Chapter 1 - Introduction to Fluid Geochemistry

1.01a Applications for Unconventional Reservoir Production - Part 1 (18 min.) Sample Lesson
1.01b Applications for Unconventional Reservoir Production - Part 2 (16 min.)
1.01c Applications for Unconventional Reservoir Production - Part 3 (13 min.) Quiz: 1.01c Applications for Unconventional Reservoir Production - Part 3

Chapter 2 - Geochemical Fingerprinting of Oilfield Fluids

2.01 Natural Subsurface Tracers for Production Optimization (14 min.)
2.02 Geochemical Production Monitoring and Allocation (22 min.)
2.03 Source of Produced Fluids (23 min.)
2.04 Examples of Source Rock Fluid Mobility (16 min.) Quiz: 2.04 Examples of Source Rock Fluid Mobility

Chapter 3 - Production Allocation Program Design in Tight Unconventional Reservoirs

3.01a Generalized Workflow for Production Allocation - Part 1 (14 min.)
3.01b Generalized Workflow for Production Allocation - Part 2 (14 min.)
3.02a Types of Data for Production Monitoring and Allocation - Part 1 (13 min.)
3.02b Time lapse Monitoring of Fluid Geochemistry - Part 2 (9 min.)
3.02c Time lapse Monitoring of Fluid Geochemistry - Part 3 (15 min.)
3.03 Psuedo End Member Oils vs Core Extracts (16 min.) Quiz: 3.03 Psuedo End Member Oils vs Core Extracts

Chapter 4 - Analytical Methods to Ensure Representative Samples for Fingerprinting & Production Allocation

4.01a Analytical Work (Molecular Chemistry for Allocation, Bulk for Maturity) - Part 1 (16 min.)
4.01b Analytical Work (Molecular Chemistry for Allocation, Bulk for Maturity) - Part 2 (11 min.)
4.02 Sample Type Limitations of Production Allocation (11 min.)
4.03 Analyzing Liquid Petroleum (17 min.)
4.04 Methods of Production Allocation (13 min.) Quiz: 4.04 Methods of Production Allocation

Chapter 5 - Production Allocation Examples in Tight Unconventional Reservoirs

5.01a Identifying Fluid Types and Outliers - Part 1 (14 min.)
5.01b Identifying Fluid Types and Outliers - Part 2 (15 min.)
5.01c Identifying Fluid Types and Outliers - Part 3 (10 min.)
5.02a End Member Allocation - Part 1 (13 min.)
5.02b End Member Allocation - Part 2 (17 min.)
5.02c End Member Allocation - Part 3 (12 min.)
5.03a Montney Example - Part 1 (17 min.)
5.03b Montney Example - Part 2 (13 min.)
5.04 Diamondoids Case Study (9 min.) Quiz: 5.04 Diamondoids Case Study

Chapter 6 - Data QC and Fluid Characterization Prior to Production Allocation

6.01a Interpretive Process - Part 1 (17 min.)
6.01b Interpretive Process - Part 2 (5 min.)
6.01c Interpretive Process - Part 3 (11 min.)
6.01d Interpretive Process - Part 4 (7 min.) Quiz: 6.01d Interpretive Process - Part 4

Integrated Petroleum Geochemistry for Unconventional Plays / Chapter 1 - Introduction to Fluid Geochemistry

Lesson 1.01a Applications for Unconventional Reservoir Production - Part 1

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Transcript

01. Lesson 1.01a: Applications for Unconventional Reservoir Production - Part 1 02. Petroleum Systems 03. Utility of Geochemistry in Oil & Gas 04. Aspects of Petroleum Recovery 05. Reservoir Characterization & Monitoring over the Lifecycle 06. Fundamental Principles of Petroleum Geochemistry

01. Lesson 1.01a: Applications for Unconventional Reservoir Production - Part 1

Welcome to the Integrated Petroleum for Unconventional Tight Reservoir and Source Rock Plays. I'm Jennifer Adams. I started out as a geologist and transitioned into being a hydrogeologist/numerical modeler. And then in that process, I had to learn how to calibrate models and the best way to do that is with chemical data. So I gradually moved myself into being a petroleum geochemist. When I finished my Ph.D., the main takeaway was that fluid drives everything with regards to petroleum recovery, whether you're looking at in the oilsands or you looking at really tight unconventional plays.
So today we're going to look at applications of reservoir geochemistry to unconventional plays and how to optimize production. And we're going to try and understand how geochemistry might be able to help you do that.

02. Petroleum Systems

Let's start with a petroleum system. Petroleum accumulations are the product of a dynamic interplay of over geological time of petroleum charge from at least one source rock through the complex porous media of its migration pathways into its hosting reservoir. And, at compositions been affected by the subsequent evolution and alteration of fluids related to changing PVT conditions, microbial metabolism, leak or spill scenarios, and rock-water interactions. As a result, you get a wide variety of accumulation types with a suite of petroleum compositions, resulting in many, many different approaches to recovery of these resources. Not only that, the engineers of this world get smarter and smarter about how to pull petroleum out of the ground, which means more and more rock that we deemed unproducible becomes a viable production. So it turns out the molecular and bulk chemistry of reservoir fluids in the context of your reservoir characteristics and architecture, fluid properties like PVT and based in history can actually be used to understand both the petroleum system, that's called exploration, and to monitor the progress and efficiency of production, that's reservoir geochemistry.

