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During the Q2 2017 reporting season, one technical measure -- i.e., the gas-to-oil ratio, aka GOR -- in the Permian Basin received an extraordinary amount of attention within the oil and gas investing community. Some shale bears in Wall Street and financial media even went as far as citing isolated instances of rising GOR as reported by a few unconventional oil and gas producers as evidence for a secular decline of shale oil. Investors' dramatic reaction to the Q2 2017 result release of Pioneer Natural Resources (PXD), and especially Wall Street talking heads' justification of it by way of one single factor of GOR --e.g., reminded us of the widespread misunderstandings of GOR in unconventional play.
In this article, we attempt to explain GOR in relation to tight oil exploitation in a nontechnical language, hoping to shed some light on the use of technical information released by operators to identify value in the oil patch. Petroleum geologists or petroleum engineers who may find this piece too basic are hence directed to other reports of ours here.
1. Fluids in tight reservoirs
Unconventional reservoirs are different from conventional ones in, among other aspects, that the pay zones are of such low porosity and permeability in a large expanse that the drilling of one development well will hardly ever affect the drainage sphere of a neighboring well. In spite of this, the physical principles governing the thermodynamics and phase change of reservoir fluids are the same for both conventional pools and tight ones. Multi-component reservoir fluids typically include natural gas, crude oil, and brine. Such fluids are locked in shale due to the low porosity and permeability of the host rock. Natural gas is stored in shale in two principal forms: 1) as gas adsorbed (chemical) and absorbed (physical) to or within crude oil or brine and 2) as free gas in pore spaces or in fractures, depending on organic richness, kerogen type, and thermal maturity (see Jarvie et al.).
The composition of the fluids in shale varies from one basin to another, from one area of a basin to another, and from one pay zone to another. This variation is a result of multiple factors, ranging from the organic matter in the rock, the pressure-temperature trajectory experienced by the rock, which of course depends on the geothermal gradient of the region, burial depth and history of the shale, and Earth crustal movement and numerous other changes. This is why some tight plays are gassy, while others are oil-prone. Even within the same basin, wells drilled in different areas or depths produce fluids of different initial GORs (Fig. 1).
Fig. 1. Regional variation of reservoir fluid composition in the Permian Basin (upper left, after J.B. Comer, 2005), Eagle Ford (upper right, after Rosetta Resources, 2012), and Marcellus (lower right, after marcellusdrilling), and the relationship between thermal maturity and gas-prone-ness (after Daniel M. Jarvie et al., 2007).
2. Tight reservoir drives
The techniques of horizontal drilling and fracturing are means to make an otherwise inadequate hydrocarbon pool large enough to be economical. The tight nature of shale makes such a pool nearly perfectly enclosed in all directions; neither does it have a gas cap, nor does it have an aquifer beneath or sideways, as in a conventional reservoir (Fig. 2).
Fig. 2. A conventional mixed drive reservoir, after Glover.
A tight shale reservoir resembles a solution gas drive reservoir (Table 1). The gas solution drive mechanism requires the reservoir rock to be completely surrounded by impermeable barriers; in the case of shale oil, the tightness of the rock provides just such impermeable barriers. As production goes on, the reservoir pressure drops, and the exsolution and expansion of the dissolved gases in the oil and water provide the main reservoir drive energy, which is supplemented by additional energy derived from the expansion of the rock and water.
In the beginning -- i.e., prior to any production -- a solution gas drive reservoir is either undersaturated or saturated depending on its pressure:
- It is said to be undersaturated when reservoir pressure is greater than the bubble point of oil;
- It is said to be saturated when reservoir pressure is smaller than the bubble point of the oil.
For an undersaturated reservoir, no free gas exists until the reservoir pressure falls below the bubble point. In such a reservoir, it is the bulk expansion of the reservoir rock and liquids, i.e., water and oil, that provides the drive.
3. Fracturing of a tight zone
Nobody knows the exact process how the hydrocarbon migrates to and congregates in the micro-fissures generated by fracturing. But it can be deduced that, once the tight shale is fractured, a pressure gradient appears between the open space in the micro-fractures and their immediately adjacent, hydro-carbon-hosting rock walls. It is this pressure gradient that helps liberate hydrocarbon locked in the shale and suck hydrocarbon out of the tight rock before it is lifted to the surface (Fig. 3).
Naturally, the pressure in the rock wall of the micro-fractures drops as hydrocarbon therein leaves the shale, enter the fissures and eventually flow to the surface. This pressure drop will cause a number of consequences as discussed below.
