Why do oilfields take damage when production is paused?

[Wombat + 1,028]

2 minutes ago, Jay McKinsey said:

Well the EIA disagrees with the graph . Has nothing to do with being reserved.

That graph is SOURCED from the EIA and IEA! Are you saying the EIA disagrees with it's own graph that it published today? I think it more likely you have simply misinterpreted the spreadsheet u refer to, which is HOW MUCH OIL IS CURRENTLY STORED, not HOW MUCH SPACE THERE IS? Do you see the difference Mr Expert?????

[wrs + 893]

Well I don't have to worry about any damage to my XTO section in March, they reduced output but didn't shut anything in.  They are running about 60% off their normal volume for March.  

[Jay McKinsey + 1,490]

12 minutes ago, Wombat said:

That graph is SOURCED from the EIA and IEA! Are you saying the EIA disagrees with it's own graph that it published today? I think it more likely you have simply misinterpreted the spreadsheet u refer to, which is HOW MUCH OIL IS CURRENTLY STORED, not HOW MUCH SPACE THERE IS? Do you see the difference Mr Expert?????

Good grief! The graph is sourced from Kayrros, IEA , EIA and BofA. EIA did not publish this graph. It clearly says "Assumes US inventories reach the previous peak." Let me explain this to you Mr. Genius bragging about your IQ and 3 degrees - What this analyst of yours did was look at the EIA Weekly Ending Stocks of Crude Oil and take the previous peak (March 2017) as a metric for max proven capacity and subtract the current stock.  The spreadsheet is titled "Weekly U.S. and regional crude oil stocks and working storage capacity"

"To estimate current working storage capacity utilization, EIA compares weekly reported crude oil stocks (excluding pipeline fill inventory) to the most recently available monthly refinery and tank farm storage capacity (data as of September 30, 2019). Utilization estimates are based on the ratio of stock levels to working storage capacity, which EIA defines as the difference in volume between the maximum safe fill capacity and the quantity below which pump suction is ineffective (bottoms). Working storage capacity accounts for normal operational factors that limit storage capacity. Working storage capacity is always less than shell storage capacity, which EIA defines as the design capacity of a petroleum storage tank or cavern." https://www.eia.gov/petroleum/supply/weekly/wcrudeoilstorage_notice.php

I might only have 2 degrees but one of them does say Doctor on it.

[Wombat + 1,028]

8 minutes ago, Jay McKinsey said:

Good grief! The graph is sourced from Kayrros, IEA , EIA and BofA. EIA did not publish this graph. It clearly says "Assumes US inventories reach the previous peak." Let me explain this to you Mr. Genius bragging about your IQ and 3 degrees - What this analyst of yours did was look at the EIA Weekly Ending Stocks of Crude Oil and take the previous peak (March 2017) as a metric for max proven capacity and subtract the current stock.  The spreadsheet is titled "Weekly U.S. and regional crude oil stocks and working storage capacity"

"To estimate current working storage capacity utilization, EIA compares weekly reported crude oil stocks (excluding pipeline fill inventory) to the most recently available monthly refinery and tank farm storage capacity (data as of September 30, 2019). Utilization estimates are based on the ratio of stock levels to working storage capacity, which EIA defines as the difference in volume between the maximum safe fill capacity and the quantity below which pump suction is ineffective (bottoms). Working storage capacity accounts for normal operational factors that limit storage capacity. Working storage capacity is always less than shell storage capacity, which EIA defines as the design capacity of a petroleum storage tank or cavern." https://www.eia.gov/petroleum/supply/weekly/wcrudeoilstorage_notice.php

I might only have 2 degrees but one of them does say Doctor on it.

Yes, assumes US inventories reach the previous peak. Unless 70m barrels of storage have been removed since previous peak, there is still 70mb of storage left? PS: The EIA does not have accurate data, they make "guesstimates", not as accurate as those of industry. Utilization ESTIMATES blah blah blah...

