Eagle Ford Shale – a snapshot of today’s activity

Southwest of Texas’ capital city Austin and towards the Mexican border there is a large area of shale called the “Eagle Ford Shale”, EFS. For those interested I can mention that there is a good website “Eagle Ford Shale” where one can find all sorts of information on Eagle Ford. Figures in this report are from that website.

Eagle Ford is considered one of world’s largest oil- and gas-investments in terms of costs. During 2013 it is estimated that the volume of investment will be on the order of $30 billion. They calculate that all the investments in EFS have in 2012 generated over 116,000 jobs just in the provinces covering EFS geographically and many more jobs in peripheral areas. In purely economic terms the investments have meant twice as much for the region.

The thing that distinguishes shale oil production is that it involves drilling of many wells that, in comparison with the traditional wells of conventional oilfields, give a relatively low production. To drill a well requires a drilling rig and there are weekly statistics available that show how many rigs are currently drilling. For 16 August 2013 it was reported that 267 rigs were drilling in Eagle Ford of which 241 drilled for oil. At the moment the price of natural gas is too low to make it profitable to drill new natural gas wells. They do drill for natural gas if it also provides quite a lot of condensate. Condensate has the same price as oil. In addition to the number of drilling rigs there are statistics on how long time it takes to drill a well and how long are the horizontal wells.

If we choose statistics for the 5 most recently drilled wells over the last quarter then we see that it takes approximately half a month to drill a well and that it is approximately 2,430 metres long.

During the last year they have drilled approximately 1000 wells per quarter (Q3 2012 – 1,024 wells, Q4 2012 – 974 wells, Q1 2013 – 1,044 wells, Q2 2013 – 1,050 wells) and it is obvious that production has increased. In May 2013 EFS reached production of 600,000 barrels per day. In April 2013 the USA produced 7.3 Mb/d and of this approximately 8% came from Eagle Ford. They estimate that Eagle Ford will exceed the production of the Bakken. Looking at all the wells being drilled in EFS and realizing that the production from the Bakken has begun to level off, this estimation would certainly appear to be correct.

At the beginning of July there were approximately 4,000 oil wells and 1,700 gas wells in production in the EFS. Considering that they have drilled 4,000 wells in the last year you can understand that most of these wells must be quite new and so should have good production levels. Normally, a fracking well will lose more than 50% of its initial production rate in the first year. If 4,000 oil wells produce 600,000 barrels per day in total this means an average of 150 barrels per well per day. One company has reported that production when they initially pump in fracking fluids is 822 barrels per day which is less than they expected. The average production number of 150 barrels per day indicates therefore that production per well has declined very quickly.

In the figure above you can see that on 13 May permission had been given to drill 10,422 wells since 2008. Of these approximately 5,700 have been drilled. At the rate of drilling now prevailing this means that permits still exist for a little over one year of drilling. How rapidly can new permits be granted? The average cost for drilling a well has fallen from approximately $7 million to $6 million, but 4000 wells would thus still cost $24 billion. As long as the price of oil is high it is profitable to drill new wells but if the price falls, as it has done for natural gas, this may cause difficulties for the profitability of new projects. Those who think that fracking will give us cheap oil and natural gas must reconsider.

There is an image of a local spot of EFS that shows how individual wells are drilled and one sees that there is no room for an unending number of them. The question is how many profitable wells can be drilled in future. There is a maximum limit and when we reach it, presumably sooner, then Eagle Ford will reach Peak Oil, i.e. the maximal rate of oil production. The question is whether the maximum will exceed 1 Mb/d.