4. Consequence of dropping reservoir pressure
If the reservoir is initially undersaturated, the reservoir pressure can drop a lot. Gas will not exsolve from the fluids until it is in the wellbore, and the GOR will slowly increase but remain at low levels. This pressure drop will eventually turn an initially undersaturated reservoir into a saturated one when the reservoir pressure falls below the bubble point. As production from a saturated reservoir continues, a drop in reservoir pressure will cause gas bubbles to exsolve from oil and water and expand (Fig. 4). Gas expansion is the primary drive for reservoirs below the bubble point. Solution gas drive reservoirs exhibit a peculiar pressure, GOR, and fluid production history (Fig. 5).
When the reservoir pressure drops below the bubble point, bubbling starts. Gas bubbles will form and expand to take up the volume left behind by produced oil, hence protecting against pressure drops - this is why the pressure decline slows down once bubbling starts. When this happens, the GOR will rise dramatically. The rise of GOR is accompanied by falling oil production, which is when artificial lift systems are usually instituted. Oil recovery from this type of reservoir is typically between 20% and 30% of original oil in place (OOIP) (see Table 1). A further drop in reservoir pressure can, however, lead to a decrease in GOR when reservoir pressures are such that the gas expands less in the borehole (Fig. 5).
Fig. 4. GOR variation along with months on production for Resolute Energy, modified after Shaleprofile.com.
Fig. 5. Reservoir pressure for solution gas drive (left), and GOR evolution for solution gas drive reservoirs (right), modified after Glover.
5. What can cause rising GOR in a tight oil play
From the general principle detailed above, what factors can result in a rise of GOR for an operator producing from a certain basin?
Everything else being equal (or being adjusted for), the initial GOR of one new well should not be vastly variant from another drilled in an earlier time because the low porosity and permeability keep the drainage sphere of the new well virgin. From this point of departure, we identified the following cause for a rise in GOR.
5.1. Locational variation in initial GOR.
When a company moves rigs from one area with a relatively low maturity to another with relatively high maturity, the new wells will flow fluids with higher initial GORs. This appears to be what Resolute Energy (REN) have encountered in Q2 2017, as Resolute CEO Richard F. Betz commented during the conference call:
During the second quarter, we did see our oil percentage dip to 63% from 68% in the first quarter. This is consistent with what we expected going into the year as we added more Permian wells with higher GORs. This does not reflect a significant change in the reservoir...
As you look across the three properties ... Appaloosa definitely has a lower GOR ... And Mustang itself as you transition from east to west across Mustang you do observe rise in GOR. So any particular quarter is heavily influenced by where our completion is for that quarter...
But we tend to think of - Appaloosa being kind of around 60%, Mustang being in the high 40%s to around 50%, Bronco tracking something like that. And again, as I say, the mix at any given quarter will be heavily weighted, dependent on where the drilling rig is and where the well is brought online that quarter.
Here is an extreme scenario. Suppose an operator used to produce from old wells in the light oil window. When it began to bring on stream a batch of new wells in the wet gas window, its aggregate GOR will shoot up dramatically (Fig. 1).
Fig. 6. The three operating areas of Resolute Energy referred to during the Q2 2017 conference call, modified after Resolute Energy presentation.
5.2. Temporal variation of GOR.
On an individual producing well basis, shale oil is bound to bubble at some point of production, leading to rising GOR (Fig. 4). In a conventional reservoir, where fluids flow more freely within the reservoir, an increasing reading of GOR may signal a reservoir-wide problem. However, in a tight oil play, the impermeability of shale ensures that a new well will produce at relatively low initial GOR even though a neighboring old well has gone beyond the bubble point. In other words, as a producing well ages, GOR will steadily increase before eventually it abruptly goes through the roof.
It becomes interesting when an operator has a collection of wells, some being legacy producing wells with heightened levels of GORs, other newly brought on stream so flowing low-GOR oil, yet other in the process of being completed. The continuous addition of new producing wells into the portfolio of older wells leads to the dilution of high GOR oil produced from the older wells by low initial-GOR crude flowing from the newly completed ones, thus keeping the aggregate GOR level in check.
If old wells flowing high-GOR oil are shut in, or if a lot of new wells are put online, the aggregate GOR may even decrease. If for some reason the operator suddenly cut back drilling and completing of new wells, the aggregate GOR will certainly rise. If a large number of older wells in the portfolio enter the bubbling phase yet not enough new wells are completed, the aggregate GOR will sneak up sooner or later. In summary, in these cases, operational reasons are sufficient to explain a rise in GOR, without needing to attribute such an incidental increase in GOR to some basin-wide geological reasons.