[Jay McKinsey + 1,490]

4 minutes ago, Wombat said:

Yes, assumes US inventories reach the previous peak. Unless 70m barrels of storage have been removed since previous peak, there is still 70mb of storage left? PS: The EIA does not have accurate data, they make "guesstimates", not as accurate as those of industry. Utilization ESTIMATES blah blah blah...

I made no claims as to EIA accuracy, I just said they reported much more than 70mb of storage left.

[Wombat + 1,028]

21 minutes ago, Jay McKinsey said:

Good grief! The graph is sourced from Kayrros, IEA , EIA and BofA. EIA did not publish this graph. It clearly says "Assumes US inventories reach the previous peak." Let me explain this to you Mr. Genius bragging about your IQ and 3 degrees - What this analyst of yours did was look at the EIA Weekly Ending Stocks of Crude Oil and take the previous peak (March 2017) as a metric for max proven capacity and subtract the current stock.  The spreadsheet is titled "Weekly U.S. and regional crude oil stocks and working storage capacity"

"To estimate current working storage capacity utilization, EIA compares weekly reported crude oil stocks (excluding pipeline fill inventory) to the most recently available monthly refinery and tank farm storage capacity (data as of September 30, 2019). Utilization estimates are based on the ratio of stock levels to working storage capacity, which EIA defines as the difference in volume between the maximum safe fill capacity and the quantity below which pump suction is ineffective (bottoms). Working storage capacity accounts for normal operational factors that limit storage capacity. Working storage capacity is always less than shell storage capacity, which EIA defines as the design capacity of a petroleum storage tank or cavern." https://www.eia.gov/petroleum/supply/weekly/wcrudeoilstorage_notice.php

I might only have 2 degrees but one of them does say Doctor on it.

Unless your degrees include the study of Green's Theorem or Einstein's General Theory of Relativity, you probably don't understand the math behind the supply/demand equation of the oil industry?

[Wombat + 1,028]

1 hour ago, Jay McKinsey said:

What the EIA is saying is that there is about 255mb of that floating top space still available.. Has nothing to do with being reserved.

OK, my apologies for not reading ur response carefully. U did say 225 MORE! However, I find that hard to believe given that gas pipeline operators are already converting their pipes for oil storage and expect to start filling them in about 3 weeks. Don't want to quibble any longer, the reason I posted that graph was to let Dan Clemenson know that we will soon have an inventory overhang of about 700-900mb, not the 300m he believes. I think that Eric Gagen made a good point above that storage is not yet full, but is in some places. Clearly, the US is getting very close if you ignore SPR.

[Walter Faber + 48]

Regarding the original topic, check out this oilprice.com article by an experienced engineer. 

https://oilprice.com/Energy/Crude-Oil/The-Oil-Wells-That-Will-Never-Recover.html

[Dan Clemmensen + 1,011]

4 hours ago, Jay McKinsey said:

What the EIA is saying is that there is about 255mb of that floating top space still available.. Has nothing to do with being reserved.

Let's review. I originally just said "storage" when I meant "storage potentially available for low-volume Texas wells". A made it clear that I was referring to storage that is currently physically empty, even though is is reserved. The idea is to find a way to allocate that strorage such as to minimize physical destruction of existing physical capital (wells, pumps, pipelines, oil fields) in order to permit a rapid resumption of production when consumption picks back up. "total US storage", I'm told, is not relevant because it takes too long to move the oil, so we are just asking if, in theory, allocating storage to permit minimal maintenance-level production would in fact prserve capitalm, and if a mechanism can be put in place to implement this. As of the time of my original speculation, there was about 70 million bbl of empty storage at Cushing, and all of it was already reserved.

[Eric Gagen + 713]

5 hours ago, Walter Faber said:

Regarding the original topic, check out this oilprice.com article by an experienced engineer. 

https://oilprice.com/Energy/Crude-Oil/The-Oil-Wells-That-Will-Never-Recover.html

I worked for a while with Dave Messler before he transitioned into journalism.  He knows his stuff, and I would say this article is an excellent summary of the sorts of issues that are liable to come up with some of the wells that get shut in. 