8 Comments on "Eagle Ford Shale – a snapshot of today’s activity"

Matt on Wed, 21st Aug 2013 1:14 pm 



It is good that it has created jobs along the way, given the unemployment situation nationally. But also, it is a huge blow to investors and the company if things don’t work out financially to produce more wells. Citizens should read this & become more aware of this “cheap oil and gas” that the government talks about. It has its dark side, & its not pretty.

bobinget on Wed, 21st Aug 2013 1:31 pm 



Simmons Oil & Gas

Macro

Oil
August has been somewhat of a revelation, notwithstanding the seasonal torpor. The IEA’s August editorial sermon, “Mugged by Reality,” is not only well-phrased, it is well-crafted, as the emerging reality for the global oil supply and demand framework is one of considerably less flexibility than many appreciate. While the NAM narrative is one of resource abundance and incandescent production growth, that is far from the case in the international realm. Dislocations in Libya and Iraq, coupled with intractable turmoil in Nigeria, Syria, Sudan and Yemen, the appalling carnage in Egypt, and the tyranny of decline rates in mature provinces collectively crystallize the challenges in bringing supply to the market.

Yes NAM production growth continues to be unrestrained. US production in May averaged ~7.317mbd and was ~15-16% or 1 mb/d higher y/y. Leading edge production data suggests that current run-rate production is hovering at ~7.5mbd. Recently, Bakken (North Dakota to be more precise) production breached the 800kbd threshold for the first time and based on seasonal tailwinds meaningful production growth is likely to be forthcoming in 2H’13. When one contemplates the early well results from the Delaware and Midland Basins and the fact that producers are only beginning to scratch the surface of the multi-stacked pay zones in these plays with horizontal drilling and completion; the continued onslaught of the Eagle Ford; encouraging down-spacing results in the Bakken; ongoing efficiency gains and E&Ps enjoying unfettered access to capital, it appears that SFL (stronger for longer) is the apt narrative for domestic production prospects. While Canada is a compelling story as well, the rate of growth and the absolute numbers aren’t nearly as compelling or as a consequential as they are for the US, And that’s the good news from a production standpoint, globally.

Libya appears to be devolving back into clockwork orange chaos, thanks to a combination a labor unrest and civil strife. The IEA reported that oil production had collapsed to ~400kbd or by ~70% from a YTD high of 1.4mbd in April. The Libyan oil minister last week provided repeated assurances that the security situation continued to improve, even though there wasn’t any overt evidence that export terminals had reopened. Today, the Libyan Prime Minister warned that the disruption to exports could not go on indefinitely (strikes at Libya’s main oil export terminals are now entering their fourth week) and “the state will be obliged to use all means at its disposal, including those of the army…” Further, the Libyan defense minister, speaking at the same press conference expressed that “a group of outlaws behaving in a manner that threatens the security of all Libyan citizens could result in total chaos from inside and from abroad.”

Meanwhile, Iraqi production growth is faltering as June production fell below 3mbd for the first time in six months – keep in mind that targeted production for this year was 3.7mbd. Iraq, along with NAM, was one of the few presumed supernova production narratives. While “SFL” is perhaps the apt acronym in this case as well, “stagnating for longer” is emerging as the more precise narrative. The combination of incessant security issues (pipeline attacks) and revenue disputes between Baghdad and the regional government, as well as corrosive and inadequate infrastructure is arresting production growth. Further, there is ongoing and growing discord between Baghdad and IOCs over production targets. Lastly, Iraq was planning to upgrade its SPMs (single point mooring systems) which would have resulted in a ~500kbd reduction in exports in September (July exports were ~2.7mbd) – now according to media accounts, Iraq is reconsidering this possibility (perhaps due to tighter than expected market balances?).

Reported Syrian production is now 50kbd (beginning of ’13 ~100kbd) down from 350kbd prior to the furies being unleashed. South Sudanese production, which reportedly ramped to 200kbd in early-July since the April restart, has regressed to 75kbd thanks to continued discord with Sudan. Nigerian production of 1.80-1.9mbd remains below ’12 avg output of 2.1mbd thanks to a combo of ongoing oil theft and internal instability.

The appalling spectacle in Egypt is becoming a study in unrestrained carnage. Tom Friedman once described Egypt as the antithesis to Las Vegas: what happens in Egypt does not stay in Egypt. Where this ends, is a worthy question. One would think that a new generation of radicalized Egyptians is in the process of being formed.