03. Utility of Geochemistry in Oil & Gas

So what do we actually use for in oil and gas? Basically, geochemistry uses the naturally occurring geochemical differences in petroleum in two different ways, and these two ways are related to either production or development. These can be applied really only in two ways. 1) exploration to understand a petroleum system or 2) in development operations where we apply reservoir geochemistry.
In exploration, the process is simply that we correlate fluids to source rocks and determinehistory. We also primarily develop proxies for difficult to measure fluid properties:, GOR, any number of things, and we try to do that ahead of the drill-bit or ahead of completion. This, of course, requires calibration to specific plays or basins. Now, what's challenging in exploration geochemistry is that there're all sorts of correlations and understanding that's been done over the years, and every singleincan be a little bit different. So an exploration is the process of trying on different models or different proxies to your particular play type to see whether it's actually going to work. So, sometimes people get frustrated with exploration geochemistry because you can try all sorts of different correlations or proxies which worked other places and they won't work where you work. So that's a bit of a challenge.
I'll just give you one example. So everyone talks about reflectance equivalent, like %Ro. And that little correlation as to, let's say, T(max) vs. %Ro or fluid properties vs. what we call thermal, was developed based on a very tiny number of samples, from a limited number of basins, a very long time ago. It was only meant to be used for kerogen source rocks. And the whole thing was designed based on conventional produced fluids. And yet, we use that all over the place regardless of source, regardless of basin, whether it's conventional or unconventional. So yes, it's a reasonable proxy. Just remember that whatever you're going to apply that's been learned, those calibrations, have greater and greater error as you move away from that calibration dataset. All right, that's exploration, we're not going to talk about that much anymore.
Development deals with reservoir geochemistry. And it's quite simple, we monitor production from geochemical heterogeneous reservoirs or operations using whatever petroleum compounds as tracers to track different operational issues. So this kind of work requires statistically significant differences between different reservoirs, different pools, different what we might call, end members. And once you have that and you've identified the end member samples, they must be representative of whatever production you're doing or whatever parameter you're trying to match, then the process is more or less the same. So the nice thing about reservoir geochemistry is the overall process is quite similar, but you can apply it in any way that helps you solve the particular development problem that you're having.

04. Aspects of Petroleum Recovery

All right, let's talk a little bit about different aspects of petroleum recovery. I think these are the elements of recovery that have to be characterized to ensure profitable operations. And this really doesn't necessarily have anything to do with, it's just the lifecycle of a petroleum field. It's important to estimate, to know how much petroleum is present, what's recoverable from the subsurface.
Fluid quality is essential because that's what you actually, the fluids you deliver to market, that's what you get paid for. So what's the value of that produced petroleum and how much does that vary over time?
You want, of course, to understand recovery efficiency so you can optimize your resource. So how much fluid can we recover? Have we adequately drained the resource that we have? Are there any well interactions going on?
Often, operators need estimates of unwanted fluids that have to be disposed of. Let's say water or non-hydrocarbon gases, acid gases, H₂S, CO₂. They need to understand those so that they can design the infrastructure properly, so that things don't get corroded too much. You might group into that category as well, microorganisms, any kind of biological issues having to use biocide.
#5 is a flow assurance. Can we minimize the downtime or deterioration of the infrastructure or the reservoir quality or the fluid quality?
And then lastly, once you've moved into that brownfield or moving into some kind of, can you look at the viability of monitoring any kind of enhanced recovery? Are there tertiary recovery options and how can we monitor them?
So with regards to what geochemistry can add to this basic workflow that you need to move through to optimize recovery. Basically, geochemistry provides an estimate of fluid quality, hopefully pre-drill or pre-completion composition. And you also can use geochemistry to measure mass transport or understand mass transport to calibrate your models to look for flow paths, PVT fractionation, if that's what's going on. So although geochemistry has a lot of caveats, a lot of case studies, a lot of models that work one place and not the other, I would encourage you maybe to even go back and look at these very simple definitions I've given, because usually any activity that's going to go on using geochemistry falls into the category of creating a calibration curve so that you can predict something either in an exploration environment or doing the same sort of thing to be predictive in a development environment, trying to predict a fluid property that's hard to measure. And then in development, you might just be looking to monitor. And in that case, you're trying to find groups and differences between different zones, different wells, whatever there are differences in, and then monitoring how those differences shift and change.

