This week’s final US sellside energy conferences before the summer did not disappoint anyone who was looking to see what “new” technology applications are likely to be highlighted when energy conferences restart in September. This weekend’s Sunday Energy Tidbits memo will cover a range of non-technology sector insights from this week’s presentations including heavy oil differentials, service sector cost inflation, lower rig counts in H2/17 vs H1/17, drilled uncompleted wells, etc. But we wanted to highlight three technology developments that aren’t just bigger and tighter fracks, but are items pointing to why US shale/tight oil could continue to surprise to the upside in 2018 – finer proppants, scientifically engineered gas, and tank/cube development.
Readers of our Sunday morning Energy Tidbits memos know that we love to review transcripts for energy conference presentations and quarterly earnings calls. Slide decks keep getting better, but the best value often comes from seeing what management says to describe the slide content or, even better yet, their reply to a question. The comments paint a clearer picture and often excellent excellent disclosure on sector developments and insights that tends to get overlooked as analysts have to focus first on updates to their models, valuations and targets. We look at individual company disclosure (and any references to individual companies) to help paint a picture for a broader sector insight or future trend.
The focus of this blog is on three technology developments that are likely to be highlighted in September and that are pointing to why US oil production could surprise to the upside in 2018. We expect US oil rigs (drilling) to start to decline if WTI stays at $45 for a few more weeks. But the momentum of drilling, the conversion of DUCs (Drilled UnCompleted Wells) should lead to US oil production continuing to increase into 2018 even if oil rigs decline in Q3. The below table shows the EIA has consistently increased its forecast for US oil production in almost every month for the past year. US oil production has surprised to upside, driven by technology being applied in increasingly better and more effective ways – primarily from a series of completion improvements of more fracks per well, bigger fracks, more proppant per well, and longer horizontal well length. Each of these completion advancements has helped on a step by step basis to increase well rates and recovery. US shale players are still looking at bigger and better fracks and tighter spacing, but this week, we saw more insights and confirming data that these other (non-bigger/tighter fracks) technology developments are working and/or increasing in application. We expect to see more on these once summer is over, in the wave of September energy conferences.
EIA Estimated US Crude Oil Production By Forecast Month
Source: EIA
First data points to confirm that finer proppants are having a material impact on recovery/rates. Our May 9, 2017 blog highlighted one of these technology advances – “Will Finer Proppant Be The Next Completion Tweak That Leads To US Shale Oil Surprising To the Upside In 2018?” [LINK] noting Core Laboratories (CLB) bullish views that finer proppants could more than double the amount of stimulated reservoir ie. from stimulated reservoir volume of 20% range to a 50% range. We believe using finer proppants makes sense. When a shale or tight zone is fracked, it opens flow paths for the oil or natural gas. But these fracked flow paths will end up closing unless proppant is inserted to keep the fractures open. Using smaller sized proppants (100 and 200 mesh sand) will keep more of the smaller flow paths (secondary and tertiary fracture patterns) open. It seems logical, and applicable on a broad basis. The non-technical description is that the finer proppants allow more of the fracked shale to stay open. This week, we saw confirmation of the success of finer proppant from Murphy Oil’s presentation. Murphy noted how their recent Eagle Ford wells (4 new Jambers wells) were “testing completion style with No-Gel & 100 Mesh Sand, Rapid Choke Progression in Early Flowback”. Murphy said that 3 of the 4 new Jambers wells are at 133% to 150% of the type curve. We expect to see more disclosure on finer proppants as we get into Q2/17 and Q3/17 reporting.
