Promising New Methods to Improve and Enhance Oil Recovery: More Oil with Less Drilling?

     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