PART 1 of 3—OVERVIEW
In the last 36 months, 34,070 horizontal wells have been completed in the U.S. This represents about 12% of all horizontal wells drilled, and since the last three years have seen a big uptick in both activity and technology improvement in unconventional play development, I thought it was a good time to dig into geosteering data to get some perspective on this critical piece of the unconventional puzzle.
Of the horizontals completed in the last three years, nearly 14,000 have been analyzed in our Play Assessments application for characteristics, such as percentage of well bore in landing zone, toe in landing zone, and footage in landing zone.
How good of a job have we done getting our horizontals into their targeted landing zones to maximize the productive potential of our unconventional resource play acreage?
Using our highly quality controlled DI Play Assessments data, we can start taking a look at these 14,000 wells to see where operators landed their wells.
Since wells with a relatively high percentage of out-of-zone drilling within targeted landing zones will negatively affect play economics, I thought I’d look at wells, by basin, in Play Assessments with 25% or more of lateral length out of zone. The graph below shows the percentage (displayed logarithmically) of wells, by basin, that had less than 75% of their wellbore positioned in the intended landing zone.
Note that the DJ, Gulf Coast, and Williston were the most likely basins to see wells out of zone (DJ 35%, Gulf Coast 13%, Williston 21%).
In contrast, the basins that showed the highest percentages of wells 90% or greater in zone were the Central Basin Platform at 94%, Mid-Continent at 91%, and Midland Basin at 90%. What accounts for the differences?
Operators in the three Permian sub basins—Delaware, Central Basin Platform, and Midland—are doing a great job of landing their wells in zone and keeping them there.
But what’s going on the Williston and DJ in particular?
These are the most targeted landing zones by basin (source: DI Play Assessments).
For the 23 operators that have completed any wells in the last three years with at least 25% of the wellbore out of Middle Bakken landing zone, nearly one quarter of them account for almost 45% of the out-of-landing-zone wells.
Since the percentage of total wells completed with more than 25% of lateral out of zone in the Middle Bakken in the last three years is about 16%, is this operator dependent or geologically driven (high faulting, rapid lithologic changes, challenges of staying in zone in high dip areas)?
Since the out-of-zone wells are not concentrated in one part of the basin, this implies that geology, faulting, or steep dip complications are not the drivers of out-of-zone performance.
Most of the large operators have done a good to excellent job of keeping their wellbores in their landing zones.
If we look in DI Play Assessments at the 10 operators in the DJ that account for 93% of the wells landed in the Niobrara B, their in-zone landing performance is also quite variable.
Plotting these on a map also shows spatial variability in the position of these wells, again implying that the out-of-zone performance in the DJ is most likely operator driven and not tied to geologic complexity.
In Part 2, I’ll look at identifying the most problematical landing zones.
Please send me an email at firstname.lastname@example.org if you have any observations on or comments about geosteering challenges.
Natural gas storage inventories increased 106 Bcf for the week ending May 10, according to the EIA’s weekly report. This injection meets the market expectation, which was an inventory increase of 105 Bcf.
Thus far in 2019, lower-48 dry natural gas production is ~7.03 Bcf/d higher than the same period in 2018, while natural gas demand is up ~4.66 Bcf/d for the same period. Since injections started this season for the week ending March 29, 2019, total inventories have increased 546 Bcf. In 2018 for the same time frame, storage showed an injection of 155 Bcf.
Working gas storage inventories now sit at 1.653 Tcf, which is 130 Bcf above inventories at the same time last year and 286 Bcf below the five-year average.
At the time of this writing, the June 2019 contract was trading at $2.623/MMBtu, $0.022 above yesterday’s close of $2.601/MMBtu.
Prices traded in a narrow range this week for the June 2019 contract, trading between $2.601 and $2.659. The main driver of the price movement has been weather. Forecast changes will continue to be the main price driver as we get deeper into the summer and the expectations regarding how much gas will be needed for power burn becomes more of a reality.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending May 16, 2019.
- Dry gas production decreased 0.14 Bcf/d. Most of the decrease came from the South Central/Gulf region, which fell 0.15 Bcf/d.
- Canadian net imports decreased 0.13 Bcf/d on the week.
