SPE PB Young Professionals Gas Li Shop Tour: Feb 6, 2025
SPE PB General Sec on Mee ng: Feb 18, 2025
SPE PB Volunteer Event: Feb 21, 2025
SPE PB DASG Lunch & Learn: Feb 27, 2025
SPE PB—Scholarship Deadline: Mar 31, 2025
SPE PB—13th Annual Plays & Clays: Apr 11, 2025
71st Annual Southwest Petroleum Short Course: Apr 21-24, 2025
SPE PB—Awards Banquet: Apr 30, 2025 Save The Date!
CHAIRMAN’S CORNER
Dear SPE Members,
Tyler Yancey Petroleum Engineer Chevron
SPE-PB Chairman 2024-2025
As we step into the month of February, it is with great pride and enthusiasm that I share with you and celebrate a truly remarkable milestone for our organiza on. The year 2025 marks the 80th Anniversary of the SPE Permian Basin Sec on! This historic achievement is a testament to the dedica on, hard work, and commitment of our leadership and members over the decades. We extend our hear elt gra tude to every individual who has contributed to the growth and success of SPE, ensuring that we con nue to thrive and make a posi ve impact on our industry.
In addi on to commemora ng our 80th Anniversary, we are currently in the midst of Awards nomina on season. This is an excellent opportunity to recognize and honor those who have made significant contribu ons to our field. We have six pres gious Regional Award Categories, including the Service Award, Faculty Award, Public Service Award, Young Professional Service Award, and Corporate Award. Similarly, on an interna onal level, we have six dis nguished categories for the SPE Major Awards, Technical Awards, Service Award, Faculty Award, Public Service Award, and Young Professional Service Award. We encourage you to par cipate ac vely in the nomina on process and help us celebrate the outstanding achievements of our peers. You can find more informa on on awards here h ps://www.spe.org/en/awards .
Dates and Deadline for Awards
· 15 February | Interna onal Nomina ons Close
· 25 February | CV/Resume or LinkedIn Profile & Suppor ng Le er(s) Due - Interna onal
· 1 March | Regional Nomina ons Close
· 10 March | CV/Resume or LinkedIn Profile & Suppor ng Le er(s) Due - Regional
With our remarkable 80-year anniversary it is very apparent SPE Permian Basin strives for excellence. Here recently I was able to see excellence and brilliance firsthand in our community.
(Con nued
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CHAIRMAN’S CORNER
I recently volunteered and helped judge at a few MISD robo cs compe ons where students from different junior high and high schools competed in team design, presenta on, program, and build a robot to perform in a compe on with a common set of rules to play. By observing these students, I saw so much encouragement amongst each other. From “you got this,” to “I believe in you,” and several secret handshakes to mo vate each other. There was one group in par cular that had a student named Drake. You could see him silently mimic the words through his team's presenta on as he had everyone’s part memorized. As they finished reci ng their part, he would make his arm bent at the elbow, hand clenched into a fist, then, with a quick, energe c mo on, (silent but loud enough to see and hear), celebrate with a “YES!” as each member aced their part. He was so charged up and excited about his team members' success and during the speech would walk up to them and give a high five as they finished. Seeing this in person really inspired me and made me think about, do we do this as grown adults? Why not? We need to carry this type of ac on into our lives to share with others the recogni on and encouragement. Seeing this experience in person reminded me of another piece of advice I heard recently during a speech at a different func on. The speaker shared their thoughts on what it takes to be the best. They said, if you want to be the best, bring out the best in everyone around you. If you do that, the rest will take care of itself.
We have several events in February and more to come. I want to encourage you to come out to SPE events, volunteer to be a presenter by reaching out to our Board Members, volunteer to help support, volunteer to take on more, and help bring out the best in everyone around you.
· Feb 6th Young Professionals Gas Li Shop Tour
· Feb 18th General Sec on Mee ng Duncan Blue “Are you Drilling Mor and Enjoying Less”
· Feb 21st West Texas Food Bank 9-11am
· Feb 27th Data Analy cs 1130-1 Ryan Hassler “Permian: Top Themes to watch out For in 2025”
Thank you,
Chairman of the Board of Directors
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Jennifer Pallanich, Journal of Petroleum Technology
In the quest to cost-effec vely boost produc on, operators are experimen ng with ar ficial li methods and how digital tech can boost its performance.
