Category: Oil and Gas

Hydraulic Fracturing, or hydro fracking, is a primary method for oil and gas wells stimulation. It is a highly engineered and complex procedure. The limitation of hydraulic fracturing application is generally to low-permeability reservoirs (e.g., < 1 Milli Darcy for gas reservoirs and < 20 Milli Darcy for oil reservoirs).

Hydraulic Fracturing Process

Successful fracture treatments may increase the productivity of a well up to 400% relative to a zero skin well. The fold of increase might be more if there was damage in the well. This may result in substantial CAPEX savings (fewer wells per field necessary) or extend the field’s economic life. Hydraulic Fracturing may be essential to break through severe formation damage (we can’t penetrate by the perforations). Or it may be desirable to increase the well productivity in low to medium-permeability reservoirs. In some cases, we would not develop a field for the success of frac treatments. However, such processes are generally expensive, so we must evaluate their economic benefit carefully.

The Fracturing Technique

Hydraulic Fracturing is pumping fluids at rates and pressures sufficient to break the formation, ideally forming a fracture with two wings of equal length on opposite sides of the well borehole. If we stopped pumping after the fracture creation, the fluids would gradually leak off (Leak Off Test) into the formation. In addition, the pressure inside the fracture would fall, and the fracture would close, generating no additional conductivity. To keep the fracture open, either utilize the to etch the faces of the fracture (an acid-frac in carbonate) to prevent them from fitting closely together or pack the fracture with proppant to hold it open.

To Create a Propped Frac

• Perforate well –efficiently.
•  Pump cross-linked gel under pressure to initiate and propagate a fracture. The gel is used to minimize leak-off.
•  Pump proppant to hold the frac open.
•  The gel must have a ‘breaker‘ to allow the fluid to revert to a water-like consistency for ease of flow-back once the Frac is in place.

Induced Fractures

Conventional hydraulically induced fractures are almost planar, with widths typically of 2.5mm to 6.4mm (1/10th to 1/4 inch), even though lengths and heights may grow to several hundred feet. A fracture will always tend to open against the line of least resistance, so the plane of the fracture will be perpendicular to the minimum principal stress, irrespective of the deviation of the well.

In principle, a hydraulic fracturing treatment is usually a combination of stages.

• We are initiating the viscous cross-linked polymer gels at pressures exceeding the formation breakdown pressure.
•  Once there is a frac, it will propagate at a slightly lower pressure.

Hydraulic Fracturing Behaviour

Suppose the fracture initiates in the middle of a thick, uniformly stressed body of rock. In that case, it will generally grow uniformly in all directions within the plane, resulting in a coin-shaped fracture. However, suppose a fracture initiates in a lower-stressed formation, bounded above and below by higher-stressed rocks, as is usually the case for a sandstone surrounded by shales. In that case, the shales will restrict the vertical growth of the fracture.

As a hydraulic fracture opens, the fluid begins to leak off into the formation along the Frac, driven by the difference between the fluid pressure in the fracture and the pore pressure. As the fracture area increases, the rate of leak-off from the fracture increases, so the fracture propagation rate falls. Ultimately we will reach a point of diminishing returns when the creation rate of additional fracture area by continued pumping is meager.

Minifrac

Often we perform ‘Minifrac’ or ‘Datafrac’ – without proppant – (and the pressure decline monitored) before the main job to check the design parameters used in job planning. The on-site measurements may modify the predictions made by various computer simulations, which use historical data and rock properties taken from cores and mechanical properties logs to compute estimates of fracture lengths, pressures, etc.

The propped Frac aims to open a channel between the reservoir and the wellbore, effectively increasing the drainage radius of the well. The Frac will deliver the hydrocarbons to the wellbore, but the matrix of the rock must still provide the hydrocarbons to the frac face. The pressure drop within the Frac must be low to encourage the passage of hydrocarbons; in other words, there must be good fracture conductivity.

Hydraulic Fracturing Materials

The criticality of hydrofracking additives is always high. Not only will we have to select or tune them for each application, but quality control on their properties and additions to the fluid is vital. It is not unknown for a hydraulic stimulation to fail due to incorrect additives concentrations or inability to add them due to pumping problems.

Fracture Fluids

The following characteristics of the fluid are essential or desirable:

• Good clean-up behavior to maximize fracture conductivity.
•  High viscosity in the fracture – both to create width and to suspend proppant.
•  Good leak-off control. We must prevent the fluid from leaking off excessively into the formation. If this were to happen, there would be no deep propagation for fracture. The fluid may deposit a filter cake, or particulate additives are sometimes used.
•  Low cost – note cost alone must not be used solely or selection criteria. Value is much more critical.
•  Low friction pressure to allow high-rate pumping.
•  The high hydrostatic gradient minimizes surface treating pressures.
•  Non-hazardous and environmentally friendly. Remember, excess fluids may have to be disposed of, and pumped liquids will eventually return to the surface.

The first characteristic – good clean-up behavior is critical.

Adnoc Policy

Hydro Fracking Fluid Components

Commonly used hydraulic fracking fluids include water-based gels, oil-based gels (Oil Based Mud), oil/gel emulsions, nitrogen & CO2 foams, and lease crude. There is often a strong preference for water-based cross-linked gels.

The main constituents of water-based fluids are (we recommend that you read WBM additives & Mud Properties to understand the below items fully):

• Water – fresh or seawater unpolluted and filtered.
•  Gelling agent – normally hydroxy-propyl guar (HPG), a processed form of naturally occurring guar gum. Typically added at 4.8kg per m3 (40 lbs/1,000 gals) to give a fluid with a viscosity of about 73 cp at a shear rate of 300 rpm (Fann viscometer).
•  Cross-linking agent, usually a borate, titanate, or zirconate. After adding a cross-linker, the gel will form into an incredibly thick, structured, highly non-Newtonian fluid (Fluids Regimes). Under conditions in the Frac, while pumping, the apparent viscosity is probably 100 to 1,000 cp.
•  Breaker to break the cross-linked gel back to a thin liquid. Either an oxidizing breaker (usually sodium or ammonium persulphate), an enzyme breaker (at low temperatures), or an encapsulated breaker. A breaker is essential to ensure fracture conductivity. Commonly Breakers concentrations are increased with pump time (cooling of the reservoir due to cold fluid injection) to optimize the polymer degradation and the fracture conductivity.
•  Buffers for pH control. Most cross-linkers work under alkaline conditions: too low a pH can cause a poor cross-link, and too high a pH may result in a poor break.
•  De-foamers.
•  Biocide (bacteria thrive on guar gum, causing rapid viscosity loss).
•  Surfactant, as an aid to clean-up.

Proppants

Proppants can be high-grade sand, intermediate-strength proppants (ISP), sintered bauxite, or ceramics. Intermediate strength proppant (MaxPROP ISP – Intermediate-strength ceramic proppant) is a mix of quartz and bauxite, ground down and stuck together to form high-strength particles with perfect sphericity. Manufactured proppants are more expensive than sand but offer higher proppant back permeabilities through higher strengths, sorting, and sphericity.

Resin-coated proppants are gaining widespread use around the world. We use them like conventional proppants. However, as the fracture closes, the temperature increases toward the original reservoir temperature. This causes the resin coating to cure, sticking together adjacent grains of proppant. This then reduces the backflow of the proppant when the well is on production. However, we must take reasonable care with resins to ensure that it does not interact with the fluid additives, especially oxidizing breakers and certain cross-linkers.

Treatment Types

Acid Fracs

The following (acid stimulation) article will mention this stimulation method.

Propped Hydro Fracking

We usually place the proppant in fractures in slurry form. First, we pump a stage of clear frac fluid, the ‘pad,’ ahead of the slurry stage to create the correct fracture dimensions. Then, we pump a slurry stage to fill that volume. As the slurry moves towards the tip of the fracture, it becomes progressively more concentrated as fluid leaks off. Usually, we pump the early part of the slurry, which we expect to reach the tip at a low concentration (probably 1 lb of proppant per gallon of frac fluid). If we pumped too high a slurry concentration early on, it could dehydrate and bridge off before reaching the end of the fracture. The slurry concentration starts gradually increasing as the treatment progresses. In a tip screen-out treatment, the pressure will increase, and pumping continues once the proppant reaches the end of the fracture – this creates width.