6. The case of Pioneer Natural Resources
Fig. 7 shows the evolution of GOR along with time on production for Pioneer Natural Resources. Within error, curves for different years overlap; there is no observable trend of systematic increase in GOR from older wells to new wells. For all years between 2011 and 2017, GOR first increased at a moderate rate, and then rose dramatically. It appears that its wells on average start to reach the bubbling point by the fifth year, plus or minus half a year (Fig. 7). Such a general pattern is confirmed by similar curves for Resolute Energy (compare Fig. 4). The GOR for Pioneer's aggregate production remains more or less flat since 2014; only beginning in Q4 2016 did it appear to tick up. This incipient uptick in GOR continued in the Q1 2017 (Fig. 8), and received Wall Street attention by the reporting of the Q2 2017 result.
Fig. 7. GOR for Pioneer Natural Resources by year of the first production, modified after shaleprofile.com.
Fig. 8. Total gas and oil production and GOR for Pioneer Natural Resources, modified after shaleprofile.com.
We think that the uptick of GOR in the case of Pioneer can be well explained by a significant drop in drilling and completion of new wells over the last couple of years alone. And by Occam's Razor principle, this may well be the real reason behind the rise of GOR which has received so much publicity. However, what has been the drilling activity of Pioneer like in recent years?
In the annual reports from 2008 to 2016, Pioneer reported its drilling activity in the Permian Basin, complete with acquisition costs of proved and unproven properties, exploration costs, development costs and ARO. Our compilation of these data indicates that Pioneer was most active in drilling and completing exploration/extension wells and development wells in 2011-2014. Wells completed in these four years account for 64% of all wells completed between 2008 and 2016. In contrast, the company only drilled and completed less than one-third of wells as recorded in peak years of 2011 and 2012 (Fig. 9). Therefore, it is fair to say that Pioneer did not drill and complete enough new wells in the last two years to counter the legacy wells which flew high-GOR oil. Judging from production growth alone, things seem to be fine (Fig. 10); however, the GOR was lurking on the horizon.
Fig. 9. Exploration/extension and development wells spudded and completed by year (left) and percentage of completed exploration/extension and development wells among all wells completed in 2008-2016 (right), author's chart based on data compiled from company annual reports.
If it is true that Pioneer wells on average bubbles in the fifth year, with an error of 6 months, it follows that now is about the time that the wells completed in 2011-2012 drilling peak start to bubble. If Pioneer had drilled and completed enough wells in 2015 and 2016, such a bubbling effect shown in legacy wells would have been balanced out by newer oil-prone wells. However, the company cut back its drilling and completion significantly due to the recent oil price crash.
In other words, the rising GOR is an unintended consequence of the reduced drilling budget of the last two years. Due to some technical reasons, Pioneer has to delay well drilling, with the deferral of 30 Permian wells into 2018, which only made things worse.
7. Discussion and Conclusions
Our analysis above leads us to believe that the GOR malaise that Pioneer encountered is more of an operational issue due to decreased capex in 2015 and 2016 when the industry was ravaged by decimated oil prices than a basin-wide geological phenomenon.
However, such an operational issue may indeed result in a pan-Permian problem in oil production. As HFIR correctly pointed out, Pioneer Natural Resources, the "mother fracker," "gives us a good gauge for the direction of the Permian." Due to typical herd tendency of the E&P companies, the majority of legacy wells of other operators may have also been drilled around the time of 2011-12; these old wells may also be entering the bubbling phase. These peers of Pioneer brought significantly fewer wells on stream than usual over the last two years, just as Pioneer did. So it would not surprise us if the other operators also report rising GOR in this or the next quarters. If this proves true, then oil production from the Permian Basin may face a new headwind, just as HFIR forecast.
On the other hand, because this is an operational issue rather than a play-wide geological phenomenon, ramp-up of drilling in the future will reverse the rising trend of GOR. After all, the Permian operators have plenty in store in their inventories of drilling locations.
As independent investors, we have some general lessons to glean from watching how the financial analysts of Wall Street and journalists rationalize their pre-existing bearish emotion toward the Permian producers with a newly-reported, apparently related data point. Just like anything is a hammer to a man holding a nail for it to be hammered, they ran into the reported rising GOR and used it conveniently to buttress their case. However, to prove a hypothesis like the Permian oil production being losing steam requires in-depth investigation beyond prima facie linking of an effect to a possible cause.
Furthermore, oil exploitation, like all other economic activities, is a complex process involving numerous variables. Hardly can a security analyst be so lucky as to turn out to be correct barely by pointing the finger to one single factor as the root cause of the phenomenon. Repeating this practice multiple times will only result in a list of unrelated factors, which may not help move the research closer to the truth. An effective but laborious approach is perhaps to examine the inner working of oil exploitation as a multi-factor system, which again demands in-depth research.
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Disclosure: I am/we are long REN.
I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.