05. Reservoir Characterization & Monitoring over the Lifecycle

So here's just the lifecycle of a petroleum field. You can see the exploration and land acquisition of the early, moving into appraisal, full field development, and then possibly or decommissioning. And I've just selected a few different disciplines that interact throughout this lifecycle:,, looking at pressure, reservoir quality,,. And this is more on the reservoir characterization side, rather than the engineering side, necessarily. And you can see that early on, there's a lot of reservoir characterization that gets done using different tools. And I just simply wanted to highlight that geochemistry is in fact involved all the way through from the very beginning of exploration right out to tertiary recovery, but the activity that we do, using geochemistry, changes. Initially, it looks at fluid quality and petroleum system definition. Then you might move into production allocation and production monitoring. And then finally, if you're doing tertiary recovery, you might look at the viability of different subsurface injectants and then monitor miscible floods. I've also added production monitoring down here, which starts after you at least have a few wells in the system, and that brings forward the idea of optimizing completions and monitoring any kind of microbial activity or doing some remediation if needed, later during decommissioning.

06. Fundamental Principles of Petroleum Geochemistry

So I know some people who would be viewing this material come from all sorts of different disciplines. And it's hard to get into the geochemical mindset, sometimes. I've written out some fundamental principles of petroleum. And they're exceptionally dense, but I've tried to translate them into, let's say, chemical or physics based language, rather than a whole lot of jargon that people have to go back and understand. And there are only 4 of them, because I actually think that if you were to take each of the principles and apply them to whatever system that you're looking at or a field that you're operating, you would find that, if you really pulled these principles apart, you would be able to effectively infer the nature or the habit of thethat you're doing, given these principles.
So one of the most important things I hope you learn, is that geochemical signatures of any fluid or rock are the integrated record of time, temperature, history of mass transport in a system. And that sounds funny, but it's only because fluids are moving around, temperature is changing, there is mixing going on and the interaction during the transport that allows geochemical signatures to change.
So let's start with the first principle. Petroleum is generated from condensed organic matter, we call that, via cracking of hydrocarbons during progressive geological heating, we call that. With progressive heating, generated petroleum becomes richer in lowers, ultimately converting oil to dry gas, which is methane and residual inert carbon, which we call pyrobitumen. It's no different than burning something in the oven. It starts off something relatively uncooked and takes you all the way out to char. Maturation does continue in the absence of kerogen. That's important, oil to gas cracking happens, given sufficient temperature to trigger kinetics of a given reaction. So this means oils will crack at high temperatures,s might crack at moderate temperature. The other thing that we don't talk about very much in classic petroleum geology is that time and temperature make a really big difference. Typically, basins operate on certain timescales with certain burial histories, but you can also imagine alike the Basin, that's been sitting at a single burial depth for 200 million years before it went underwent a little bit of uplift. 200 million years at the same temperature, that still could do some interesting things to kerogen.
All right, principal b) PVT conditions and the hosting pores media character dictate the phase and segregation of the petroleum over geological time. So this is calling in that mass transport idea. It's the fluids interacting with the actual rock. Migration pathway and host reservoir quality, that's the rock quality, combined with fluid and buoyancy, that brings in the idea of density, control the rate of fluid equilibration and homogeneity. So many of the systems that we operate in can be so tight that there are a lot of disequilibrium conditions. Or in other situations, you might get a gradient because of an equilibrium situation with regards to gravity. Subsequent production of petroleum will be commensurate with operational PVT conditions and fluid. And thatis a function of in-situ reservoir permeability and saturations, as well as fluid viscosity. We usually can get at an understanding of fluid viscosity using fluid composition. But I'm trying to get at the point that these principals have words like density, viscosity, gravity, temperature. Those are all physics based things. Then we use things like composition or thermal. We use proxies for the actual physics that's going on in the system.
Principal c) generated petroleum composition is controlled by the type of organic matter originally in the kerogen, which is dependent on depositional environment and the quality of preservation. Migration, either secondary or primary, and alteration processes, lead to changes in petroleum composition within an accumulation or associated accumulations. However, of the fluids coming into a system and the various focusing or defocusing processes, that can be or stratigraphic and structural controls or rock-water petroleum interactions, all of those processes can take place over basin scale distances and over geological time. That means there are a lot of degrees of freedom in these systems. And yes, we have lots of conceptual models to try and make them simple, but it's strongly possible that as you do your work, looking at production, doing exploration, you will discover all sorts of different cases because of the different combination of all of these factors and the degrees of freedom that we're discussing.
Last one, oil consists of thousands of compounds with distinctive reactive chemistry related to water solubility, thermal maturation, depositional environment, operational fractionation, alteration processes, and many more. And these can be correlated back to fluid properties and mass transport processes. So all of these compounds can act as natural tracers to understand the origin and evolution of petroleum and monitor its recovery through whatever reservoir that you're working with.
All right, we're going to go dive into just a few fundamentals of geochemistry about source rocks and actual liquids. Put some jargon in here. I'm just going to draw your attention to the material provided to you with this course. There are a series of definitions and I'm not going to read them to you, but you can just click on them in the resources that are provided for you here. I do recommend you might just scan down them and make sure that when I use a particular word, that we're on the same page about whatever that particular bit of jargon means.
Quasi-continuous hydrocarbon accumulation: An alternative model for the formation of large tight oil and gas accumulations." Journal of Petroleum Science and Engineering 174 (2019): 25-39.