Stage	Concentration (ppg/clean)	Gel Vol (1000x gal)	BBL	Slurry Vol (100x gal)	BBL	Proppant   (1000x lb)	Prop Size	Pump Stage (min)	Time Cumm (min)
1	Pad	2.2	53	2.2	52.8	none	20/40	2.6	2.6
2	1	0.9	220	1	23.3	0.9	20/40	1.2	3.8
3	2	0.1	3.2	0.1	3.4	0.3	20/40	0.2	4.0
4	3	0.2	5.3	0.2	6.0	0.7	20/40	0.3	4.3
5	4	0.3	7.3	0.4	8.6	1.2	20/40	0.4	4.7
6	5	0.4	9.1	0.5	11.0	1.9	20/40	0.6	5.3
7	6	0.4	10.6	0.6	13.3	2.7	20/40	0.7	5.9
8	7	0.5	11.8	0.6	15.4	3.5	20/40	0.8	6.7
9	8	4.9	117	0.6	158	39.3	20/40	7.9	14.6

Hydraulic Fracturing Planning

The productivity increase due to the fracturing process is a function of the following:

• Fracture length,
•  Fracture conductivity,
•  Fracture/wellbore communication,
•  Reservoir permeability, and
•  Near-wellbore damage (skin).

It is difficult to lay down firm guidelines for selecting wells, as we should consider each field or well should focus on its merits.

Input Data

When planning any hydraulic fracturing or fracking job, we should consider the risk of a frac extending ‘out-of-zone,’ i.e., below the oil-water contact or up into a gas cap. There are numerous computer programs to predict the size and shape of a frac. Like all programs, if we input insufficient data, the predictions are not worth much. Ensure that valid data is used to predict the Frac.

Data for input to the frac program includes:

• Geological data
•  Formation boundaries/layers from logs
•  Mechanical properties (from logs, sonic + density)
•  Core data – Young’ Modulus
•  Poisson’ Ratio
•  Reservoir data – pressure and temperature
•  Frac fluid and proppant data (for some frac models).

We should consider that if a frac prediction is wrong, it can lead to any of the following:

• Placement problems, where too much proppant is pumped for the size of the fracture;
•  Or to production problems when the well flows differently than predicted.

Other Consideration For Hydraulic Fracturing

Evaluation of the competence of the cementing in drilling surrounding the perforations is essential. The perforations need to be four spf to six SPF, although higher shot densities may be beneficial. Phasing is usually 45 to 60 degrees. Oriented (180° phasing) perforating has been tried with limited success in deviated wells. Theoretically, the perforation diameter should be seven times the average proppant diameter.

Gas Wells Hydro Fracking

It is preferable to consider all low-permeability gas wells for hydraulic Fracturing, either at the completion stage or later in the life of the field. If the plan is to carry out the Frac later, it is essential to consider when designing the completion (including the casing design).

For example, in the North Sea, and well with a permeability of less than five mD or a permeability thickness (kh) of less than 700 mD.ft is a definite candidate, although we shouldn’t dismiss better wells. It is essential to consider the actual permeability distribution within the sand body.

Oil Wells Hydro Fracking

Oil wells require higher permeabilities (Absolute Permeability) to produce at commercial rates than gas wells. We can achieve the benefits of Fracturing at up to 500 mD “the best wells are the best frac candidates.” The benefits of Fracturing are potentially more significant if there is positive skin. But Fracturing is expensive, and we should always investigate other ways of removing near-wellbore damage.

Conventional vs. Tip Screen-Out Treatments

A conventional frac is designed to be long and thin, whereas a tip screen-out (TSO) frac is intended to be fat! A TSO frac is loaded with proppant that ‘screens out, thus preventing further outward propagation of the Frac, but continued pressure increase causes the Frac to grow outwards.

Most propped hydraulic fractures will back-produce some of their proppant. Slow bean-up of wells when putting them on production is essential. It may be necessary to use special proppant knock-out pots between the well and the process facilities. Alternatively, we can resin-coat the proppant to try and bind the proppant together; alternatively, use a proprietary binding agent (e.g., plastic fibers). Experience doesn’t recommend using resin-coated proppant during the last stage only. This is because the previous proppant pumped in does not equal the first proppant to be produced.

Hydro Fracking In Deviated and Horizontal Wells

Many Oil and Gas Companies recommend that hydraulic fracking is in wells with low deviation angles through reservoirs, especially wells with a high production rate due to Fracturing. This may mean drilling an S-bend well. However, we should still fracture deviated wells. In these cases, the productivity increase from Fracturing will not be as significant as from a vertical well, and the actual fracture may be more challenging to place successfully. If we know the orientation of the principle stresses – from measurements or the fault pattern – then fracture stimulation is very advantageous.

The reason for preferring fracture candidates to be low deviation is to get the maximum communication between the Frac and the wellbore, which may not happen in highly deviated wells where the Frac and the wellbore may only cross at one point. Fracture initiation and propagation pressures will be higher due to higher perforation friction losses.

Water Injectors

Many Companies believe that rock cooling and lowering the formation fracture pressure below the injection pressure (thermal fractures) are the leading cause of Fracturing in most high-rate water injection wells. Propped fracturing injectors rarely gain much – if possible, increasing the injection pressure would be better and more straightforward.

Evaluation Of Hydraulic Fracturing

Generally, there will be great care in planning a frac: to get the right size and shape of Frac, after evaluating all the available log and core data and running numerous computer simulations. However, more often than not, very little post-frac evaluation is done.

How can we evaluate Hydro Fracking?

• Comparison of pre-frac and post-frac test data, including pressure build-up
•  Multiple-isotope radioactive logging (isotopes placed in proppant)
•  Temperature logging
•  Bottomhole treating pressure responses
•  Production logging tools (spinners)

Downhole gauges will undoubtedly aid in evaluating the bottom hole-treating pressure response. If gas lift valves have to be dummied off, then consider temporarily replacing the valves with gauges. They operate and are installed/removed precisely like a gas lift valve or dummy. Downhole memory gauges set in a nipple below a perforated joint may be an alternative; however, if left for any period downhole, they may be difficult to remove when solids settle on top of them.

Best Practices – Hydraulic Fracturing

A protection sleeve on a tubing retrievable downhole safety valve is only needed on wells where the pump pressure will cause the flow tube to retract, leaving the flapper and seals exposed. If possible, increase the control line pressure rather than use a protection sleeve. This may require a special pump and isolating the well from the shutdown system.

Prevent Damage during Frac:

• All fluids pumped must be compatible. All compatibility notes mentioned under acid apply here.
•  Complete core compatibility testing (e.g., Frac Tech or Corelab) is strongly recommended.
•  Reasonable quality control of frac fluids. Any cross-linked gel must break.
•  Check the breaker in the heat bath on site.
•  Check proppant for quality and cleanliness.
•  Mix water must be unpolluted, filtered, and inhibited with NaCl or KCl (shale inhibition).
•  We must thoroughly clean all pipework and tanks.
•  Minimize pipe dope used on the frac string.
•  ‘Flex’ the frac string before pumping the Frac.
•  If using resin-coated proppant (RCP), ensure complete compatibility between resin and fracturing fluid.
•  We should consider a safety valve protection sleeve (a must for wireline retrievable systems).

After The Hydraulic Fracturing Job

After a propped frac has been placed, We must take precautions to ensure proper clean out of any proppant left in the wellbore. When a frac string is pulled out, a suitable filtered fluid must be left in the hole, preferably with a degradable lost circulation material component to stop excessive losses into the Frac just formed (the same applies during the workover of a fractured well). Ideally, the well should not require killing (Wait and Weight, Driller’s method, or Volumetric Method), and a top-hole workover is only performed. Fraccing through the completion avoids any problems with workovers or well kills – however, ensure the completion can take the loads.

On Stream

When a propped-frac well is brought on stream, we should bean it up slowly to minimize the shock to the pack and thus minimize the flow-back of the proppant. Likewise, during the life of the well, we should always make rate changes gradually. We must not open the well fast while broken frac fluid flows back.

It is worth bearing in mind that we will force fluids into rocks at very high pressures yet produced back at much lower drawdowns in naturally fractured rock.

When After Completion With Some Time

When stimulating some time after the well has been drilled and completed, we must take further precautions:

Part A

• Re-perforate the zone to be fractured – old perfs can be blocked.
•  Think about reducing the length of the perforation interval (e.g., to increase the stand-off from water) as needed with sand back or mechanical plugs (Bridge Plug).
•  If corrosion is possible or suspected, run Kinley caliper logs and derate the burst rating of the tubing.
•  We may require a tree saver – ensure it is compatible with your tree!
•  Check the tubing stresses and any expansion device movement – get space out from the actual completion report.
•  Also, check the liner stresses (especially if the cement bond is poor).
•  Consider proppant flow back – where to put it etc.
•  We should consider proppant production, velocities, erosion, cleaning of separators, etc.
•  Drift the well before stimulation – check for wax, scale, etc. It must be removed if there is a lot or the Frac is small. Check all tools run in the well or debris (gauge rings, dummy guns, e-line drip, trays, etc.)