The tyranny of decline rates in mature provinces continues inexorably. UK oil production contracted by close to 15% last year and Q2 output of 820kbd was down 200kbd y/y or ~20%. Due in part to seasonal maintenance, UK oil production in August is expected to fall 650kbd, the second-lowest level seen in decades, before rebounding to 720kbd in September. Norwegian production declined by ~6.5% last year and is projected to decline by additional 5% this year. While Russia continues to be the world’s largest oil producer, the rate of production growth is becoming more labored and ‘14 production is expected to be ~flat with current levels. Long-story short, apart from the resource abundance narrative in NAM, production flexibility is diminishing and rather markedly in recent months thanks to a combination of the aforementioned factors.

Lastly, we believe that there is risk to the IEA’s projections for 2H’13 non-OPEC production, which it projects to rise by over 1 mbd compared to the first-half of the year. On a y/y basis, growth over the 2nd half of the year is expected to accelerate to 1.4 mb/d y/y, vs. 800 kb/d of y/y growth during 1H’13, representing a significant step-up in non-OPEC supply contributions, and we believe there is downside risk to this ramp-up. The IEA expects the most meaningful contributions to the increase to 2H’13 production vs. 1H’13 production to come from: 1) refining processing gains and biofuels (+520 kb/d); 2) the US (+380 kb/d); 3) Canada (+175 kb/d); Brazil (+175 kb/d); and 4) Sudan (+140 kb/d). We specifically see potential for downside risk in Brazil, where PBR is guiding to flat q/q 3Q’13 production, and Sudan, where the production outlook is clouded by instability.

While the demand narrative is less dramatic and fluid, it is quietly better behaved than consensus opinion may appreciate. US demand has expanded in four of the first six months of this year and over the preceding 5 weeks gasoline demand is up ~2.5-3.3% and distillate is up ~8-19% (exports are obviously playing a prominent role). China’s June apparent demand was the highest level in six months and early indicators of July demand are reasonably encouraging. To the latter point, China reported strong import data across the board as oil imports were up 20% y/y, iron ore imports were up ~26% and copper imports were up 12%. Chinese copper premiums (the cost of physical copper over benchmark future prices) have more than tripled since the beginning of the year and stand at an all-time high – whether this is inventory replenishment, a portent of improved industrial demand, or a combination, remains to be seen, however.

Global refinery throughputs in June surged 3.1mbd m/m, the highest monthly increase for June on record. From April to July, global throughputs have expanded by 5.1mbd, more than 2x the 5-year average. And while the Fall refinery maintenance season looms, how extensive it will be remains to be seen.

Inventory trends across the OECD have been better than many appreciated over the past 3 months, contributing to a somewhat tighter market. As we recently observed, total OECD inventories for May were revised lower by a material 32 mb, as total inventories declined by 18 mb on the month (vs. a typical 17mb May build). Yes, inventories in June did build by a somewhat larger than normal 11.9 mb (5 year average +6mb). More importantly, however, preliminary data for July points to a significant counter-seasonal draw of 13.6 mb (vs. 5 year build of 21 mb). The Q3 call on OPEC crude has been revised higher to ~30mbd, and while OPEC is currently producing ~30.5mbd the large miscellaneous to balance number of 900kbd (indicated either more anemic production or more robust demand) implies that OPEC is actually having difficulty meeting current demand.

With regard to differentials, we have noted in numerous epistles that during the 2010-2012 period the rate of production growth considerably exceeded the pace of infrastructure development, resulting in logistical bottlenecks and widening oil price differentials. However, during 2013-14 the pace of infrastructure development (2013 pipeline additions +1.5 mb/d, 2014 pipeline additions +1.3 mb/d, 2013 to 2014 rail loading/unloading additions ~2 mb/d) is expected to significantly exceed production growth, resulting in debottlenecking and compressing differentials. WTI/Brent has recently widened back out to about $3.50/bbl, from ~$2/bbl over the last few weeks and could further widen to ~$5/bbl in the short-term before converging more tightly once the 700 kbd Keystone GCA pipeline (line pack to start early Nov) and the 450 kbd Seaway twin (line pack early 1Q’14) come online.