Edited May 1, 2020 by Eric Gagen

[Eric Green 0]

 

• From what I know about wells, not only is it time consuming and expensive to Shut in a well, but they can gain a large amount of build up depending on how long they remain plugged, sometimes needing to be Re-Drilled or even, after being shut in for so long. Sometimes the wells can even begin to break down, requiring new pipe to be run down hole, overall a long time consuming and costly project. Especially seeing as drill sites have multiple wells per pad, and multiple pads per oilfield. But what do I know, I just work under the hook of a Crane

[pat1369 + 1]

I've been in the industry since the late 80's, fracking isn't anything new, there's very few non coal-seam wells in the San Juan basin that weren't fracked, I started out in the work over/stimulation business and most wells in a shale formation can be brought back online with minimal loss(it's what I used to do) . With the low price definitely less loss than producing in the red. If the well won't come around typically you'd drill another in close proximity and use the old one for water flood or sidetrack the existing well and move on. Point is that the market needs to be there if the USA oil industry is going to be significant in a world market, or even able to sustain Americans needs. In my opinion shut them in and wait for profitable pumping at a loss is stupid and production will continue to fall anyways without as many new wells being drilled. We need to patiently wait for profitable conditions or it will be the same cycle of boom and bust forever.

[pat1369 + 1]

7 hours ago, Eric Gagen said:

I worked for a while with Dave Messler before he transitioned into journalism.  He knows his stuff, and I would say this article is an excellent summary of the sorts of issues that are liable to come up with some of the wells that get shut in. 

Definitely true, but probably less losses in the long run than producing in the red.

[John Galt + 1]

On 4/21/2020 at 2:43 AM, Walter Faber said:

I have read repeatedly in articles that some types of oil reserves and some of the equipment used for extraction can take damage when production has to be stopped, implying that you cannot simply pause production and restart once demand bounces back. Could you please help me out with explanations and links to understand why this is the case? 
I am aware of economic damage which can endanger the company, I am asking explicitly for technological/gelological/chemical/physical factors here. 

Regards and thanks in advance

 

See article Oil Wells That Will Never Recover by David Messler in oilprice.com for an engineer's view on bad things that can happen to shut wells.

[Tom Kirkman + 8,860]

On 4/21/2020 at 3:43 AM, Walter Faber said:

I have read repeatedly in articles that some types of oil reserves and some of the equipment used for extraction can take damage when production has to be stopped, implying that you cannot simply pause production and restart once demand bounces back. Could you please help me out with explanations and links to understand why this is the case? 
I am aware of economic damage which can endanger the company, I am asking explicitly for technological/gelological/chemical/physical factors here. 

Regards and thanks in advance

 

17 hours ago, John Galt said:

See article Oil Wells That Will Never Recover by David Messler in oilprice.com for an engineer's view on bad things that can happen to shut wells.

 

The Oil Wells That Will Never Recover

also

Why it took so long to dial back oil production, despite the glut

Something weird happened on the oil market last week. For a few minutes on April 20, the price of a barrel went negative for the first time ever. The unprecedented collapse of prices is linked to the pandemic, which has caused people to stop doing oil-guzzling things like flying and driving. There’s now so much extra petroleum on the market that the world is running out of places to put it. If you’re an oil producer, it seems like the sensible thing to do in this situation would be to … stop producing so much oil.

On Friday, members of the Organization of the Petroleum Exporting Countries, Russia, the US, and others will begin scaling back their production by nearly 10 million barrels per day. They hope that this will help stabilize prices and take some pressure off of producers and refineries that are scrambling to find a place to store the excess. But the rollback isn’t likely to be enough. Oil producers would have to reduce production by almost three times that amount to match the downturn in demand. So why don’t they?