Part B

•  Consider the blanking of GLMs, especially if annulus pressure is required.
•  Beware of cement-squeezed perforations; they may break down during the Frac. Consider patch flex or straddle.
•  When using an inflatable bridge plug to isolate lower perforations, run temperature predictions to see if the plug can cope with the pressure, temperature change, and inflation ratio. Set the plug at the optimum temperature.
•  Sanding back perforations is tried and tested. Can be done to ±0.6m (2 ft) in vertical wells and ± 1.5m (5 ft) in low-angle wells, and ±3m (10 ft) in higher-angle wells.
•  Cleaning out of the well will probably require coiled tubing – run simulations to confirm that the proppant can be lifted with the completion and coil configuration. Consider reverse clean-outs. They can be highly effective, and despite some companies’ reluctance to use reverse circulation up the coil, they can be performed safely.

Hydraulic Fracturing References:

• Firstly, Ahmed, S., Hanamertani, A. S., Hashmet, M. R. CO. Foam as an Improved Fracturing Fluid System for Unconventional Reservoir. Available from: https://www.intechopen.com/chapters/66559 DOI: 10.5772/intechopen.84564.
•  Secondly, Fracking. (2022, December 3). In Wikipedia. https://en.wikipedia.org/wiki/Fracking
•  Thirdly, Wright, R; Muma, RD (May 2018). “High-Volume Hydraulic Fracturing and Human Health Outcomes: A Scoping Review.” Journal of Occupational and Environmental Medicine.
•  Last, the Fracturing Litigation Summary.

It’s that time of year, time for my oil and gas predictions for 2023. But before we get into that, let’s recap what I got right and what I got wrong last year.

What I Got Right and Wrong Last Year

So number one for last year, global energy shortage. Absolutely nailed that one. Number two, fertilizer shortage. Yep, nailed that one. Number three, combo plants. I got that one wrong. I thought there’d be a lot more construction of refineries and combo plants, but because of the political unrest and supply chain issues that didn’t happen. Number four, supply chain issues. I nailed that one. Number five, inflation. Got that one right. Number six, the beginning of a supercycle. Got that one right. Number seven, lack of skilled labor. I got that one right. Number eight, energy theft. I got that one right. Number nine, a change in consumer fuel mix. I’m going to call that one a draw.

I thought there’d be a lot more electrical vehicle sold in 2022 and the need for more recharging stations, but there was a constraint on the supplies needed to build electric vehicles, so it didn’t grow as fast as I thought it would. Then number 10, the chance to change negative public perception. I absolutely got that one right.

If you look at what I did last year, I got 80% of those predictions correct, which is much better than my average. I’ve been doing this for nine years now and my average is about 74%. If you want to check out the past predictions, there’ll be links in actual show notes going all the way back to 2014. Check out past predictions here: 2014, 2015, 2016, 2017, 2018, 2019, 2020, 2021 and 2022

Pricing for 2023

Before we get into my predictions, 2023, let’s go through my pricing. What I think prices will be for 2023. Brent will average about $102 a barrel. WTI will average $95 a barrel. Natural gas will go for $7.05 cents per million british thermal units. But it’s a mess to try to predict this. Between the EU and G7 sanctions on Russia, China opening back up, OPEC’s inability to increase production, and the end of the SPR releases and the need to buy the crude order to fill the SPR back up. It is hard to get a line of sight on any of this.

Oil and Gas Predictions for 2023

All right, so let’s get to my oil and gas predictions for 2023.

Peak People

Number one, peak people. If you look at the world’s population growth, it’s still growing, but the growth percentage is slowing down, we are coming to the top of that bell curve. Certain countries like China for years had a one child per couple, literally government mandated order. Look here in the US, birth rates are really low. And there’s some states in the US like the upper East Coast where there’s such a disparity between the number of new births and the number of people that are dying. If that trend continues in another 60 or 70 years, there’s going to be nobody living in those states. So for a long time the world was worried about population growth. Too many people for the earth support and think in 2023, you’re starting to see that peak people come in, which means somewhere in the future, the problem’s going to be that we don’t have enough people on the planet. That’s a strange one to think about.

Major Conflict

Number two prediction for next year. Major conflict, and I hope I’m really wrong about this, but between what’s going on between China and Taiwan, Iran and Israel, Russia and Ukraine, and then the world’s social unrest, food and energy shortages, high prices, everybody’s on the edge right now. And with these hotspots around the world, geopolitically, all it takes is somebody to make a mistake, one soldier to pull the trigger when he shouldn’t. Somebody to push a guided missile button when they shouldn’t. And we have a major conflict, not a world war, but a major conflict. Now if that happens, you will see prices of crude spike to 120, maybe even $150 a barrel. And like I said, I really hope that doesn’t happen.

Birth of the Mega Majors

Number three, prediction for 2023. Birth of the Mega Majors. So for years, Exxon and Chevron, Shell, BP were all neck and neck competitors. Well, for the last couple years, they’ve kind of split up on their strategies. So Exxon and Chevron are putting their returns and their capital back into hydrocarbon projects. BP and Shell are taking their returns and their capital investing in renewable projects and their shareholder value and their profits show the difference. Chevron and Exxon are doing so much better financially than BP and Shell because that difference in strategy, which is allowing Chevron and Exxon to grow, and they’re going to grow much bigger than BP and Shell. And as they grow bigger, they’re going to have more capital to deploy, more reach, more leverage, both with governments and with vendors, which is give them even more competitive advantage against BP and Shell. So I think you’re seeing the birth of the Mega Majors. New term, I should patent it probably.

Carbon Capture and Storage

Next thing for oil and gas predictions for 2023, carbon capture and storage, regardless of what you think about carbon dioxide, it doesn’t matter. There’s business here and there’s two big pieces of it. Number one is the world’s governments are funding, carbon capture and storage, carbon taxes, carbon caps, all this stuff, which means that there’s government money to fund this sort of stuff and companies are taking advantage of us. Number two, carbon dioxide is actually a commercial product that you can make money on, whether there’s government subsidies or not. So you’re seeing all these projects going on where they’re pulling CO2 out of the air, they’re building the infrastructure like pipelines to move it around. They’re storing the carbon dioxide and then they’re using it to do enhanced oil recovery. And so it use to be they had to buy that CO2 off the market for enhanced oil recovery. Now they’re using government subsidies, it’s genius actually, and, and capture the CO2 making money from the government. And then they were using it for enhanced oil recovery. So regardless of what you think about this, carbon capture storage is going to be a big business starting in 2023.

Anti Renewable Movement

Then number five, anti renewable movement. The world’s had enough. You’re seeing people, companies, countries look at what’s going on with the renewables. Look at things like ESG and then turn around and look at how expensive energy prices are, how expensive food prices are and the fact that it’s causing social unrest. And they’re going “you know what, maybe renewables aren’t the way to go, or maybe we should go as fast”. So you’re going to start seeing a pushback against renewables. And that’s not a good thing. Our biggest problem in this world right now around energy, is we’ve allowed it to become politicized. We need to disconnect politics with energy. The energy mixe has always changed and always will. Every energy source has an impact. Every energy source’s impact can be mitigated. But by pushing renewables too fast, it’s one of the main reasons the world’s in an energy shortage right now. And I think you can see a lot of people push back, which like I said, is not a good thing because it perpetuates the hydrocarbons versus renewables, the us versus you type of butting heads, which isn’t good for anybody. We need to recognize that all energy is good and that all can be used responsibly.

World’s Energy Shortage Will Continue

Number six, unfortunately the world’s energy shortage will continue. Demand will continue to be larger than supply. You see China starting to open up after Covid, you’re seeing other economies pick back up, but we don’t have the ability to get hydrocarbons back on the market to fund all this energy. And like I said, the renewables can’t fill that gap either. So unfortunately the world’s energy shorts will continue during 2023.

Shale Growth Will be Slow

Then number seven, unconventional shale growth will be slow. Between capital discipline, focus on returns, debt repayments, supply chain constraints, and then our current administration here in the US sending mixed singles to the industry. The shale growth is not going to boom like it did before. It will increase in size and it will grow, but that shale growth will be very slow, which leads me to number eight.

Oil and Gas Predictions for 2023 – Offshore Oil will Boom

Offshore conventional oil will boom. You’re seeing, offshore projects pick back up all over the world. Even some deep water projects have picked back up, which are very expensive. And the reason is it’s a much better return and has a much longer decline rate than the shale resources. So the world’s in an energy shortage, there is money to made off hydrocarbons and offshore oil is going to boom because of that demand.

