Imbibition — the “old all new”production mechanism of shale gas and oil
Conventional oil and gas production mechanisms
In the conventional oil production mechanism, oil and gas are being produced through viscous flow by sweeping the fluid (oil and gas) through pressure gradient. Director of Sensor Research at Arrow Grand Technology Published on 2018 M10 21
In the conventional oil production mechanism, oil and gas are being produced through viscous flow by sweeping the fluid (oil and gas) through pressure gradient.
Director of Sensor Research at Arrow Grand Technology
Published on 2018 M10 21
Such conventional transport mechanism is well understood and also believed to be the dominant transport mechanism in shale gas and oil production.
Under such conventional production mechanism, it is widely accepted that there is the “Bubble-Point-Theory(BPT)” process that will repeat in unconventional tight/shale oil and gas production. The “BPT” model goes like the following,
- As production starts and pore pressure drops in tight rocks, the initially dissolved oil and gas phase (usually in the super critical phase as most components are light oil and burial depth is high and so is pressure) will separate due to phase change, and oil will be permanently trapped once liquid is formed inside. As Scott’s BPT paper uses a squeezing toothpaste tube as the example of BPT in tight rocks. After the pressure drop induced bubble point, GOR will go up very fast, i.e. oil production will enter a terminal drop.
- In conventional reservoir, production engineers could count on the separated dissolved gas expansion or external water and gas to push out the oil, like the toothpaste tube helper here. But in tight reservoir after fracking, the water injected externally will push through the larger fractures created during fracking and will not seep into the tight rocks and push out the remaining oil and gas there, much like a water breakthrough larger fractures in conventional production where remaining oil and gas are just trapped in finer fractures. To make things worse, water breakthrough will seal the finer nano pore throat through very high capillary forces, resulting fast decline of both oil and gas. This was demonstrated by the infamous Miss Lime in the northern Anadarko basin where the often encountered original reservoir water nearby breakthrough and flooded a well shortly after production starts.
However, in tight rocks there are many other production pathways. As the reservoir rock’s permeability and flow speed gets smaller and smaller, there will be more slippage and Knudsen diffusion components. It is proposed that the long production tail of shale gas in Barnett and tight oil in Bakken are such results. Or, as we propose below, other production pathways could also play a more significant role.
The old all new production mechanism
However, as demonstrated both in the lab and in the field, there is a production mechanism that will continue the production of oil and gas long after pressure drops.
In shale/tight oil, it has been demonstrated by several labs using Bakken and other basins’ tight rocks as example, that oil could be exchanged out through so called imbibition processes. By adding fresh water and enhanced by chemicals, more oil could come out spontaneously from cuttings and cores of tight rocks without external driving force or pressure.
In Bakken, although EOG has demonstrated what Scott’s papers shown as “peacock feathers” decline curves (figure on the right side from Scott’s 1st paper), the overall oil production decline is much different to such “peakcock feathers”, as shown in the figure above, suggesting different rocks in the basin might behave differently, and the fracking and completion methods could also make the differences.
ChemEOR did an exciting demonstration of how imbibition help oil production in tight rocks (SPE147531). By adding surfactant chemicals and it is shown (figures below) that we could significantly improve oil recovery through imbibition process. The oil recovery could be increased well over 10 folds compared to using only 2% KCl water and achieve recovery close to 40% from a Bakken core (last figure below)!
In shale gas, this imbibition production mechanism is no more clearly pronounced than the imbibition test that Professor Terry Engelder demonstrated with a week old dry shale cutting after retrieving from a lateral well in Marcellus drilled with oil based mud. The thin shale cutting was still able to hold quite some gas even after exposing to the air for a week. Then, after Terry impinges a micro water droplet on the dry cutting chip, surprisingly, micro gas jets started coming out from the cutting and are visible in the water droplet, and this lasted over 17 minutes (figures below).
“what’s happening is we have a chip (shale cutting) here, sitting on the desktop and holding gas in it, virtually forever. And when you put water on it, the water imbibes, and as it imbibes, it drives out gas in the pore space.”— Professor Terry Engelder lecture in Yale on Youtube, from 50 minutes.
I want to highlight several issues about Professor Engelder’s vivid demo:
- How much amount of gas is ejected from each gram of cutting after water droplet is impinged upon the cuttings?
- As one would argue that gas might have also been ejected without water droplet, so the next question is — if such rate has been maintained constant without water in the past 7 days, what kind of gas volume should be trapped inside the cuttings? It will be outrageous amount of gas trapped if such rate is maintained over a week. In fact the rate should be even higher earlier as the pressure was higher. A fiction could be coming true — we might be able use a small cylinder filled with such cuttings and get enough gas out to drive a car for 100 miles.
- If gas has not been released at such high speed, i.e. visible micro gas jets, after water droplet is impinged, what’s holding the gases for a week? I used the model that Prof. Engelder in his paper about this demo and also addressing the concern of the fate of the fracking water as a majority part of the fracking water never returns in some of the prolific shale/tight gas and oil reservoirs.
I replaced the 200million years with 7 days, and 40meters of shale with 1mm of shale cuttings, and the conclusion is that the permeability of this cutting has to be smaller than 5E-5 nanoDarcyin order to hold the gas for a week. As shale’s permeability is much larger than nano Darcy in both the vertical and horizontal direction of the chip, the force that actually holding the gas for a week has to be water induced capillary force.
The water, once dreaded by oil and gas production, is actually helping the tight oil and gas production in an unexpected way —- “imbibition”!