The short answer is because temporarily closing or “shutting in” a well costs money—and potentially lots of money. It’s not just about the foregone revenue, which is less of a concern when prices are dipping into the negative. It’s about what happens when the well is opened back up. “Shutting in a well is not especially difficult,” says Eric van Oort, a petroleum engineer at the University of Texas at Austin. It’s mostly a matter of shutting off a master valve at the surface, much like turning off a faucet. But, he says, “operators are generally reluctant to shut in their wells if they don’t absolutely have to, because they know they’re going to incur some damage on those wells.”

The US has been the largest producer of crude oil in the world for the past two years, and the vast majority is dredged up in Texas and on offshore derricks in the Gulf of Mexico. On land, most of America’s crude is produced from shale reservoirs, which trap the oil in rocks with low permeability. To set it free, companies use a technique called hydraulic fracturing, or fracking, that opens cracks in rocks deep in the Earth by blasting them with water or gas.

Shut-ins are a normal part of oil production, but they are usually limited to a few wells at a time and mostly undertaken for repairs. Petroleum producers have known for decades that shale wells that have previously been shut in produce less oil when they’re reopened, says John McLennan, an expert in geomechanics at the University of Utah Energy and Geoscience Institute. But the exact cause of the damage is often unclear. McLennan says that one of the most well-supported explanations is water blockage.

Oil and water

A well typically taps into a mixture of oil and water. Both are pumped to the surface, but the water is treated as waste. When a well is shut in, the ratio of oil to water is recalibrated, since there’s no longer a big pipe sucking on the fissures in the rock. Because the rock in shale wells isn’t very permeable, water may accumulate in the fractures. When the well opens up again, it may end up producing more water than oil, because the accumulated H2O impedes the movement of oil. Shale wells typically operate on thin profit margins, so even a relatively small loss in productivity could make the well unprofitable.

Van Oort says the amount of time a well is closed doesn’t really affect how much damage the shut-in inflicts on the reservoir. Once the well is closed, the damage is done. If producers have to repeatedly shut the well, the damage can compound over time and reduce productivity even more. “It is always best to leave the well alone once you go to production,” says van Oort.

The situation is a bit better for the roughly 1,000 offshore oil derricks in the Gulf of Mexico. These are typically conventional wells where a pipe is drilled into the ground and oil is pumped up—almost like sucking a milkshake through a straw. Offshore oil producers are accustomed to temporarily turning wells off during hurricanes, and shut-ins don’t have as big of a negative effect on their ability to produce oil. The reason for this, says McLennan, is because the offshore reservoirs are more permeable, which allows the oil to flow more freely.

But even though offshore reservoirs might not sustain as much damage from shut-ins, McLennan says the wells are a bit more challenging to turn off. Some subsea pipelines may need to be protected if the oil contains waxy paraffins, which can solidify in pipelines at the bottom of the ocean, where temperatures are just a few degrees above freezing. So before an offshore well can be turned off, there’s often a lot of preventative maintenance that needs to be done, like flushing the pipes and filling them with a fluid that prevents wax formation. “If you don’t do the preventative maintenance in advance of a shut-in, it can have serious consequences for subsea flow lines,” says McLennan.  ...

 

[Douglas Buckland + 6,308]

“The US has been the largest producer of crude oil in the world for the past two years, and the vast majority is dredged up in Texas and on offshore derricks in the Gulf of Mexico.”

Offshore derricks dredge up oil? First off, oil is not ‘dredged up’ offshore. Secondly, derricks (or masts for those of you who know the difference) are utilized for DRILLING not PRODUCTION.

If you can’t get the terminology correct, it diminishes the credibility of what you are writing.

[Dan Clemmensen + 1,011]

7 hours ago, Douglas Buckland said:

“The US has been the largest producer of crude oil in the world for the past two years, and the vast majority is dredged up in Texas and on offshore derricks in the Gulf of Mexico.”