Capital will be Easier to Get

Then number nine in the industry for 2023 capital will be much easier to get. For the last few years capital is really hard, especially for the smaller and independent operators around the world because of ESG and funds and companies were not putting money back into the oil and gas industry because they were worried about ESG pushback from activists, from shareholders. Well, what they’ve done is they’ve missed out on tremendous returns in 2022. And so they’re seeing the amount of money they could have made that they missed out and they’re going “you know what, this ESG isn’t something as important as I thought it was versus me making a lot of money”. So you will see much easier ways to get capital in the oil and gas industry for 2023.

Record Business Year for Oil and Gas Industry

Then number ten, 2023 is going to be a record business year for the oil and gas industry. The other verticals will suffer, the world’s economy will continue to slow down. The recession’s going to get worse. But the oil and gas industry will be on fire for at least the next 8 to 12 years. Maybe even another 20 years, because we have to fuel the world basically.

Share and Comment

So there you go. There are my oil and gas predictions for 2023. If you like this, do me a favor, share it with your friends. And if you have any suggestions or any input on what I said, let me know. I’d love to have that discussion with you. Hopefully this helped. We will see you next time.

China is making fast inroads in the market for newbuild liquefied natural gas (LNG) tankers as local and foreign shipowners turn to its shipbuilders for the specialty vessels because long dominant yards in South Korea are fully booked. 

Three Chinese shipyards – only one of them having experience building large LNG tankers – won nearly 30% of this year’s record orders for 163 new gas carriers, claiming ground in a sector where South Korea usually captures most of the business. 

LNG tanker order books for Chinese yards tripled as China’s gas traders, and fleet operators sought to secure shipping after freight rates soared to records following the upending of global energy supply flows by Russia’s invasion of Ukraine. 

With South Korean shipbuilders swamped by orders to service Qatar’s massive North Field expansion, Chinese yards also attracted more foreign bookings, including first overseas orders for some ship makers only recently certified to build membrane-type LNG carriers. 

“As more Chinese gas traders engage local shipyards, they will be forced to climb the learning curve and eventually grow the whole industry,” said Li Yao, founder of Beijing-based consultancy SIA Energy. 

Chinese shipyards this year won 45 LNG tanker orders worth an estimated $9.8 billion, about five times their 2021 order values, according to shipping data provider Clarksons Research. By late November, Chinese yards had grown their LNG order books to 66 from 21, giving them 21% of global orders worth around $60 billion. Comparatively, Chinese shipyards built just 9% of the existing global LNG fleet, according to Clarksons. 

STEEP CURVE

Shanghai-based Hudong-Zhonghua Shipbuilding is the only Chinese yard with experience building large LNG carriers, delivering dozens going back to 2008. This year, it took 75% of China’s new orders.

Hudong-Zhonghua shared 26 orders from local owners – versus nine the last two years – with fellow China State Shipbuilding Corporation units, Dalian Shipbuilding Industry and Jiangnan Shipyard (Group), according to Clarksons and industry officials. 

Two other yards – China Merchants Heavy Industry (CMHI) and Yangzijiang Shipbuilding YAZG.SI – were certified to build large LNG carriers this year and have attracted interest from local and foreign shippers. LNG tankers, like aircraft carriers, are among the most difficult vessels to build, taking up to 30 months. 

For membrane-type containment tanks alone, 200 workers spend two months welding barrier walls made of paper-thin steel and 130 km (81 miles) of connecting lines. Workers on these systems for housing gas chilled to minus 160 Celsius (minus 260 Fahrenheit) for shipping also have to be certified by Gaztransport & Technigaz (GTT), a French engineering company that holds the patents and licences its designs to shipbuilders. 

“The learning curve will be steeper for the newer builders … We’ll also face a shortage of skilled workers,” said Hu Keyi, corporate technology chief at Jiangnan Shipyard. Jiangnan is building its first 80,000 cubic meters (cu m) tanker for Guangdong-based trader JOVO Energy and won an order in March from Abu Dhabi National Oil Company (ADNOC) for two 175,000 cu m LNG carriers. 

“Considering relatively low financing costs thanks to Chinese banks’ support … investing in a newbuild offers greater security versus term chartering,” said Jacky Cai, a director at JOVO Energy, which is considering ordering a larger tanker. U.S. GAS China’s demand for LNG tankers is propelled by a need to ship 20 million tonnes a year of gas from the United States, part of a boom set to swell the global LNG fleet by a third over the next five years, said Robert Songer, an analyst at commodity consultancy ICIS.

China needs about 80 vessels to transport U.S. LNG, said SIA Energy’s Li. 

“Apart from servicing Chinese demand … the vessels may also be used to trade cargoes on other routes,” said Stephen Gordon, managing director of Clarksons Research. 

Strong local shipbuilding benefits state energy giants PetroChina, China National Offshore Oil Corporation (CNOOC) and Sinopec, and private firm ENN Natural Gas Co, helping to better secure a fuel key to meeting China’s 2060 carbon-neutral target. 

PetroChina and CNOOC lined up orders at Hudong-Zhonghua earlier than their peers, mostly via joint ventures with state shippers COSCO Shipping Energy Transportation 600026.SS and China Merchants Energy Shipping (CMES), following President Xi Jinping’s call for energy security. 

Sinopec, a minority stakeholder of CMES, is also in talks to secure newbuilds at Jiangnan and Dalian, industry officials told Reuters. Sinopec declined to comment. COSCO Shipping Energy is “ready to work hand-in-hand with shipowners and yards,” Qin Jiong, a company vice president, told an industry seminar last month, pointing to another advantage of using local shipyards. 

FOREIGN ORDERS

While their labor costs are higher, Korean yards – such as Hyundai Heavy Industries and Daewoo Shipbuilding & Marine Engineering – are more efficient in design and construction and have a local supply chain, said Sunny Xu, founder of Singapore-based LNG solution provider C-LNG. 

“Shipowners seem to have a more positive view about Korean shipyards … to realize the design shipowners want, ability to meet deadlines, and problem-free operation,” said a South Korean shipbuilding industry source who declined to be identified. 

Still, Chinese yards received 19 foreign orders for LNG tankers this year and that number is likely to grow. “Chinese yards have become more attractive because of the South Korean backlog, as well as rising costs,” said ICIS analyst Songer. 

Chinese yards’ relationship with GTT also helps, he said. 

“It is a fair assumption that China will start building a lot more vessels in the future.” Spot LNG freight rates double this winter vs lasthttps://tmsnrt.rs/3FgvMDX 

Chinese shipyards expand share in global LNG tanker fleethttps://tmsnrt.rs/3OSxKO3 

(Reporting by Chen Aizhu; Additional reporting by Joyce Lee in Seoul; Editing by Tom Hogue)

Transcript: APPEA Chief Executive Samantha McCulloch discusses gas market pricing  

12 December 2022 

Doorstop

Samantha McCulloch: The reforms announced by the government on Friday evening fundamentally dismantle the efficient operation of Australia’s gas industry. It goes well beyond a temporary price cap and includes indefinite regulation into the prices in the Australian gas market. 

This is going to have a chilling effect on future investment in supply, and it’s that new investment in supply that is actually the key to bringing down prices for Australian households and Australian manufacturing. 

Reporter: In the mandatory Code of Conduct, the framework released by Treasury, it says reasonable price, are you seriously suggesting you want to impose an unreasonable price gas? 

McCulloch: Well, it’s a regulated price concept that will be administered by the ACCC. It doesn’t reflect the risk profile of the industry. This is an industry that spends billions of dollars before any money is made, so a regulated price is not going to be conducive to new investment in supply. 

Reporter: Are you speaking to the Crossbench and Coalition about your concern with this legislation and asking them not to support it, and so on? 

McCulloch: We’re speaking to all stakeholders. This is far-reaching reform that will have long-term consequences for Australia’s energy security, and for our gas industry and the 80,000 jobs and workers that are employed the gas industry. 

These are considerable reforms that really need adequate consultation, with stakeholders including the gas industry. 

Reporter: Can you confirm you’re planning a $20 million campaign against these reforms, and if you are don’t you think that could be seen as out of touch, given how many people are struggling right now? 

McCulloch: All options are on the table, this is an industry which has invested $400 billion in the Australian economy over the last decade and what we’re seeing now is a government changing the rules of the game with alarming frequency. So, as an industry we’ll be looking at all options in regards to these reforms. 

Reporter: Inaudible. 