Ar ficial li experts are increasingly adding ar ficial intelligence (AI), machine learning (ML), and autonomous opera ons into their workflows because these data-driven technologies are demonstra ng they can generate upli when they are though ully developed and deployed. Operators are also looking at the performance of high-pressure gas li (HPGL) wells compared to wells using electrical submersible pumps (ESPs) for ar ficial li . Finally, operators some mes have to decide whether to risk replacing equipment that seems to be func oning, even if at subpar levels, in a bid to increase produc on.
Digital Boost
Op mized gas li workflows and autonomously implemented ESP set points are helping ExxonMobil and Vital Energy produce more oil
Gas li is a popular ar ficial li method partly because the system is simple, robust, and inexpensive to operate, but op mizing it has historically been me-consuming. SPE 219553 outlines ExxonMobil’s approach to automa ng gas li op miza on for wells in the Permian Basin. The resul ng workflow, which relies on AI and ML, generated a 2.2% upli in produc on at the more than 1,300 wells where it was deployed, without requiring changes to surface or downhole equipment or genera ng addi onal work for personnel.
produc on op miza on engineer in August that one of the big benefits of applying the closedloop itera ve well-by-well gas li op miza on workflow is that it removes the need for an engineer or specialist to have to go into the field repeatedly to change injec on rates and analyze the well’s
“For each well, that might take a few hours, at least,” he said. “We’ve done this on hundreds and hundreds of wells, and it happens every month without anybody, any manpower, or anything. So that’s one of the huge benefits of doing this in a data-driven manner.”
Gas li is so robust that it can be challenging to diagnose if the system is opera ng in a subop mal state, the paper noted. Changes in a well’s water cut or produc vity can cause a previously op mized system to lose efficiency, which may not otherwise be known for years.
ExxonMobil was seeking a method to op mize gas li that would con nuously monitor the state of the system and respond immediately. The resul ng closed-loop so ware itera vely performs mul rate tests analyzes the results, and remotely implements setpoint changes to op mize the wells.
“The op miza on process is most effec ve in an itera ve form, in which each mul rate test produces a model that suggests a given change,” the paper stated. While each model produces its own op mal injec on rate, subsequent models may point to the same injec on rate, and thus changes are not always
Even if an ini ally suggested set point is not op mal, it will “push the well in the right direc on,” which improves the star ng point for the next test and helps the well reach an op mal set point over the course of a few itera ons, according to the paper.
The workflow was tested in two different stages, with the first 3-month stage requiring manual approval of “Somebody in the field would go through and say yes or no,” Burmaster said, and that resulted in an average upli of 1.87% in the tested wells.
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During the second 3-month stage, most changes were automa cally approved and implemented. He said that approach improved the average upli to about 2.2% “We’ve taken this to be a pre y significant success,” he said.
Vital Energy tackled op miza on and automa on of ESP set points as a method of removing a human bo leneck while increasing produc on. The operator traced its journey to autonomously op mize ESPs on wells in the Midland Basin through the use of ML, AI, and an ar ficial neural network in
opera ons engineer at Vital Energy, said during ALCE that Vital Energy created a machinelearning inference model (MLIM) that generates ESP set-point recommenda ons based on user-defined goals, such as maximizing oil or total liquid produc on. Solid data is necessary for op miza on, so gauges and sensors collect values such as pump intake pressure, motor temperature and speed, and more every quarter-hour from the wells. The model uses that data to forecast a well’s produc on and make set-point recommenda ons for the ESP to safely maximize produc on.
In the early stages of the journey, petrotechnical experts approved or rejected the recommended changes. But, Erickson said, to achieve “true, real-world AI, you actually need to take that a step further, have that autonomous piece, and take the human out of the loop.
Once the MLIM was sufficiently trained on a dataset of 193 ESP-li ed wells, Vital Energy used it to generate set-point recommendaons for about 60 wells, which was about one-quarter of the operator’s Midland Basin ESP-li ed wells. The MLIM was refined over 9 months before deployment expanded to more than 200 wells, or more than 80% of Vital Energy’s Midland Basin ESP li ed wells
The operator then measured the quality of the MLIM set-point recommenda ons by calcula ng next-day upli , with results indica ng a mean program upli of 2 to 4% a er the recommenda ons were point changes that didn’t align with the MLIM recommenda ons
Erickson said Vital Energy also wanted to compare results of implemented recommenda ons versus set-point changes that didn’t align with the MLIM recommenda ons. We saw an average of 1.8 mes higher upli when the recommenda ons were accepted versus when they were rejected, or when set-point changes that were counter to the recommenda ons were made,” he said
In addi on to the increased upli , Vital Energy also noted that ESP run lives improved year over year, that mean me to failure increased by 49%, and ESP up me increased by about 4% in 2023 over 2022 rates. “We don’t fully a ribute that to the machine learning model, because we’ve got a lot of background efforts
This deployment indicated the MLIM was possible to run at scale and, based on the increased upli , it was effec ve at scale. Further, the scaled deployment didn’t place observable pressure on lease opera ng expenses while key performance indicators of ESPs improved year over year.
