Previous Lecture Complete and continue  

  4. Different RFG Processes with Same Charge

Lecture content locked

Enroll in Course to Unlock
If you're already enrolled, you'll need to login.


- [Oliver] Now what I want to take a look at is a reservoir that has three adjacent fault blocks. And each of the fault blocks had oil with a gas charge in the Pleistocene. So in other words, the same petroleum system model. Each of these fault blocks will be seen to have totally different realizations of the reservoir because of the RFG processes, the different reservoir fluid geodynamic processes. So we'll look at this case, very instructive. And I'll note that Well one is in a faulted section of the reservoir and Well three is near the charge point of the reservoir. Fault block one, what we can see is the following. The asphaltenes are measured to show a gigantic gradient going from about 7% asphaltene to about 35% asphaltene in the oil, huge concentration of asphaltenes and very much in disequilibrium, not equilibrated. In addition, we have this huge gradient of saturation pressure. Here's the equation of state, and this is what's actual. So the solution gas is not equilibrated, nor is the GOR equilibrated. There's a very high GOR up top, low GOR down below. What's go on? So we had an initial condition of a late gas charge above black oil, and then the gas diffused into the oil column. This gas is diffusing down, so there's a lot of gas near the gas-oil contact, a lot of solution gas, but not as much solution gas down below. And that's why we have this disequilibrium gradient. We are in an active diffusive process here. What happens to the asphaltenes? Well the asphaltenes don't like gas. In chemistry, like dissolves like, so oil does not dissolve in water because the CH non-polar bond does not like the OH polar bond, they don't like each other, so they don't dissolve in each other. Whereas alcohol has OH and water has OH, so they dissolve in each other. So I'm told, I have no personal knowledge of whether alcohol dissolves in water. Anyway, so when you have a high solution gas, the gas is a colorless gas, the asphaltenes are a dark brown solid, they don't like each other chemically. If you increase the solution gas, you expel the asphaltenes. So what we can see is the asphaltenes being expelled from upstructure and they migrate down as the solution gas is increasing as it's migrating down, the asphaltenes are migrating down as well. So that's what's going on in fault block one. Now you can say the following, this is only at tens of meters, well why is it that this diffusive process is not complete? Why is it still ongoing, taking so long? Well one explanation is, this is a Pleistocene charge of gas, so okay, it's very recent. So it hasn't had as much time to equilibrate, but it had a million years or so. So why did it not equilibrate? Well we can establish with the waterline formation testing tool using vertical interference testing that the vertical permeability in this fault block at least at this well, is not so good. Remember this well is in the faulted section of the reservoir, these faults are sealing, they're not transmissive. So we have a baffling. What else does baffling do besides slow down the equilibration rates? Baffles cause low production, it's well known. And so we have low DST production rates in this fault block out of this well. We look at the adjacent fault block. This is fault block two. We see a very different story, entirely different. In fault block two, there's very little asphaltene, it's almost near zero, as opposed to in fault block one where we're getting up to very high, up to 35% asphaltene. In addition, the GOR in fault block two is equilibrated in contrast to fault block one, the GOR's not equilibrated. So in this fault block the diffusive process went to completion and it's equilibrated. While as I have mentioned, in fault block one the asphaltenes don't like gas. They migrate away from the gas. What do they do over here? They formed a giant tar mat. You don't see that in the fluid, you see that in core extracts. There's the asphaltene content in the core extracts, and there's this giant tar mat. Just to check that's a tar mat, we run the SEM, scanning electron microscopy of thin sections and you can see there is the tar. This has a characteristic crack in it when you prepare the core with hexane wash to wash out the oil and it extracts a little bit of bitumen out of the deposit causing a slight volume reduction and the characteristic cracking. So it's easy to recognize that that's the asphaltene plugging the core and tar mat. So that's fault block two. What about fault block three? Fault block three has a totally different realization of the reservoir than either fault block one or fault block two. It took us a little while to figure this one out. What we see in the data, first off, I'm not showing it, but the fluids are equilibrated. There's a shale break, I guess I should start there. There's a shale break. The pressure and fluids are equilibrated above and below the shale break. I'm not showing that, but we have very high GOR fluids, very low asphaltene content. So it looks like the diffusive process went to completion in this section. The asphaltene deposition. Okay, above the shale break, we have a thin tar mat on the shale break, that's fine. And then no asphaltene deposit in core above that. That's fine, that's just the standard process that we saw in fault block two where we have a vertical sweep methane diffusion down and asphaltene diffusion down. But the issue is this. Below the shale break, we have asphaltene deposition throughout the core and then no tar mat forming on the oil-water contact. What is that? That's very different than what we see up here. We now know what this is. This where you have a case of a lateral sweep instead of a vertical sweep. When you have a lateral sweep of gas coming into the formation then the asphaltenes are destabilized and they want to fall down, they want to migrate down by gravity. But they don't run away from the gas in a lateral sweep, they run into more gas and they get deposited locally right there. That's a very different process than a vertical sweep where the gas came in from above and the asphaltenes could fall with their extra density and size than when the asphaltenes were destabilized and fall out the way. Here they can't fall out of the way, so they get locally deposited. So we have a lateral sweep. The concept then is, and if you remember fault block three is near the charge point of the reservoir, this is a bit like a fire hose where the charge point is acting like being close to a fire hose pointing laterally and that you feel the sideways force when you're getting close to the fire hose. If you get farther away from the fire hose, then the fluids density stack. So here's close to the fire hose, you get the lateral sweep, the charge point in the reservoir. You get asphalt deposition throughout core. If you get further away from the charge point, you get a mixed sweep, some vertical, some lateral. That's what we saw in fault block three, some vertical and some lateral in the same well. And then if you're far enough away from the charge point, the fluids just density stack. I understand and the purists would be upset if they thought that I was trying to imply that the fluids enter the reservoir at the rate of a fire hose, they don't. This is over geologic time. But we will take a little bit further look at this lateral sweep because we have unassailable evidence that this is correct in the next case study. And I note, this is a microscopic picture of a lateral sweep where you get this local deposition. We can see it in the SEM imaging. That's you could say, a microscopic picture. Okay, so if we continue, what I want to point out is here we have three adjacent fault blocks with three totally different reservoir realizations in each of the wells in each of these fault blocks. Yet, they all have the same petroleum system model of a Pleistocene gas charge into oil reservoirs. This is why asset teams can't use PSM to predict reservoir realizations. It's required to also incorporate the RFG processes that give rise to these different realizations. Here we have this very different realizations, fault block one is baffled, it had low production rates. Fault block two is not baffled. It came to equilibrium and has good production rates, but there is a tar mat, you have to worry about aquifer sweep and pressure support. And I don't have the production data in fault block three, but actually I think it should be fairly good. Okay, this lateral sweep concept is quite new, so we're gonna look at this in a different reservoir.