Offshore derricks dredge up oil? First off, oil is not ‘dredged up’ offshore. Secondly, derricks (or masts for those of you who know the difference) are utilized for DRILLING not PRODUCTION.

If you can’t get the terminology correct, it diminishes the credibility of what you are writing.

Doug, Tom was quoting the Ars Technica article. Those guys know a lot about tech. Oil, not so much.  Ars Technich picked the story up from Wired.com, who are even less Oil savvy, and they are writing for a general audience:

https://www.wired.com/story/the-world-is-still-producing-more-oil-than-it-needs-why/

(Ars Technica probably has permission from Wired, but Tom may not have gotten permission from them. I would not quote so extensively from a copyrighted source like that myself.)

[Douglas Buckland + 6,308]

Regardless of who quoted from whom, whoever started the ball rolling did not do their homework.

Their editor did not do theirs.

If this would have been a thesis, how would it have been graded?

My point is, it is poor ‘journalism’.

[Wombat + 1,028]

7 hours ago, Douglas Buckland said:

Regardless of who quoted from whom, whoever started the ball rolling did not do their homework.

Their editor did not do theirs.

If this would have been a thesis, how would it have been graded?

My point is, it is poor ‘journalism’.

Relax Doug, Tom was just trying to give a newbie a general picture of where us oil production comes from and probs with shutting in. The editor does not have time to correct every technical error in a quickly pasted article. Good on you for doing so, but don't be so harsh on poor ol Tom for trying to help a newbie in the quickest way possible? Poor journalism yes, intended to be a thesis, no. As I say, perfectly acceptable to let good folk such as yourself point out the errors, perhaps a little more politely next time?

[carbonates + 22]

I'm late to this discussion, but as a geologist working in the Permian, with experience in Eagle Ford, Niobrara, and most other unconventional basins in the US,  I may have some useful insight. 

"Oil fields" do not necessarily get damaged by wells being shut-in, but individual wells may be seriously damaged to the point of becoming P&A candidates after being shut-in. The reasons are complex, and sometimes unique to single wells because of their characteristics. Many wells have slight differences in their initial completion technique, differences in landing depth, and most importantly differences in age, so the resulting reservoir pressure and fluid mix is different. 

For horizontal unconventional wells, and even horizontal tight oil and gas wells, there are multiple problems. Dry gas wells in shale may have the fewest problems because they often have no water production, and no other issues that come with multiple phases in the reservoir. But dry gas wells are not the issue right now, so I am addressing oil wells, with associated gas and water that comes with them.  

1. Wells with higher water cuts often end up with even higher water cuts after shut-in. Water becomes more mobile with time. Because wells with higher water cuts are more likely to be uneconomic, they are most likely to be shut-in, and are more likely to become P&A wells when reopened. 

2. Wells with high doglegs are likely to have problems coming back online. The high parts of the wellbore will fill with lighter fluids, like gas, and the lower points will fill with sand and heavier fluids. The result is that more distant parts of the well may not have enough energy remaining in the reservoir to overcome the resistance of these fluids and debris. Most horizontal wells are not that straight because the extra time and cost to drill a perfectly straight wellbore is something drillers mostly discount. 

3. Cross flow becomes a problem and is impossible to measure or estimate without a series of downhole pressure gauges that very few wells have. Different frac stages have differing pressures and the higher pressure will equalize with the lower pressure stages in a sitting well. In some stages this may cause the proppant to fail. Few operators can afford to use ceramic proppants these days, so proppant damage will be more likely than when ceramics were more common. In other stages that held more oil, they will be contaminated with water coming back from the well and this may damage flow in near wellbore fracs. There could be interactions between expandable clays and water that that clay has not been exposed to until this crossflow. 