- Domestic natural gas demand increased 1.04 Bcf/d week over week. Res/Com demand accounts for most of the increase, gaining 1.18 Bcf/d, mainly due to cooler weather in the East. Power demand showed a drop of 0.35 Bcf/d, while Industrial demand gained 0.21 Bcf/d.
- LNG exports increased 0.23 Bcf/d week over week, while Mexican exports increased 0.01 Bcf/d.
The ICE Financial Weekly Index report is currently expecting an injection of 110 Bcf. Last year, the same week saw an injection of 91 Bcf; the five-year average is an injection of 91 Bcf.
- US crude oil inventories posted a substantial increase of 9.9 MMBbl last week, according to the weekly EIA report. Gasoline inventories increased 0.9 MMBbl, and distillate inventories decreased 1.3 MMBbl/d. Total petroleum inventories showed a large increase of 12.7 MMBbl. US crude oil production increased 100 MBbl/d last week per EIA. Crude oil imports were up 265 MBbl/d to an average of 7.4 MMBbl/d versus the week prior.
- The WTI price regained some of its strength as the market ignored comments surrounding the Trump administration’s conversations with Saudi Arabia. These comments regarding increasing oil flow and keeping gasoline prices in check had a negative impact on prices in the week prior. That enthusiasm was supported with the news of Venezuelan opposition leader Juan Guaido calling on the population and military to seize power from President Maduro. Unfortunately for the rally, the uprising fell short of expectations as the week wore on.
- The upcoming OPEC meeting and decision regarding the supply cuts will likely hinge on the effects of the Iranian production and the global supply-demand levels. The Saudis mentioned last week that the supply cuts may be extended beyond June depending on the situation.
- This uncertainty going into the OPEC meeting will lead to a potentially volatile period for oil prices. Last week’s bearish inventory data confirms the potential volatility for the market as petroleum stockpiles grew substantively despite the supply reductions imposed earlier in the year. The market is also digesting the effects of US production as it continues to grow, which will take market share from other producing countries and shows no signals of slowing.
- The CFTC report (positions as of April 30) showed the Managed Money long component taking some profits by reducing speculative length by 8,969 contracts while the Managed Money short component increased their position for the first time in weeks, adding 5,429 contracts.
- The price collapse after the inventory release was dramatic and swift, with most of the losses coming on Thursday after traders got a chance to digest the new data point. The declines took prices down to $60.95, just above the commonly traded 200-day moving average, which now sits at $60.95 going into today’s trade. While prices rebounded a little on Friday (hitting $62.52), prices resumed weakness by the end of the day, closing the week at $61.94.
- Market internals are now neutral bias with the retracement, as prices are now in the lower end of the expected short-term range of between $60 and $67. The volume was down week-on-week but remained strong compared with recent weekly averages. Open interest also gained slightly as prices fell during the week according to preliminary data from the CME.
- Prices have consolidated, as expected, and are now facing some critical support levels that will need to hold before the market develops a negative bias. The first area is the aforementioned 200-day moving average at $60.95. This is a commonly traded average for the speculative sector, and a close below it (on a daily basis) will likely bring about additional selling and profit taking. These declines may take prices down to the breakout levels between $57 and $58 from early March. Should the critical support level hold and prices catch a bid (as they did early Friday), $62.52 and up to last week’s high of $64.75 will likely find substantive selling. The market may be entering a period of volatility and range expansion, depending on the extent of the rebound off of the support test.
- Natural gas dry production showed an increase of 0.19 Bcf/d, while Canadian imports increased 0.29 Bcf/d.
- Demand showed the Res/Com market sector rising 3.27 Bcf/d, while Power and Industrial demand increased 1.99 Bcf/d and 0.18 Bcf/d, respectively. LNG exports showed a gain of 0.34 Bcf/d, while Mexican exports increased 0.05 Bcf/d. Total supply for the week showed a gain of 0.48 Bcf/d, while total demand rose 6.00 Bcf/d.
- The storage report last week showed injections for the previous week at 123 Bcf. Total inventories are now 128 Bcf higher than at the same time last year and 316 Bcf below the five-year average.
- The CFTC report (as of April 30) showed the Managed Money long sector reducing positions by 11,358 contracts, while the Managed Money short position increased by 16,955 contracts. These additional increases in the short positions occurred as prices rallied over $2.60 during May expiration, and the rally continued into early last week as June took over as prompt. The speculative sector is clearly expecting a test of the June lows from last month at $2.477 and perhaps more declines beyond that level.