Based on this success, Vital Energy trialed full self-pumping (FSP) mode on nine wells, with the MLIM recommenda ons being autonomously wri en to field devices, he said. The wells opera ng on FSP have autonomously produced more than 1.4 million bbl of total liquids and 500 MMcf of natural gas. Oil produc on for the six wells with the highest FSP u liza on
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According to the paper, the favorable results during an extended period of 100% FSP u liza on indicate the FSP solu on is accre ve and does not lead to adverse effects for opera ons or equipment
Erickson said that before the autonomous deployment, there was a “human bo leneck” because people couldn’t get to so many wells “mul ple mes a day to implement the changes.” Instead, petrotechnical experts can focus on other tasks, he said They can “take (their) eyes off those wells for extended periods of me and free up that me to do something that’s more valuable,” he said.
HPGL, ESP Showdown
Operatorso enturn toESPstomaximizeproduc on in wellswith high water cuts. Thedownsideisthey arevulnerableto damagefromreservoir solidsandreplacinga failedESP costsmoney in addi on tothelost produc on.BPX Energy and DG Petro Oil& Gas both inves gated howHPGL wells stack up against ESP wells A five-well BPXpilot aimed to seehowHPGL comparedto theopera ngcostsand produc on ratesofESPs, anar ficialli methodtypically used in theDelawareBasin.
Speaking during ALCE
Permian Basinar ficialli op miza on teamleaderat BPX,said thekey ques on BPXsought toanswer with SPE219552 revolved around whether HPGL wellscouldachievesimilar drawdownsasESP wellsinthearea
That’sa ques on everyonehasin theirminds, andwewerereally excited to try. But alongwith that,(also)reliability, up me,” hesaid.“Addingonemorepieceofkit in therewith thecompressor, that’sanother bigques on. What will thereliabilityofthesesystemslook like?”
The five pilot HPGL wells are all on the same pad and were drilled and put online at the same me. Each wellinthe pilot wasconnected to itsownelectric150-hp high-pressurecompressor, which wassuppliedbyEs sCompression LLC. A nearby BPX-operated midstreamfacility provided thegassupply fortheHPGL pad. For comparison, BPXselected nearby similar wells equipped with ESP that were on a different pad butbrought onlineat thesame meastheHPGL pilot pad wells. Thepaper noted thecompressorshad shown run meexceeding 99%a er 6monthsofservice
“We’ve been really impressed with the Es s compressors,” McNeilly said, no ng only onetrip was requiredover thefirst 10monthsofopera on. “Really happy withtheup me. Theoperatorsloveit.I mean, it’sset it andforgetit.”
One of the big surprises the pilot delivered was the surface arrival temperature of produc on fluid from the HPGL wells. McNeilly said there was a “significant” drop in arrival temperature compared to ESP wells producing at similar rates, with produced fluids from the HPGL wells arriving at temperatures from 5°F to cooler than fluids from ESP wells. “We saw this in every well,” he said.
Typically, Delaware Basin wells use rented cooling equipment during the early producon period to ensure the fluid temperature is below the temperature ra ng of the export flowlines. With the fluids from the HPGL wells arriving at lower temperatures, the coolers weren’t needed as long, which resulted in an Opex savings McNeilly said.
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Another finding was that the wells on HPGL produced less sand than those using ESPs, he said.
“This one’s harder to explain than the temperature effect, but again, we did see it. We did see it on all five
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The upshot, he said, is that this phenomenon allowed BPX to remove the sand knockout flowback equipment on site, resul ng in addional Opex savings. “It’s something that we did see that we want to explore,” he added.
According to the paper, the overall results from the HPGL wells were sa sfactory, with the company planning to consider HPGL as an ar ficial li method moving forward.