4. Wells on electric submersible pumps will be expensive to restart. Electric submersible pumps are expensive, and often rebuilt ones are used to cut costs. They cannot sit idle without experiencing some damage, like corrosion, and are costly to remove and replace. The cost of the submersible pump is sometimes enough reason to plug a well. Other times, if possible, the well must be converted to rod pump or gas lift, which ever is possible and appropriate. This cost may very well exceed the economic value of the well.

5. Reservoir pressure. If the reservoir pressure has already been depleted, or was never that great to begin with the well may not flow after restart. Pumping it may not help. In overpressured formations like the Wolfcamp, at least one operator has expressed confidence that newer wells will not have issues, but older Wolfcamp wells may very well have issues. 

6. Skin damage. In wells that have high paraffin oil, like most of the Permian Basin, wells that have been producing for a while, or those that are shallower, may not remain at high enough temperatures to keep paraffin, asphaltenes, and other precipitants found in connate water, from forming in the pores and fractures around the wellbore, which is naturally colder than the reservoir, and the well may end up naturally plugged in ways that are difficult to remediate. This problem is probably more common in conventional wells, but is certainly possible and more difficult to remediate in a horizontal. 

7. Hammer. Just like water hammer in your home plumbing, restarting a well causes a kinetic force that "hammers" the well. Slow restarts may be needed, and fast restarts may cause more damage. This cycle damage could pinch off fractures leading to productive parts of the well that may never contribute flow again. The economics of slow starting are often an obstacle to having the patience to slowly open a well over several weeks or even months. 

8. Retrograde condensate. In a well that produces a lot of condensate (e.g' much of the oil window of the Eagle Ford, and much of the Permian) a shut-in well may clog itself up with condensate that comes out of the gas phase and enters the liquid phase as the well sits and lighter phases move up the wellbore. The condensate reduces near well-bore permeability clogging pore throats and stops flow. I am not sure how often this will happen but I am very concerned about it because when it happens it literally shuts down production and is hard or impossible to recover from. 

Conventional wells will have a few of the same problems.

1. Paraffins in some formations in the Permian are likely to destroy some shut-in conventional wells, as treatment is expensive and difficult. Hot water, solvents, and acids often have to be pumped down the well, but if enough paraffin is in the well those remedies may never reach the perfs. 

2. Reservoir pressures in vertical shut-in candidates are likely to be low, because the lowest producing wells are the most likely to be shut-in. In a conventional field reservoir pressures may have a chance to equilibrate across the field, and this could be good or bad. In some reservoirs the gas cap may get larger, making what were once oil wells into gas wells. In others the oil may continue to move updip leaving the well as a water well. This is not easy to figure out from a cased well. It often takes specialized logging tools that can detect oil behind pipe to figure out where the oil is now. This costs money that may not be justified to spend. 

3. Formation of salts. A flowing well tends to keep itself cleaner near the perfs. If perfs are left to sit covered in water or oil, precipitation of calcium carbonate, calcium sulfate, barium salts, and many others can build up and damage both the nearby reservoir and the well perforations. These are often treated later with acids, but it doesn't always work well. 

4. Cross flow can be an even bigger problem in vertical wells that have multiple perforations. These perforations may be in reservoirs that were not in communication with each other and while producing, did not have any chance to equalize. Now the fluids from the higher pressure reservoir will be pushing into the lower pressure reservoir with all sorts of unpredictable chemical and physical reactions. Just the water mixing can cause precipitation of salts that will close pores. Some states, such as Texas, have not restricted operators from commingling formation production so this will be a problem they probably did not expect when they completed the well. 

5. Corrosion. Both sweet corrosion and sour corrosion may be more likely in a shut-in well. A build up of hydrogen sulfide due to bacterial processes can create acidic water that acts on the well bore. As pH decreases, steel can crack, and become fatigued. In some instances the well bore may collapse. Often oil and gas contain carbon dioxide in solution. This creates carbonic acid as it equalizes with water in the well, this can result in deposits of siderite, FeCO3 on production tubing, casing, and downhole equipment. I have seen cases where this siderite permanently plugged the perforations in a well. In any event, it damages equipment and obstructs flow. 