- Market internals maintain the slightly negative bias, with volume increasing from the previous week and open interest increasing as the prices rebuffed the gains. The market has softened from the oversold momentum levels obtained during the price declines at the end of last month.
- Prices are continuing in the recent range and following a pattern similar to last year’s, but at lower levels. Early projections of supply growth have the market above 3.5 Tcf at the end of the injection season, based on normal summer demand. It is unlikely this market will see a dramatic move in either direction until the summer demand is better defined. Declines to last month’s low of around $2.43 will find support, and the highs of around $2.65-$2.733 will find sellers. Watching the deferred strips and their price behavior will give a clue as to the near-term direction of this market. If the market breaks below the lows of last month, look for confirmation in the winter strip.
NATURAL GAS LIQUIDS
- Ethane gained slightly week-over-week, increasing $0.002 to $0.237. All other purity products saw declines in price, with propane falling $0.041 to $0.603, normal butane down $0.072 to $0.698, isobutane down $0.059 to $0.710, and natural gasoline down $0.054 to $1.287.
- US propane stocks increased ~1.2 MMBbl the week ending April 26. Stocks now sit at 58.9 MMBbl, roughly 22.6 MMBbl and 19.3 MMBbl higher than the same week for April 2018 and April 2017, respectively.
SHIPPING – DI shipping content is produced using DI’s new import manifest tool. Please contact Bert Gilbert (email@example.com) for more details.
- Waterborne crude imports dropped substantially from last week, with data from manifests indicating a drop of more than 1.4 MMBbl/d across the country. PADD 3 saw the biggest drop, falling by nearly 800 MBbl/d week-over-week to 1.436 MMBbl/d. PADD 1 fell to 618 MBbl/d, while PADD 5 fell to 868 MBbl/d. Last week’s bump in PADD 3 imports was driven by higher-than-normal imports from Colombia, Kuwait, and Russia. Imports from those countries fell this week, but imports from Mexico rose to nearly 740 MBbl/d. That represented more than half of overall PADD 3 waterborne imports. Houston took in more than 35% of total imports to PADD 3.
- Imports from Nigeria have increased slightly, with overall imports from that country reaching the highest since January. The majority of these barrels went to PADD 1, with Phillips 66 Bayway taking the most. However, Valero Texas City did receive a cargo of medium sweet Bonga.
Natural gas storage inventories increased 123 Bcf for the week ending April 26, according to the EIA’s weekly report. This injection is above the market expectation, which was an inventory increase of 118 Bcf.
Working gas storage inventories now sit at 1.462 Tcf, which is 128 Bcf above inventories at the same time last year and 316 Bcf below the five-year average.
At the time of this writing, the June 2019 contract was trading at $2.567/MMBtu, $0.053 below yesterday’s close of $2.620/MMBtu. The May 2019 contract rallied on expiration and closed at $2.566/MMBtu last week.
Another week, another record injection for the month of April. This injection tops the previous April injection record, set by the injections the prior two weeks, by 31 Bcf. These record injections helped inventories jump above last year’s and gain on the five-year average inventories.
Inventories are increasing, but weather is driving price volatility. Warm weather is driving Power demand higher in the Southern region, while cooler weather is driving Res/Com demand up in the East, Midwest, and Mountain regions. This increased demand took the June contract to $2.62/MMBtu for yesterday’s close. However, demand is expected to fall off and be below average throughout May. If that holds true, prices will stay well below $3/MMBtu, and larger-than-normal inventory builds will continue.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending May 2, 2019.
- Dry gas production was relatively flat week over week, gaining 0.03 Bcf/d.
- Canadian net imports increased 0.11 Bcf/d on the week.
- Domestic natural gas demand increased 5.06 Bcf/d week over week. Res/Com demand showed the largest increase, gaining 3.16 Bcf/d. Power demand showed a gain of 1.75 Bcf/d, while Industrial demand gained 0.15 Bcf/d.
- LNG exports increased 0.20 Bcf/d week over week, while Mexican exports increased 0.28 Bcf/d.
Total supply is up 0.14 Bcf/d, while total demand decreased 5.68 Bcf/d week over week. With the gain in demand outpacing the gain in supply, expect the EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 93 Bcf. Last year, the same week saw an injection of 89 Bcf; the five-year average is an injection of 75 Bcf.