McCulloch: Let’s break that down actually, the price of gas, let’s distinguish between the domestic market and the export market. Domestically, and when we’re looking at the wholesale market, where the caps are going to be applied, most gas is sold under long-term contracts and the average price being struck in those long-term contracts is around $12 a gigajoule.  

What we have seen is agreements between the Australian government and the east coast LNG exporters, struck in September, that guarantees supply into the Australian market, that guarantees supply at competitive rates, yet the government hasn’t given these mechanisms a chance to work. Within three weeks of the Heads of Agreement (HoA) being struck, the government was calling for further intervention.  

What we need now is not more intervention, not more regulation, we need more supply to increase gas to the market and bring those prices down. 

Reporter: Isn’t it the case the HoA was admitted straight afterwards by the government that it wouldn’t do anything to lower gas prices, which was the problem with it, and the manufacturers and people like Innes Willox and the AWU who leaped up and down and said we need more to keep gas prices where they are? 

McCulloch: The Heads of Agreement enshrines a principle that domestic customers will always pay less than international customers. It offers more than 157pj of uncontacted gas to the domestic market and we’re seeing evidence that the Heads of Agreement was working.  

There have been several gas supply agreements struck just in recent weeks, including an 11-year supply deal between Santos and Brickworks, that was struck at rates which were competitive and that both parties were comfortable with. This is how the market is working. 

Reporter: The government has been talking about strengthening the Code of Conduct for months, did you think they were bluffing? I’m wondering why you so surprise about what you saw on Friday given they were talking about going down this route and giving the ADGSM some actual teeth. Why were you so surprised? 

McCulloch: Friday’s reforms were beyond what most in the industry and most in the community were expecting because it included not just the temporary, one year price cap, that could still be extended, but ongoing regulation of gas prices in the code.  

Now this started as a voluntary code that was negotiated between gas producers and gas suppliers and the Australian government over almost a two-year period, negotiated in good faith.  

It provides for transparency around how gas is offered to market and provides for a dispute resolution process, but it wasn’t given a chance to work, within three weeks of the Code of Conduct coming into play the government was calling for more intervention, and now the mandatory code will include these regulated price provisions. 

Reporter: Why, given the fact that the vast majority of Australian gas is sold overseas, would a price cap on the local market deter investment? Wouldn’t that have a small effect, if any? 

McCulloch: Well what we need to do is be bringing on more supply where it’s used in Australia. When we look at the east coast market, which is the subject of most of the reform, 80% is produced in Queensland but the key demand centres are actually in New South Wales and Victoria, and what we are seeing is the supply in those states is either prohibited through moratoriums, bans and delays, or it’s declining. 

So, what we need to do is see more investment in those eastern and southern states to meet demand. 

Reporter: Have you spoken with the PM yet or do you plan to? 

McCulloch: We’ve requested a meeting between APPEA Board members and the Prime Minister this week. I think it’s important that the Prime Minister meet with the industry to understand the long-term consequences for investment if these reforms… 

Reporter: Is there any indication that that meeting is going to happen? Have you heard anything from the PM’s office? 

McCulloch: We’re liaising with the Prime Minister’s office currently. 

Reporter: Can you give me a specific example of investments that might not go ahead because of this? 

McCulloch: I would have to leave it to my members to make comments on individual projects and the impacts of these reforms on individual projects? 

Reporter: Will this new regulation stop the industry selling more of its gas overseas? 

McCulloch: Look, the Prime Minister has assured that the long-term LNG contracts would not be interrupted; what would be of a concern here is among the package announced on Friday night – but also included in the budget – was a quarterly review of the ADGSM, which is the Australian Domestic Gas Security Mechanism. 

This means that every quarter the government will be looking at whether or not it wants to interrupt those contracts with our major trading partners. 

Reporter: Ben’s question a moment ago was about new projects that might not go ahead and you don’t want to talk about individual companies obviously – that’s for them to discuss – but does APPEA as an organisation have a forecast of how much new gas is meant to be developed over the next 5-10 years across the sector, and whether the Friday deal changes that outlook at all? 

McCulloch: We’ve only had this information now for a few days but what I can say is that analysis we released the week before last by EnergyQuest really highlighted the impact of intervention such as price caps on future investment and on the economic viability of projects going forward – and that includes energy storage facilities in Victoria that are key to balancing peak demand during winter periods. 

It also includes the viability of LNG import terminals. We know that these import terminals are going to play an important role in terms of energy security on the east coast of Australia in the next decade.

Doorstop Interview

Parliament House, Canberra

Topics: Australian Government energy plan, impact of gas price caps on investment, importance of gas in the energy transition, export contracts

Q: What is your reaction to the caps?

Samantha McCulloch: We welcome effective relief for Australian households and industry but what we saw last night announced by the government is a fundamental dismantling of the Australian gas market. It will do the opposite of what’s needed and will destroy investor confidence in bringing on new supply and that’s the key to bringing down prices.

Q: The government claims that these caps will leave the average households will be $230 better off next year as a result of these caps. What do you say to that?

McCulloch: Let’s just look at the role of gas in the power market. The reduction in electricity prices is being primarily driven by the coal measures, not by the gas measures. On the east coast of Australia gas is only 7% of the market, or 7% of generation, and it’s actually coal or hydro that set the price of electricity most of the time.

Q: So what do you think we’re actually going to see happen with power prices as a result of this plan?

McCulloch: I’d like to talk about wholesale prices in the gas market. Gas producers and APPEA members are selling into the wholesale market and the ACCC has highlighted just recently that the prices received by gas producers have increased about 11% in the last 12 months. In the retail market, prices have increased 95%. But what we didn’t see last night was any measures to address those retail prices. The focus is entirely on the wholesale market.

Q: So has it unfairly targeted your members?

McCulloch: I think it’s inefficient in terms of a response. What we’re seeking to do is provide relief to Australian households and industry. What we need to do is let the market work, let the market work to bring on new supply, to reduce prices in the long term.

Q: But we’re trying to undo that, we’re trying to (inaudible). In any case, this is driven by the Ukraine. Hopefully that will be somewhat temporary. Is there something a little bit hollow about your concern about the long term?

McCulloch: In terms of the energy transition, we need gas. The role of gas has never been more important because we need gas as a partner to bringing on more renewables into the electricity system. We need gas to help support energy security as we move away from coal. So the role of gas is actually growing as we head towards to net zero. In terms of temporary measures, what we have seen is a fundamental dismantling of the Australian gas market and, out of that, out of the pressures that we are seeing, of course because of Russia’s invasion of Ukraine, but these are also problems that have been a long time in the making. Prices and energy prices were going up even before Ukraine and that was because of tight supply and volatility in the power market.

Q: When you say we need more supply, which is what the opposition has been saying – it’s not about capping prices, it’s about getting more supply – that takes five, six years for new supply to come on…

McCulloch: What we do need, though, is to bring on new supply to reduce prices in the medium term. We’ve seen yesterday that the Narrabri pipeline will be given major project status. Our APPEA members and gas producers in Australia have announced more than $20 billion in new investment in supply in the last few years. But what we are seeing now is increasing uncertainty. We’re seeing bans and moratoriums. They are impeding the ability of the industry to make those long-term investments in new supply, and that’s the key to bringing down prices for Australian households and Australian businesses.

Q: What is your answer to the immediate problem, the immediate price issues?

McCulloch: As I just highlighted, when we’re looking at the gas market, the gas wholesale market is working. Just in September, the major gas producers and LNG exporters on the east coast of Australia struck a Heads of Agreement with the Federal Government that ensured domestic supply. It ensured domestic supply at competitive rates. And we were already seeing signs that this was working. We saw Santos just last week strike an 11-year supply deal with Brickworks. These are agreements being struck at competitive rates. But we’re not giving these existing mechanisms a chance to work. There’s intervention, after intervention. And what we’re seeing, after billions of dollars of investment by the industry, is that government is changing the rules of the game on an almost constant basis.

Q: The government says that this won’t impact Australia’s reliability as a gas exporting nation. It won’t affect those export contracts. Is that not the case?

McCulloch: So one of the measures that was announced in the Budget and reinforced yesterday was the quarterly review of the ADGSM, the Australian Domestic Gas Security Mechanism. That means on a quarterly basis the government will be investigating whether or not it needs to interrupt those long-term international supply agreements. This is going to undermine Australia’s reputation of being a secure, safe reliable partner for countries like Japan who rely on our energy exports.

Q: You’re suggesting that this will see prices go up rather than go down. How concerned do you think (inaudible).