Basically, shutting in a well becomes a chemistry and physics experiment and the outcome is likely to be different for each well, but the danger remains that many wells will have negative effects and to me, seems more likely than the cases where well production might benefit from a shut-in. 

 

Edited May 7, 2020 by carbonates

[Walter Faber + 48]

5 hours ago, carbonates said:

6. Skin damage. In wells that have high paraffin oil, like most of the Permian Basin, wells that have been producing for a while, or those that are shallower, may not remain at high enough temperatures to keep paraffin, asphaltenes, and other precipitants found in connate water, from forming in the pores and fractures around the wellbore, which is naturally colder than the reservoir, and the well may end up naturally plugged in ways that are difficult to remediate. This problem is probably more common in conventional wells, but is certainly possible and more difficult to remediate in a horizontal. 

Thank you for your detailed reply, very appreciated! 

Could you please explain the boldened part, why is it this way? 

 

[carbonates + 22]

Just the act of drilling a well reduces the near-well bore temperature as the drilling mud is circulated from the surface to the bottom of the hole so the well starts off with a slightly lower temperature than the surrounding rock. Introducing frac fluid and sand will further reduce the temperature because that material is not heated to reservoir temperatures before being pumped downhole. Then during flowback most of that water is produced, after being given time to absorb heat in the reservoir and warm up to reservoir temperature. During production the change in pressure across the reservoir to wellbore boundary also induces a cooling effect, just like venting compressed air out of a SCUBA tank will cool off the tank. It is much the same principle that an air conditioner uses to move heat by compressing a fluid and letting it expand.  It is a function of the Ideal Gas Law, PV=nRT, where P is pressure, V is volume, n is the volume of gas, R is the ideal gas constant, and T is temperature (and for practical purposes you can ignore n and R as constants). 

Edited May 7, 2020 by carbonates

[Coffeeguyzz + 454]

Mr.  carbonates 

Those were outstanding comments and I thank you for sharing your knowledge.

Quick question if you are able to respond ...

Several Bakken operators have adopted gas lift early on for virtually all their new wells.

There has been a somewhat recent introduction by a few companies to try gas lift that extends the inject tubing within a larger tubing in efforts to sweep the well to the heel.

There, a packer is positioned where standard vertical valves are placed to continue lifting the fluid to surface.

Have you any familiarity with this?

If it does work, would it overcome several potential problems that you so eloquently described?

[Douglas Buckland + 6,308]

@carbonates

“Most horizontal wells are not that straight because the extra time and cost to drill a perfectly straight wellbore.”

Thank you for your detailed explanation concerning damage to a shut-in well.

I am somewhat confused by your comment above. Any horizontal or directional well will be drilled to a ‘target’. As ‘time is money’ they are usually drilled as direct as possible towards that target. Doglegs are to be avoided (dogleg severity being tracked while drilling). The reason is not so much to prevent gas on the high side/sand on the low side, but to avoid issues later while running casing or tools into the well.

Micro doglegs are created while steering the bit, and also simply from the bit turning to the right, reactive torque and drilling through different formations or non-homogenous rock within the same formation.

[carbonates + 22]

Coffeeguyzz,

I am a geologist and not a production engineer so I have some uncertainty about my answer. I do know that gas lift is often more cost-effective than immediately going to rod lift or ESP. To do what you are describing probably takes a coiled tubing rig, because wireline cannot place production equipment down in the lateral. That would be a more expensive completion technique, but perhaps it has enough benefits to be effective. I can guess that it eliminates some problems with porpoising wellbores. In a shut-in situation, I think most of the issues I described would still be problems. Much of the potential damage from a shut-in takes place in the reservoir near the wellbore and the production method you are describing would not have any way to prevent this when it is shut down and not lifting fluids.  I appreciate you pointing it out and I will look into it as it sounds like a good idea. 

Edited May 8, 2020 by carbonates