance have helped improve production.
Aside from hydraulic
fracturing there are a few other ways to initially enhance oil and gas production,
A common method is acidizing wells, particularly wells producing from carbonates,
or limestones and dolostones. There are some new methods and formulas in acidizing.
The acids eat away carbonates which enhances porosity and permeability in
carbonate reservoirs.
It is known
that current oil production methods can leave much of the oil in the ground, up
to 90%. That certainly suggests there is room for improvements to unlock
remaining oil. Natural gas production can also be improved in some reservoirs. New
methods of improved oil recovery (IOR) and enhanced oil recovery (EOR) are
looking promising for increasing oil production. IOR and EOR seem pretty synonymous,
but EOR usually refers to enhancing oil production with water flooding or CO2
flooding. Water and CO2 are pumped into the formation to gather and push more
oil out.
Single Shot IOR Tech: Water Alternating Gas Injection
with NGL’s (Propane and Butane)
Universal
Chemical Solutions (UCS), at the behest of Oil Technology Group, began researching
and testing EOR with ‘water alternating gas injection’ using propane and butane
in 2019. Single shot IOR is an offshoot of this so-called gas frac technique where
NGLs are injected to help move oil out of the reservoir. Two UCS engineers and
another engineer from C3 Oilfield Services, who previously worked for Gas Frac
Energy Services, combined for R&D for a year of work and came up with and
patented Single Shot IOR technology. The purpose of the technology is to re-establish
the wells’ original stimulated rock (or reservoir) volume (SRV). Some reservoirs
are sensitive to water and single shot tech offers an alternative to water-based
treatments. Injected NGLs are able to penetrate the formation.
It is believed
that longer laterals result in more frac water trapped in the formation which
can impede oil production. “The Single Shot IOR treatment employs a
surfactant that has an affinity for water and will transfer from the NGL to
water, making the water less viscous and letting it flow much more easily.”
The chemicals used, surfactants and inhibitors, are designed to work in propane
and butane. The method also employs diversion techniques to move the NGLs out into
the formation from the well’s heel though the article doesn’t really explain how.
This is the first NGL treatment that employs surfactants and diversion. The goal
is “to eliminate emulsification of the NGLs or the oil/water it contacts
downhole.” Thus far the tech has not yet been used on horizontal wells due
to the higher horsepower requirements for pumping/injecting but has been used
successfully on 4 vertical wells in Texas and Oklahoma. The treatment has been successful
in addressing condensate blockage and water block in water-sensitive
formations.
Nitrogen Nanobubbles, aka “Fluffy Water” for EOR
Another
promising technology is the use of nitrogen nanobubbles, also known as “fluffy
water,” for improving oil production. This is like the bubbles in Guinness beer
or in nitrogenated Coca Cola. Scientists from Nano Gas Environmental developed
a nanotechnology that could increase the amount of gas a liquid could hold. “While
the amount of the gas increase has not been fully measured, Bland and his team
think it is 3,500 times the amount of gas that would be in water naturally.
Nanobubbles are invisible under a light-based microscope but become visible and
measurable with a device called a NanoSight.” That is a huge difference in
gas capacity! “That extreme concentration alters the liquid’s physical,
biological and chemical characteristics. The company has used all three for
EOR, cleaning produced water and eliminating dredging for sewage lagoons.”
Surface
tensions are reduced as the nanobubbles attach to the rocks making them “water
wet” which helps move the oil. The bubbles are as hard as steel when under high
pressure and that hardness along with their small size makes them function somewhat
like fracking and frac sand in pushing oil out of fractures. The company first
used the technique to clean produced water, extracting more oil from it. It has
also been used to reduce hydrogen sulfide (H2S), iron sulfide, and total
suspended solids (TSS), which renders the produced water reusable. Nanobubbles
can also recover oil and remove solids from tank bottom water, which can
temporarily increase API gravity of the oil, allowing it to flow and more oil to
be sold. The patented process is called Nitro Nano.
Nitro Nano
tests in the lab with oil-infused cores, comparing it to tests with EOR-ready
saltwater, have yielded very good results. “The company has now tested the
process on four stripper wells. The company said each well saw production
increase to 200% of the normal rate. A Kansas well in a limestone formation
achieved a 540% production improvement after 90 days, and was still at 200%
after 150 days. The other three are in sandstone formations in Oklahoma.”
Those phenomenal results are from single treatments injected close to wellbore.
It is thought that further injections at time intervals can keep improving
production and that the treatments can be pushed further from the wellbore. As
far as materials, it’s just water and nitrogen. Plans are to scale up the
technology and use the nitro-nanobubbles waterfloods for EOR. If the results
continue to show such improvements this could be a major new EOR technology.