McCulloch: The introduction of gas price caps is destroying the incentive for investment in new supply. We released analysis last week that highlighted that not only does it undermine the economics of new supply, but in other measures such as gas storage facilities in Victoria, in LNG import facilities. This is going to create long-term risks to our energy security and it will ultimately drive up prices because we will see shortages of supply.

Q: Is that even the case even though it’s got a 12-month limit on it?

McCulloch: This is not a short-term measure. The gas price cap of $12 announced yesterday initially will be 12 months but subjects to review. But the government also announced a regulated price under a mandatory code of conduct which has an indefinite period. So the government promised short-term measures emergency responses to the current pressures in the energy system – what we are seeing now is ongoing regulation of the gas market in Australia.

Q: Isn’t $12/GJ a pretty OK cap. Just a year ago gas was selling for about $10/GJ. So this is above that. Sure, it’s not at the $26 or whatever it is today, but it’s still above what it was?

McCulloch: When we look at the gas market, there’s, of course, the spot market, which is about 15% of supply, which tends to have higher prices. Those long-term contracts, the average price for those long-term contracts at the moment is around, the contracts being struck currently, is around $12. There’s a big difference between having an average of $12 and a cap of $12 because what the cap doesn’t recognise is the complexity of some of these agreements and the differences in terms of the quantity being supplied, the duration of the agreement, the interuptability of the agreement. This just underscores that these measures are being introduced without a strong understanding of the gas market and without an understanding of the unintended consequences.

South Africa’s skills policies are not in line with its environmental commitments and the country needs to significantly improve its technical and vocational education and training (TVET) ecosystem to produce the skills required to develop and capitalise on the just transition.

“Environmental challenges are cross-cutting issues. They do not belong to one sector, and the transition involves multiple systems, but our skills system does not have the capacity to deal with cross-cutting skills requirements,” University of the Witswatersrand Future of Work Programme research centre director Presha Ramsarup said this week.

Part of the aim of the Future of Work Programme is to develop a mechanism to coordinate the development of green and just transition skills.

“We are working to determine how jobs will change. Employers do not understand what about a job will change. South Africa needs to develop employer, sectoral and system level tools for sector education and training authorities to identify changes in skills requirements and adapt training courses in line with the needs of industry,” she said.

For example, the centre is investigating whether domain knowledge within occupations is changing, whether the materials, tools, products and services in occupation are changing and, from this, whether the researchers can define what occupational changes will be, Ramsarup noted.

“This will help us to identify hotspot areas where jobs are starting to change. From this, occupational analysis and research will help to inform skills planning methods and models required for a just transition.”

Meanwhile, energy industry organisation the South African National Energy Association (SANEA) conducted a desktop study of more than 200 reports relating to South Africa’s skills and education systems.

“South Africa does not have an integrated view of what is needed to support the just climate transition, although many skills are common across many of the technologies, including renewables energy generation and green hydrogen for example,” said SANEA secretary-general Wendy Poulton.

The skills interventions are also not market-driven, neither are they based on value chains, she added.

“South Africa’s economy is also coal-based and the impact of the energy transition will be much bigger than for less carbon-intensive economies. From our research, we are seeing that the energy skills gap is widening amid deteriorating energy security. These are significant issues for South Africa in terms of climate change adaption and decarbonisation,” she said.

There are a few no-regret options open to the country that are common in all the modelled scenarios, namely increasing renewable energy generation and energy efficiency measures, as well as a drive to prosumerism, Poulton highlighted.

However, questions about the timing of changes in the energy market remain, including when and how green hydrogen will be introduced amid declining coal and oil use.

“Lots of skills are required no matter what scenario or pathway is taken,” she noted.

Sectoral master plans can help role-players understand what the future demand will be, said Department of Science and Innovation (DSI) hydrogen and energy chief director Dr Rebecca Maserumule.

Understanding the demand for skills is necessary to ensure that the education and training system is responsive to the needs of the labour market and reduces mismatches, concurred Department of Higher Education and Training (DHET) system monitoring and labour market intelligence director Mamphoku Khuluvhe.

“We need to ensure that skills are not a constraint to growth of the economy and specific economic sectors, nor to our efforts to address climate change,” she said.

Cooperation with industries to identify sectors that will be affected by the energy and climate transition of the economy is critical, and value chains must be included to ensure all stakeholders are part of the transition, Khuluvhe said.

“We need to think about what processes need to be in place to enable people to find employment in the short-, medium- and long-term, as the economy and economic sectors transition,” she emphasised.

It is critical that the TVET system be an active part of the transition in order to match the changes in industry with changes in education and training, noted Maserumule.

A green hydrogen development document, developed in cooperation with the DHET and SANEA, showed that, if South Africa were to move to using its sunshine and wind to produce green hydrogen and use it in many sectors, it could create up to 3.2-million jobs in the economy, with the highest number of jobs being created in the green iron and steel industry, followed by the platinum group metals sector and then the power generation sector.

“TVET colleges can be a critical enabler of the hydrogen economy. For example, the green hydrogen economy can revive the iron and steel sector, but we need to develop a clear master plan and need to understand how to transition education and training to develop new skills or reskill employees,” Maserumule illustrated, based on Hydrogen Society projections.

“We need to ensure adequate and sustained funding for TVET colleges, so that students can become the green artisans and technicians that we need.

“This will require capacitating colleges, improving governance within them and the TVET system, and ensuring accountability across the national departments responsible for progress, including the DHET and DSI,” she emphasised.

Meanwhile, funding for skills development to underpin a just climate transition is a global challenge, said United Nations Educational, Scientific and Cultural Organisation (Unesco) policies and lifelong learning systems director Borhene Chakroun.

“Green funds and economic stimulus packages for green transitions, such as that extended to South Africa, typically include allocations for education and training that are less than 3% of the total funding available. Therefore, it is important to speak about how green transition resources are allocated,” he said.

Attention is being paid to funding the green economy, but less so for education and training, which has implications for greening initiatives.

Further, and importantly, Unesco research has indicated that the first 1 000 days of a child’s life are critical, and investments must include foundational education and early childhood development, Chakroun emphasised.

Universities also play an important role in the green transition, in terms of research, experimentation and innovation, as well as to irrigate and feed the broader education system with skills and educators, he added.

However, there is little articulation of what feeder jobs will allow people to transition to new jobs in a green economy, noted Ramsarup.

South Africa’s national plans and sectoral master plans must think about occupational pathways for students entering the industry and for those currently employed, thereby avoiding graduates not having the required skills for future jobs and employees not being able to move to new jobs, she advised.

*The speakers quoted in this article participated in the ‘Skills for a Just Transition Indaba’ hosted by the Presidential Climate Commission, the DHET and the Energy and Water Sector Education Training Authority on December 7.

Oil & gas Kelly is a square or hexagonal pipe that fits into the drilling rig rotary table bushing (Rig components). They turn to the right as the rotary table turns. In other words, Kelly’s mission is to transfer energy from the rotary table to the drill string.

We can say that kelly is a direct connection between the rig’s surface equipment and the oilfield drilling bit and is a vital element of the rotary system. This function is more commonly performed on modern rigs by a top drive system, power swivel, or power sub directly below a conventional swivel. There is usually no drill string rotation when using a downhole mud motor for directional or other applications.

The manufacturing of Kelly in oil and gas rigs will be with either square, triangular, or hexagonal (most common) cross-sections:

The design of their angled surfaces, or drive flats, is to match into kelly bushing so that as the rotary table rotates to the right, the kelly follows its rotation. Kelly’s design has left-hand threads on their top connections and right-hand threads on their bottom connections to allow drill string right-hand rotation.

API Standards For Oil & Gas Kelly

Thanks to The API, API RP 7G, “Recommended Practice for Drill Stem Design and Operating Limits” contains design & manufacturing criteria for Kellys.

Kelly Sizes

The distance across the drive flats determines the size of kelly (see Figure below)

Kelly Lengths

API Kellys come in two standard lengths:

1. 40 ft – 12.2 m overall, with a 37 ft working space;
2. 54 ft – 16.5 m overall, with a 51 ft working space.