Natural Gas
We have written prolifically on natural gas and more is in process. Thus, we’ll strive for brevity in this note. And briefly, as it relates to natural gas we remain longer term optimistic and near-term realistic. Yes, production is still growing and with the ongoing Marcellus/Utica and associated gas uplift and decelerating underlying base decline rates from shale plays, domestic natural gas production will continue to display admirable resilience. Additionally, the thesis espoused above for oil could lead to a steeper recovery burden for natural gas due to increasingly unrestrained associated natural gas production. That said, what has been a production-led narrative will, over time, became a demand-led one. In the meantime, natural gas continues to be mispriced but it won’t stay this way forever.

bobinget on Wed, 21st Aug 2013 2:06 pm 



Production decline capabilty 3mm bbls per day or the mid range of 3-5% of the known decline rates
of various oil fields. This is conventional production of 75MM bbls per day not refinery gain, ngls. or biofuels. Fields can continue at a high rate but loose this capacity over time (Gharwar SA is resting it) , other fields this is an annual or more rapid decline. The point is that this decline & ability to achieve the same production must be made up each year. With 100’s of $B if not a $T spent over the last 10 years this capacity is not being replaced. The majors have been eating their young for years. When production has been replaced it has been done primarily with NG. World spare capacity with production off line for various reasons is down to approximately 2mm bbls per day, primarily made up of heavy sour crude in SA.

The Bakken & Eagleford have been the primary reason for any increase in world oil production. EOG’s Mark Papa doubts if there are others like these in NA. The Delaware, Midland, Niobrara, Cline, Utica all have been spotty to date and/or have had primarily NG production. On a positive front the technology learned from shale gas & oil has increased production &/or slowed depletion in areas such as the Permian Basin.

Demand is up. Gasoline usage is up 2-3% with total daily demand of product in the 19.7mm bbl. area. Chinese oil imports were up 20% in June. Europe is turning around. Over the last 10 days I have been on both US costs. Speed limits in those areas are 65-70mph. People drive at 75-80 with gasoline at $3.60 to $4+. $100 plus CL has not slowed either demand or economies.

World turmoil is not going to go away, demand will continue strong & grow,& people are not slowing their speed. Shale oil is not going to replace the worlds Gharwars by any extent. Shale technology infrastructure costs $B’s & is not close by any degree to being replicated anywhere in the world. If so it will take years.

westexas on Wed, 21st Aug 2013 2:44 pm 



Re: bobinget

Good summary.

rollin on Wed, 21st Aug 2013 3:29 pm 



Obviously, the developed and developing world needs a whole new model to follow.
This one is a dead end.

shortonoil on Wed, 21st Aug 2013 3:33 pm 



“They do drill for natural gas if it also provides quite a lot of condensate. Condensate has the same price as oil.”

Were do they get these people? Condensate sells for a discount of $10-$15 per barrel less than WTI. Condensate is not crude. It has a different density, chemical makeup, energy density, and lacks the C7+ molecules needed to produce distillates. That is why EOG (Eagle Ford’s largest producer) makes a point of emphasizing that 70% of what the other producers supply from the Eagle Ford is condensate. Condensate is not a substitute for crude, never has been, and never will be. That is why (in-spite of all the hyperbola about shale oil) the price of crude is not going down. The price of crude is controlled by conventional crude production, and that is going down!

Plantagenet on Wed, 21st Aug 2013 7:35 pm 



Good to see a well documented discussion of the EF shale from ASPO. At least they aren’t in denial like the folks ar the Oil Drum

MrEnergyCzar on Thu, 22nd Aug 2013 12:27 am 



Where does all the water come from?

MrEnergyCzar