New and Improved Acidizing of Carbonate Reservoirs
Hydrochloric
acid has been the old standard for acidizing wells. “Acid jobs” are used to
improve production in carbonate reservoirs. Commonly, a 15% HCL solution was
used. Sometimes a higher concentration of 28% is used.
Baker Hughes
and World Oil presented a webcast in June 2023: The Evolution of Carbonate
Acidizing to Unlock Full Reservoir Production Potential. Injecting acids
into wells to increase production began back in 1896. Nearly 70% of the world’s
hydrocarbon reserves are in carbonate formations. The two goals of an acid job
are to remove or bypass damage (often scale) and to access or contact more
formation by dissolving carbonates with acid. These days horizontal wells are deeper,
hotter, and longer. Such wells require more pumping horsepower for stimulation
and larger volumes. Hotter wells are more susceptible to corrosion, but acid
has more dissolving power in those hotter reservoirs. Retarded or delayed acid
systems extend reservoir contact and penetrate at high rates at the same
viscosity rather than changing viscosity as in past methods. Polymers and
emulsions in the past were used for chemically retarding, but really, they block
rather than chemically retarding.
Baker Hughes developed their Sta-Live Extreme (SLE) retarded acid system to penetrate
further into formations. Emulsified acid systems have higher viscosity and
higher friction pressures. The additives (polymers) can lead to formation
damage (form filter cakes). Blending on location takes time. SLE is mixed on
the fly and simpler. Core tests show SLE penetrates further, making a more
dominant wormhole. Much lower friction, better wormholing, and further penetration
lead to better acid distribution.
Source: Baker Hughes. World Oil Webcast slides
Source: Baker Hughes. World Oil Webcast slides
Baker Hughes’
Stim Vision models acidizing and has found a good match with models and
reality. The software can be used to manipulate designs on-the-go. It can be
pumped at higher rates without exceeding frac gradient. SLE improves
penetration at higher temps but other retarded systems decrease a little at
higher temps. SLE also works better in dolomites than other retarded acid
systems.
In the webcast
Baker Hughes presented two case studies: Case study 1 – Middle East – no
increase with emulsified acid, 1000 Bbls/day increase with SLE. Case study 2 –
Brazil -no increase with emulsified acid – 3000 Bbl/day increase with SLE.
These results suggest that SLE will be a game-changer. It won best new
technology at Baker Hughes for 2023.
The Stim
Vision software can model for different reservoirs and helps predictability. SLE
can be modified to work in sandstones. It can work in old wells and in wells
with high water cut, increasing oil cut and maintaining or decreasing water cut.
It can be applied in acid fracturing since the viscosity does not change. SLE
aims to give low corrosivity without sacrificing the dissolving power of HCl.
It can inhibit corrosion with magnitudes less of corrosion inhibitors. It is best
mixed on the fly, which is advantageous if there is a delay, which can cause
need to remix or reformulate a batch mix. Hydrofluoric acids, or mud acids are
used to acidize sandstones but that can lead to the acid attacking cementation
materials in the rock which can liberate fine particles that can plug permeability.
Baker Hughes is working on a solution that can leave sandstone cements intact. Risk/reward
profiles lead to candidate selection. H2S affects corrosion inhibitors so there
is a need for more of them when this “sour gas” is present. SLE is good for
fractured carbonates. With matrix porosity near-field diversion is needed.
Far-field diversion is needed for fractured reservoirs.
EOG’s New Stealth Frac Design: What’s the Recipe?
EOG recently
announced success with a new frac design that increased production in the
Permian Wolfcamp formation by 20% and well EURs by 22%. Analysts tried to get
them to divulge the recipe with no luck. They had been testing the technique
since first using a version of it in the Eagle Ford in 2016. The design was
tested in 39 Wolfcamp wells and EOG expects to use it in about 70 of 350 Delaware
Basin wells this year. They noted that it works better in some rocks than in others,
although they are now using it in the Eagle Ford as well. Indications are that
it is only slightly more expensive. They are testing the design cautiously in
deep formations and plan to test it in all their emerging plays. It is most
applicable to deeper targets, but they plan to test some shallower targets as
well. EOG president Billy Helms noted that depending on the mechanics of the
rock it’s being applied to, “it involves constructing the wellbore in a way
that lends itself to this new technique.” It has also been said that it is
applicable to both oil and gas plays.