Connections

Square Kelly Connections

API Nom. Size (in.)	Top Connection   Std. (LH) (in.)	Optional (LH) (in.)	Top OD    Std. (in.)	Optional (in)	Bottom Connection    Std.  (RH) (in.)	Bottom OD    Std (in)
2 1/2	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	NC 26	3 3/8
3	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	NC 31	4 1/8
3 1/2	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	NC 38	4 3/4
4 1/4	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	NC 46	6
4 1/4	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	NC 50	6 1/8
5 1/4	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	5 1/2  FH	7
5 1/4	6 5/8  Reg.	4 1/2  Reg.	7 3/4	5 3/4	NC 56	7
**6	6 5/8  Reg.	—	7 3/4	—	6 5/8  FH	7 3/4

**6 in. square oil and gas kelly, not API.

Hexagon Kellys

API Nom. Size (in.)	Top Connection Std (LH) (in.)	Top Connection Optional (LH) (in.)	Top OD Std. (in.)	Top OD Optional (in.)	Bottom Connection Std. (RH) (in.)	Bottom OD Std (in.)
3	6 5/8 Reg	4 1/2 Reg	7 3/4	5 3/4	NC 26	33/8
3 1/2	7 5/8 Reg	5 1/2 Reg	7 3/4	5 3/4	NC 31	41/8
4 1/4	8 5/8 Reg	6 1/2 Reg	7 3/4	5 3/4	NC 38	43/4
5 1/4	9 5/8 Reg	–	7 3/4	–	NC 46	6
5 1/4	10 5/8 Reg	–	7 3/4	–	NC 50	61/8
6	11 5/8 Reg	–	7 3/4	–	5 1/2 FH	7
6	12 5/8 Reg	–	7 3/4	–	NC 56	7

Dimensions of New Kellys

Square Kelly In Oil & Gas Rigs

API Nom Size in	Max Bore A in	Across Flats B (in.)	Across Corner C (in.)	Radius R*  (in.)	Radius Rc (in.)
2 1/2	1 1/4	2 1/2	3.25	5/16	1 5/8
3	1 3/4	3	3.875	3/8	1 15/16
3 1/2	2 1/4	3 1/2	4.437	1/2	2  7/32
4 1/4	2 13/16	4 1/4	5.5	1/2	2 3/4
5 1/4	3 1/4	5 1/4	6.75	5/8	3 3/8
**6	3 1/2	6	7.625	3/4	3 13/16

Hexagon Kelly

API Nom. Size (in.)	Max. Bore A (in.)	Across Flats B (in)	Across Corner C (in)	Radius R* (in.)	Radius Rc (in.)
3	1 1/2	3	3.375	1/4	1 11/16
3 1/2	1 3/4	3 1/2	3.937	1/4	1 31/32
4 1/4	2 1/4	4 1/4	4.781	5/16	2 25/64
5 1/4	3 1/4	5 1/4	5.9	3/8	2 61/64
6	3 1/2	6	6.812	3/8	3 13/32

*Corner configuration at manufacturer’s option.

Kelly Performance In Oil & Gas Rigs

The clearance between kelly bushing rollers & the flat drive surfaces significantly affects its performance in rotating the drill string. Once this clearance increases, the performance starts to decrease.

The primary cause for kelly to wear out is the rounding off of the drive corners. This wear rate is a function of the fit between the kelly and the rollers in the kelly bushing.

In Figure 7: new kelly with the new drive assembly. In Figure 8: worn kelly with the worn drive assembly.

The major reason for this natural wear rounding is the compressive force of the rollers on the drive flats. Also, rotary torque accelerates this wear.

As rounding progresses, it further accelerates the wear process by increasing the clearance and the contact angle between the drive flats and the rollers.

Factors That Affect Oil and Gas Kelly’s Life

For minimal rounding, there must be a close fit between the kelly and the roller assembly, with the rollers fitting the largest spot on the kelly flats. Manufacturing techniques and rig operating practices play important roles in determining this fit.

Manufacturing Process

The manufacturing of square and hexagonal Kellys are from bars with an “as-forged” drive section or bars with fully-machined drive sections. Machined Kellys are more expensive, but they offer the following features, which tend to result in more extended life:

• Machined Kellys had more closely fit to the roller assembly.
• Machined Kellys, unlike forged Kellys, are not subject to the metallurgical process of decarburization or decarb. Decarburization leaves a relatively soft layer of material (approximately V16″ thick) on the drive surface that can accelerate the rounding process and increase the potential for fatigue cracks;

A square drive section tolerates a greater clearance between flats and rollers than a hexagonal drive section.

Smith – Drilling Assembly Handbook

Note: Because of the high-quality steels used in manufacturing Kellys, fatigue failures are not often a problem.

Rig Operating Practices

To minimize rounding, rig personnel should follow these guidelines (Brinegar, 1977):

• Always use new drive-bushing roller assemblies to break in new kelly;
• Frequently inspect and periodically replace drive assemblies to ensure holding clearance and contact angle between the kelly and the rollers to a minimum;
• If the rollers are adjustable, adjust them to provide minimum clearance;
• Lubricate drive surfaces to reduce friction and binding at the rollers and to allow the kelly to slide freely through the kelly bushing.

Nevertheless, we should regularly inspect Kellys for cracks and other signs of wear, particularly within the threaded connections, where the flats join the upper and lower upsets and in the center of the drive section.

Oil And Gas Kelly’s Bending Loads

The areas with the highest stress concentration — and, therefore, the most likely locations for fatigue failure — are where the drive flats join the upper and lower upsets.

Generally, the stress level for a given tensile load is less in the drive section of a hexagonal kelly than in the drive section of a square kelly of comparable size. Hexagonal Kellys are thus likely to last longer than square Kellys before failing under a given bending load.

Kellys can become crooked or bent due to improper handling. Examples of mishandling include:

• Dropping the kelly;
• Misaligning the kelly in the rathole, exerting a side pull on the kelly;
• Using poor tie-down practices during rig moves;
• Not using the kelly scabbard;
• Using improper loading/unloading techniques.

Depending on the bend’s location, it may cause fatigue damage not only to the kelly but to the rest of the drill string and can also result in uneven wear on the kelly bushing.

Unusual side motions or swaying of the swivel are good indicators of crooked kelly. A good field service shop has equipment for straightening bent Kellys, making this an easily corrected problem.

When Picking Up a New Kelly In Oil & Gas Rig

Before picking up a new kelly, check your kelly bushing. The rollers, pins, or bearings may need replacing to return the drive assembly to like-new status. Also, check the bushing body for journal area wear and body spreading. A loose-fitting drive unit can badly damage a new kelly on the first well drilled. Remember to lubricate kelly drive surfaces.

Inspection

At regular intervals, have kelly’s threaded connections checked by your inspector. Remember, these connections are subject to fatigue cracks, the same as drill collar connections. Also, the drive section and upset areas should be inspected for cracks and wear patterns.

Kelly Saver Subs

Kelly saver subs protect the lower kelly connection from wear caused by making and breaking the drill pipe connection each time a joint is drilled down. They also protect the top joint of the casing against excessive wear, if fitted with a rubber protector, and provide an area to tong on when making up or breaking out the kelly. When you need a new stabilizer rubber, an old sub reworked or a brand new one, mention this to your service company before you pick up that new kelly.

What Can You Do With Old Kelly In Oil & Gas Rig?

Use the Other Corners

We can change ends on the kelly by employing a temperature-controlled stubbing procedure. This allows kelly to drive against new corners. Welding is done only in the large diameter round sections. We do not recommend welding on the hexagonal or square surfaces of the kelly.

Remachine Drive Surfaces

With the Heli-Mill, we can machine kelly. This amounts to taking a clean-up cut on each driving surface. Note: Oversize rotary drive rollers are used with re-machined kelly. The bore diameter of the kelly must be small enough to allow enough wall thickness for re-machining.

Straightening an Old Kelly

A bent kelly takes a beating as it is forced through the rotary drive bushings. Some repair centers have straightening presses that can straighten kelly and accurately check the run-out.

If Your Kelly is Too Far Gone, Your best bet is to buy a new kelly.

Reversing The Ends

To a certain point, worn kelly can be repaired by reversing the ends ( Figure 3 ) or re-machining it to a smaller size.

References:

• Smith – Drilling Assembly Handbook
• API RP 7G, “Recommended Practice for Drill Stem Design and Operating Limits“

Solar stocks have the potential be No-Brainer investments.  In Canada, provincial governments are giving them incredible tax breaks so they start to spit out Free Cash Flow very early in their 20-25 year project life.

And that’s just to mostly—but not all the way—catch up to how many big tax breaks the US is giving them.

There is a HUGE political will for solar to succeed, so you have to make them No-Brainers. Both Canada and the US have just increased tax credits and accelerated depreciation to get more solar projects built.

My job is to go find some good management teams in junior public companies who know how to access this non-dilutive capital and make their shareholders very very happy!!

Of course, increasing solar power capacity is good for the environment/climate change etc. In fact, the only bad part—and it’s not really bad—is that the banks get to win yet again.  The (much) smaller solar developers win too, but as I’ll explain, the banks really make out here. (I just like The Little Guy to win a lot, you know?)