When HPGL wells were compared to nearby similar ESP wells, the 7-5/8 in. CSG 500 Series ESP wells achieved slightly higher rates and drawdown than the HPGL wells, the paper stated. “I don’t think this was a big surprise to many people,” McNeilly said. On the other hand, when compared against 5.5-in. liner 400 Series ESP wells, the HPGL pilot wells achieved similar rates and drawdowns, the paper stated.
“Surprisingly, for a lot of people in my organiza on, high-pressure gas li matched, outperformed … but it was very close to the 400 Series ESP in terms of rate and drawdown. This surprised a lot of people who said, ‘ESP is the best form of ar ficial li ,’” he said, adding the data from the pilot showed HPGL is compeve. “The big disclaimer is: It just depends so much on the well condi ons.”
And while HPGL will be considered moving forward as an ar ficial li method, McNeilly said BPX is “not
Elsewhere, DG Petro wondered whether HPGL might serve as a suitable alterna ve for high-water-cut wells, so the operator compared how the two methods performed in terms of Capex, Opex, run me, and hydrocarbon recovery for unconven onal Wolfcamp wells and detailed the findings in
Speaking during ALCE an asset manager for DG Petro Oil & Gas, said the experiment was carried out on a pair of Permian Basin wells that were drilled at the same me from the same pad to the same depth in Wolfcamp A, as well as a third well into the Wolfcamp B.
Wells 1 and 2, which were drilled and completed in 2018, had a water cut exceeding 95%, and were on conven onal gas li . In April 2022, the operator decided to upgrade ar ficial li methods for the wells. An ESP was installed in Well 1 while HPGL was selected for Well 2.
The first well “looked good” at first, Fusselman said. According to the paper, Well 1 ini al produc on exceeded Well 2 by 120%. But in May 2022, Well 1 output dropped by half and by the fourth month the ESP failed. Analysis of the ESP a ributed the failure to reservoir debris, and a new ESP was installed in August 2022. An influx of reservoir solids led to ESP failure in November 2022. Discussions with offset operators indicated that ESP failures caused by reservoir solids and debris are common in the area, according to the so this well was put on HPGL
Well 2, put on HPGL in April 2022, on the other hand, had a run me efficiency over 99.5%, with down me associated for regular maintenance.ItsurpassedWell1oilproduc ona er4monthsanditsgas
Well 3 was drilled and completed in Wolfcamp B in September 2018 and had been on an ESP that failed in June 2022. In August 2022,
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Jennifer Pallanich, Journal of Petroleum Technology
it was replaced by an iden cal ESP, but that ESP was later lost in the well due to bolt-stress failure. Fishing was unsuccessful, and the operator opted to place this well on HPGL as well. It had a higher gas/oil ra o and lower water cuts than Wells 1 and 2 and so was considered a be er HPGL On HPGL since January 2023, both Wells 1 and 3 have experienced similar up mes to Well 2.
Well 3 “exhibited remarkable per-lateral-foot produc on” given that only about 4,933 of the total 11,847- length was thought to be contribu ng to the produc on, transla ng to a “substan al improvement” over ESP producon, according to the paper
“This was a good success story for our company. A er having lost a lot of value in the lateral, to be able to restore more produc on than we were making for that half of the lateral prior,” Fusselman said.
Between April 2022 and January 2024, Well 2 had achieved about 2.4 mes return on investment due to its lower ini al Capex, lack of workover expenses, and the opera onal efficiency of HPGL. Well 1, which suffered mulple ESP failures before being placed on HPGL, was nearing breakeven as of July 2024, The three wells that are now on HPGL have not had to be worked over, he said, and produc on rates have
We are considering or have considered and installed high -pressure gas li now in wells that we’ve had solids issues on, wells that didn’t have great cleanouts, or had a lot of sand issues, or a lot of solids,” said. “It’s con nued to be a very, very posi ve li method for us.” Early to mid-life applica ons of HPGL have generated good results, Fusselman said, and next, “we are looking to start trialing some poten ally late-life” wells that are producing with rod pump li systems
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The Basics of Crude, Gas and NGL Contracts/Marke ng for the Non-Marke ng Professional
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Execu ve
2024-2025 SPE Permian Basin Board Members
Chairman Tyler Yancey yanceyty@chevron.com
Secretary Ma hew Farris ma hew.farris@corelab.com
Treasurer Paul Brown Paulbrown@chevron.com Chevron
Vice-Chairman Sara Booth sara.f.foster@gmail.com ConocoPhillips