Stimulation with Ammonia (NH3) and the Ammonia Frac
I came across
a LinkedIn post on my feed about EOG’s stealth new frac design and in the
comments, someone posted a link to posts by a stimulation company from Oklahoma
City called Green Horse Energy that does stimulation with NH3. Of course, that
made me wonder if EOG was using ammonia as part of their new frac design. I did
a search on “ammonia fracking,” making the mistake of adding the K and coming
up with anti-fracking activist stuff. Then I searched “ammonia frac” and the
first thing that came up was a patent by Gary Lee Travis and assigned to EOG
Resources. The patent was filed in December 2014. That jives with their first
use of their new frac design in 2016. It does say that the status is “abandoned”
but is still quite suggestive. I don’t know for sure, but I strongly suspect
that liquid ammonia is a part of EOG’s new frac recipe. Green Horse Energy
touts NH3 stimulation for significantly increasing production in older wells.
They posted results of two Austin Chalk wells: one with a 150% increase in
production, and one with a whopping 1400% increase in production from 1Bbl per
day to 14Bbls per day that later leveled out at 8.8 Bbls per day. The Austin Chalk
contains several volcanic ash beds, and that ash has a tendency to plug
fractures in the wells. Chemical treatments, perhaps including NH3, are used to
re-open the fractures. Thus, perhaps the Austin Chalk is not the best reservoir
for determining the magnitude of potential of NH3 stimulation.
One thing
liquid ammonia can do down hole is to remove and prevent scale and corrosion.
Scale is usually a buildup of calcium carbonate and iron sulfides. Hot
reservoirs have higher rates of corrosion. This is well known in hot oil and
gas reservoirs and in geothermal wells. Some geothermal wells can have
especially corrosive fluids. Below is the abstract from the patent assigned to
EOG:
“Abstract
“A fracturing fluid that includes the combination of
liquid ammonia and a proppant, and a method for fracturing an underground
formation by pumping this fracturing fluid into a wellbore that extends to the
formation. The process includes generating pressure in the wellbore, creating
fractures in the formation using the liquid or gelled ammonia and proppant
slurry, and releasing pressure from the wellbore. The ammonia released from the
liquid or gelled ammonia helps stabilize clays in the formation and the
proppant helps to maintain the fractures in the formation.”
Thus, as it states, ammonia acts as a clay stabilizer.
Frac fluids consisting of mostly water may cause the clays of formations with
high clay content to swell and eventually plug the pore throats of the reservoir
rock, resulting in unrealized production. This effect is known in low permeability
sandstones and shales with high clay content, both of which make up many oil
and gas reservoirs.
Liquid ammonia
may be gelled or cross-linked. According to the patent info ammonia may be
present from 25% to 96% by weight of the frac fluid. Other frac fluids like LPG
(propane and butane) and CO2 may have a similar effect but cost more than
liquid ammonia. In addition, CO2 caused scale when mixed with water so is less
desirable.
Green Horse
Energy emphasizes dissolution of mineral scale deposits as the superpower of
NH3:
“Unparalleled Scale Dissolution: NH3 possesses
excellent scale-dissolving properties. When introduced into the system, it
reacts with mineral scales, such as calcium carbonate or iron sulfide, breaking
them down and preventing their accumulation…
Enhanced Well Integrity: Scale deposits can compromise
the integrity of your wells, leading to reduced efficiency and costly
maintenance. By implementing NH3 scale breakdown treatments, you can protect
your wellbore and production equipment from damage caused by scale-related
corrosion…
Improved Flow Assurance: Scale deposits can cause
significant flow assurance issues, resulting in reduced hydrocarbon recovery
and increased operational costs. NH3 effectively mitigates these concerns by
preventing scale formation and maintaining the integrity of your flow paths…
Environmentally Friendly: NH3 offers an
environmentally friendly solution to scale management. As a naturally occurring
compound, it presents a sustainable alternative to traditional scale removal
methods that may involve harsh chemicals…”
Addendum July 27, 2023.
A new article in Hart Energy by Paul Wiseman - Squeezing
Oil from Stone: The Quest to Improve Shale Recovery – highlights more
promising methods of increasing hydrocarbon production, and some of these new
techniques may have influenced Exxon’s suggestions of recovery improvements on
the horizon. The article focused on four techniques. The first technique
covered is the Tapered Frac Design. This method is based on work
by the University of Texas at Austin’s Mukul Sharma. Sharma’s previous research
shown that in addition to propped induced fractures wells also produced from smaller
unpropped induced fractures. Data used to determine the presence of these unpropped
induced fractures include micro-seismic data, production history matching,
tracer data, pressure communication between wells and calculations on the fate
of the injected fracturing fluids. Sharma noted: “The well completion, the
number and clusters and the number of perforations in each cluster, as well as
the pumping schedule, are things that we can control and have a major impact on
the geometry of the fracture network. Of course, the natural fracture network
and the heterogeneity in the reservoir have a big influence as well.” The
article notes: “They observed that a geometric cluster design, in which all
clusters contain the same number of perforations, often creates heel-dominated
fractures. This can result in a loss of production from the other fractures.