Before I get into all this, understand—solar can be profitable without tax rebates.  But tax rebates take solar from ‘that’s an okay return’ to ‘this is a no-brainer’!

Which makes sense, I guess.  If you want to drive investment into renewables, if you want exponential growth, you want a no-brainer.

In the most un-technical of terms, this is what the government has done.

 

IT’S ALL ABOUT FAST PAYBACK
FOR THE BANKS AND SOLAR DEVELOPER

 
I am going to keep this simple. There are two main contributors to tax breaks for solar projects in the United States and Canada:

1. Investment Tax Credit
2. Accelerated Depreciation

The intent of both is straight-forward: Recover the costs of the project, and do it FAST.

If you recall from my prior post, the #1 thing to know about solar is how big the capital costs are.

Paying back capital is what limits free cash and free cash is what determines if a project gets built.

The government recognizes this and is here to help.   How?   By essentially paying for 30-40% of the cost themselves (by not taking taxes).

In the United State the result as much as 40% of the capital cost comes back.  In Canada it is a bit less because Canada’s accelerated depreciation is a little more drawn out.  But either way it is a big benefit.

 

#1 REBATE: THE INVESTMENT TAX CREDIT

 
How does the government do this?  For one, with the investment tax credit (ITC).

This credit has been around in one form or another since 2006 in the United States.  It was supposed to be tapered off, starting in 2020.   No more: the recent Inflation Reduction Act (IRA) entrenched it for the next 10 years, which will give solar (and wind) a long run-way.

The ITC gives a tax rebate equal to 30% of the capital cost of the solar project.  For a $300 million project, the ITC allows the owner to deduct $90 million of it.

I was surprised to learn that until this year, Canada did not have an ITC of their own.  But now that has changed.   This fall Canada met the ITC with their own Clean Technology Investment Tax Credit.  Like the ITC, the credit is for 30% of capital put towards renewable energy generation and storage.

Obviously, a $90 million rebate on a $300 million project is a big deal.  But it is made much more of a big deal by the way the government lets you use it.

 

ITC TRANSFER-ABILITY

 
Let’s start with the basic premise that a tax rebate is worth more the faster you can use it.

If you are a solar company, you may not have a lot of taxes to offset.  It may take you 5 years to use $90 million of tax rebate (in other words have $90 million of profits to offset).  Maybe more.

Enter the transferability of the ITC.   With it, comes the invention of solar tax equity financing.

Solar tax equity is matching a solar project with an equity investor who has a tax liability they can offset right now.

The structure usually looks something like this:

Source: Woodlawn Associates

You have a solar developer, a tax equity partner, and usually some other financing partner that lends the rest of the money (they aren’t very important for us right now).

Together these parties form a “ProjectCo”.  The ProjectCo is where the solar project lies.

The whole reason for the structure is to let the tax equity partner benefit from the taxes.  While you, the solar developer, still own the project.

How does it work?  The ProjectCo is structured to let the tax equity partner take 99% tax ownership for the first year, the year when the tax credit is realized.

Every structure is different, but they usually look something like the table below, which shows the economic interest of the tax equity partner over time.

Source: Woodlawn Associates

For the moment, focus on the ITC row.  The tax equity partner gets 99% ITC ownership for tax purposes in the first year.  In other words, that entire $90 million rebate is their write-off.

What do you get as solar developer?   The tax equity partner funds some of your project.

For our $300 million solar project, the tax equity partner may finance $85 million (give or take) in return for the tax credit of $90 million.

Not bad.  But that is just part of it.  The tax equity partner will likely finance even more.  I will get to that shortly.

But first, who is this tax equity partner?

 

THE BIG WINNERS? THE BANKS (OF COURSE)

 
Well, the banks aren’t the only big winners here (the solar developer wins too, as does the environment).  But it never hurts the ole page views to make the banks look like the bad guys.

The most common tax equity partners are the banks.  In the United States the 3 biggest partners in tax equity are Bank of America (BAC – NYSE), JP Morgan (JPM – NYSE) and Wells Fargo (WFC – NYSE).

It makes sense.  Banks virtually always make money.  They have lots of taxes to pay.   They are happy to share a ~10% return.  They have the back-office to handle complicated structures and the capital to make large short-term loans.

The takeaway here is that this is all done to realize the tax credit as fast as possible.  Because the faster it is realized, the more money it is worth upfront to the developer.

 

#2 REBATE: UPFRONT DEPRECIATION

 
The second tax rebate is accelerated depreciation.  Companies in the United States can depreciate 85% of a solar project in the first year of operation (Canada has something similar, but the depreciation is over two years, not one).

In both the US and Canada, this isn’t a new credit; it was introduced in the Tax Cuts and Jobs Act of 2017 in the US and has been around since 2005 in Canada.  The recent IRA in the United States extended the credit to apply to renewable storage and hydrogen projects.

Upfront depreciation can be a big benefit to developers.  Like the ITC, it takes advantage of banks as partners.

Back to our $300 million capital solar project.  The ITC effectively lowered the price tag by $90 million.  Now, because of accelerated depreciation, 85% of the other $210 million can be depreciated in the first year of the project ($178.5 million).

In order to take full advantage of this, the solar developer partners likely deal with that same bank that gave them ITC funding.

Below is a re-post the chart I gave above, showing the structure of the partnership.

Source: Woodlawn Associates

We already talked about the ITC, of which the tax equity partner gets 99%.  But you’ll notice that the tax equity partner is also getting 99% of the income from the project in the first year.

Why?   So that they can benefit from the accelerated depreciation.  (In Canada the structure is all the same except it’s over two years, not one.)

Here is the benefit to the tax equity partner.  Let’s say they have a tax rate of 25%.  With $178.5 million depreciation they can offset $44.5 million of taxes.

In return for the $44.5 million of tax-offsets, the tax equity partner will give the developer more money for the project. 

How much?  That will depend on factors like the timing of the financing, when they get to realize the benefits, what the discount rate is, and some other aspects of the deal (usually the tax equity partner gets some cash flow stream as well – Cash from PPA in the table above).

Let’s say you get $35 million from your partner in return for the accelerated depreciation.  Add that to the $90 million ITC and you have reduced your $300 million project by $125 million – or 41%.
Not bad!
 

MAKING IT A NO-BRAINER

 
If a mildly-profitable $300 million project becomes a $175 million project, obviously that project is no longer just mildly profitable.  Some might say, it is a no-brainer.

Which is what the government wants.

Together, these two tax incentives allow solar projects to realize a lot of tax benefits right away.   Which effectively reduces the cost of the project by that amount.

What does that mean for us investors?

As long as these credits exist, the mantra will be: “build baby, build”.  Companies that are involved in these projects, either developers, financers or manufacturers, will all benefit.

The trick, and our job as investors, will be to find the one’s that will benefit the most.

That is my goal over the next few months.  Which companies stand to benefit from these big government subsidies which are now virtually written in stone for the next 10 years?

My hope is that I can find a few big winners.  Given the market we’ve had over the past year, we all could use them.
 
EDITORS NOTE

As an addendum, I would say The Little Guy did win once–in the early 2010s the premier of Ontario (14.5 M population), Dalton McGuinty, set out to transform the Ontario electric grid. (A Canadian premier=US governor).

They pushed out a build of wind and solar power projects.  To encourage those projects, they signed 20-year power purchase agreements (PPA) with guaranteed power prices.

Flash forward a few years and it was clear that the government had made a BIG mistake.  They had way-overpaid for power (2x the going-rate for wind, 3-4x for solar) to get the plants built.  And now Ontario was faced with skyrocketing electricity rates.  Many farmers had installed huge moving solar arrays in their yards and made big bank!! 

Farmers signed PPAs as high as $420/MWh! Holy cow!

Well, a few years later the Ontario government was skewered.  Deals like this saddled the province with high power prices and in large part led to the defeat of then Ontario premier Kathleen Wynne’s Liberal government (she took over from McGuinty).

In 2020 the provincial (now a Conservative premier, Doug Ford) government bit the bullet and said the government would pay for the high rates, rather than pushing those rates down on rate payers (which, given that rate payers are generally tax payers, could be taken as – po-tat-o/po-tato – but well, politics…).

Since then, governments have learned their lesson.  Not that they should not subsidize renewables.  But that they need to more discreet about it. Government is much better today at making renewable subsidies less painful.

Higher monthly power bills do NOT win votes! Far preferable are write-offs of depreciation and capital that can be transferred to 3^rd parties in return for upfront cash.

That’s where the banks started to win—and win big.