Murphy Oil – Jambers Wells Cumulative BOE
Source: Murphy Oil
Unconventonal EOR using scientifically engineered gas field tests expected in H2/17. Our May 9 blog noted how CLB highlighted finer proppants as one of “four major industry trends that will shape tomorrow’s oil field”. CLB’s first trend was enhanced oil recovery (EOR) from shale/tight oil reservoirs. The EOR themes are primarily focused on using scientifically engineered gas (SEG) absorption techniques, gas cycling and the “laws of physical and thermodynamics”. This week, CLB noted that it expects the first field tests later in 2017. This isn’t as easy as finer proppants to describe, but a non-technical description is that the SEGs interact chemically with the shale oil to increase the percentage of shale oil that is moveable thru the opened fracks. What got our attention was that CLB chose to illustrate this upside this week by specifically mentioning Pioneer Natural Resources Permian wells. This logically infers that Pioneer, one of the Permian leaders, is testing it in H2/17. CLB said “So, if you take a type curve, let’s say out of the Permian, that Pioneer Natural Resources typical well. It’s about a million barrels of EOR and that’s keep the math simple. Let’s say they they’re recovering about 10% of the in place oil. If we can increase that from 10% to 15%, we take that type curve from 1 million barrels to a 1.5 million barrels. The incremental capital costing – that’s going to cost that operator is somewhere between $1 million and $3 million. So, that incremental add of capital gets you another 0.5 million barrels of production over the life of that wellbore. You can see the significant boost in returns that that is indeed going to have.” Increasing the recovered reserves by 50% is a huge potential upside to shale.
“Tank/cube” development is working with lower per wells costs and better well rates/recoveries. There were multiple companies moving to tank/cube development in the Permian. Tank/cube development has started and will be increasing and not just in the Permian. This is not a case of bigger and tighter fracks, rather it is designing and executing the frack program in the optimum sequence to get better recoveries and rates while reducing the average well costs – its doing it better. Encana has previously noted it is doing tank/cube development in the Montney. The tank/cube development is when all the wells on a drilling pad to develop all the parts (height and width) of the thick pay zone are drilled, completed, BUT only brought on stream all at the same time. Using the QEP Resources’ Wolfcamp tank example below, QEP will drill all 10 wells, then complete all 10 wells, but wait to start producing all 10 wells at the same time.
Example of “Tank-Style” Completion Design
Source: QEP Resources
Tank/Cube development means lower costs and better recoveries. The tank/cube development gives two wins to the play – lower average well costs and better per well recoveries and rates per well. They can get more oil out for less cost. Last week, Encana held its Permian investor day [LINK] and noted how there is accelerated learning from its three Permian cube developments – RAB Davidson Phase 1, Abbie Lane, and RAB Davidson Phase 2. Its cube wells cost $1.2 million less per well than when drilling a single well. It also notes how the cube drilling eliminates the regularly occurring issue of infill wells (child wells) performing less than the original well (parent well).
Encana – Large Scale Development Performance Comparison
Source: Encana
Tank/cube development sets up different funding challenges. It may be more of an issue for intermediate players than the large cap players, but there will be different funding requirements for a tank/cube development. QEP said “So by concentrating our development in these tanks and developing simultaneously all four zones, we believe that we maximize the recovery of oil in place. Now, it introduces some volatility in the well delivery phase because as you can imagine, we herd up a number of wells that are drilled and completed before they’re actually turned to sales. So it introduces some lumpiness in not only the well delivery cadence but also in the production profile.” The funding challenge is that the producers needs to spend all of the capital for the 10 wells before there is any cash flow from any of the 10 wells. There is no cash flow until the point in time when all 10 wells start production. This is a very different funding requirement model.
“New” technology is working and/or increasing in application. This week’s final US sellside energy conferences before the summer gave insights and confirming data that there is more to technology advancements than bigger and tighter fracks, and that these are working and/or increasing in application. Tank/cube development isn’t bigger and tighter fracks, rather it is a case of designing and executing the frack program in the optimum sequence and it is leading to better recoveries and rates for the lower average well costs. Finer proppants and scientifically engineered gas are likely more significant and can materially increase recoveries and rates. Finer proppants can keep more of the fracks open, and SEGs can increase the percentage of shale oil that is moveable thru the fracks. These are two key developments to watch in H2/17 and 2018. If WTI stays at $45, oil rig levels should decline, but we need to watch these technology developments as they can more than offset the impact of lower oil rig levels.