Adding more perforations to the toe, referred to as tapered completions, can
provide more uniform proppant and fluid distribution.” UT developed a
software package, Multifrac-3D, which models frac and flowback. According to
the models, production could improve by 30-40%.
The next
technique mentioned in the article is Frac Count and Spacing Optimization.
This is based on research by the DOE, Continental Resources, Lawrence Berkeley
National Laboratory, the Oklahoma Geological Survey, and the University of
Pittsburgh. The four-year $20 million study is nearing conclusion. The research
involved testing cores and modeling. Each frac zone was analyzed for rock
hardness, ductility and other geomechanical properties. Maximum exposure to the
producing zone, more fracs, closer frac spacing, longer laterals, and more frac
propagation in the hardest and most brittle rock were found to be the most
important factors for increasing production. This is really not surprising. They
also found that alternating wells producing from sections higher and lower in
the rock reduced parent-child frac hits. This would be expected as well. 18
months of new production data has confirmed the modeling and this should be
applicable to refracs as well. Again, this study is more of a confirmation of
expected results.
The third
technique is Keeping Casing Liners in Place in Refracs.
“One refrac method involves inserting an expandable casing liner into the
existing casing. After sliding the liner into place the installer expands the
liner to fit by pulling a tool along its length. The liner’s purpose is to keep
the new frac from taking the path of least resistance through existing fissures
without creating new ones. From there, the producer is starting anew because,
at that point, it is essentially a brand new well that has not been perforated”,
said Jennifer Miskimins, F.H. Mick Merelli/Cimarex Energy Distinguished
Department Head Chair at the Colorado School of Mines. The goal was to
ascertain if the frac liners could be kept in place without shifting. According
to a paper published about the method: “Both the anchored and unanchored,
perforated and unperforated, patch/casing sections were then push/pull-tested
to determine friction factors and the impacts of the perforating on the
patch/casing interface. These results were then incorporated into [finite
element method] FEM modeling to determine the ability of the full-size,
field-deployed patch to remain stationary and the impact such would have on
perforation alignment during treatment conditions.” The casing liners were
found to stay in place when pressures much higher than normal frac pressures
were applied, which validates the use of the liners.
The last method
covered is Formation Structure Analysis. This involves a new
waterless frac design known as Pulsed power plasma stimulation (PPPS), which is
already commonly used for removing rock in mining operations. The University of
Houston’s (UH) Mohamed Y. Soliman believes PPPS has great potential for
hydraulic fracturing as well as frac analysis. The method involves electromagnetic
wave propagation (EWP) where a quite small amount of energy produced in a very
short time interval, 5-6 milliseconds, is able to fracture rock. EWP acts like
a shock wave. Perhaps the best use of the method is for fracture diagnostics
and underground imaging. Initial tests on concrete cylinders have validated the
method and further research is planned. They think the technique can beat
microsesimic analysis in analyzing hydraulic fracturing results.
References:
Exxon
Works to Improve Fracking Methods. Transport Topics. June 1, 2023. Exxon Works to Improve Fracking Methods
| Transport Topics (ttnews.com)
The
Evolution of Carbonate Acidizing to Unlock Full Reservoir Production Potential.
Baker Hughes. World Oil Webcast. June 21, 2023. The
Evolution of Carbonate Acidizing to Unlock Full Reservoir Production Potential
(4230897) (on24.com)
Sta-Live
Extreme polymer-free, single-phase delayed acid system. Baker Hughes. Sta-Live
Extreme polymer-free, single-phase delayed acid system | Baker Hughes
EOG
Resources’ New Frac Design: A Game-Changer? Gib Knight. July 17, 2023. EOG
Resources' New Frac Design: A Game-Changer? - OklahomaMinerals.com
Column:
EOG On Its New Frac Design: ‘No Comment’. Nissa Darbonne. Hart Energy. Oil
& Gas Investor. July 17, 2023. Column:
EOG On Its New Frac Design: ‘No Comment’ | Hart Energy
Nanobubbles,
NGLs Show Promise in Oil Recovery. Paul Wiseman. Hart Energy. E & P. June
13, 2023. Nanobubbles,
NGLs Show Promise in Oil Recovery | Hart Energy
United States
Patent Application Publication (10) Pub. No.: US 2015/0152318 A1
US
2015O152318A1 TRAVS (43) Pub. Date: Jun. 4, 2015. 1499073221569173883-US20150152318A1
(storage.googleapis.com)
Green
Horse Energy (LinkedIn). (20) Green Horse
Energy: Overview | LinkedIn
Squeezing
Oil from Stone: The Quest to Improve Shale Recovery. Paul Wiseman. Hart Energy.
July 25, 2023. Squeezing Oil from Stone: The Quest to Improve Shale
Recovery | Hart Energy
