Applied Techniques to Integrated Oil and Gas Reservoir Characterization: A Problem-Solution Discussion with Geoscience Experts

By Enwenode Onajite

Over the past several years, there has been a growing integration of data – geophysical, geological, petrophysical, engineering-related, and production-related – in predicting and determining reservoir properties. As such, geoscientists now must learn the technology, processes, and challenges involved within their specific functions in order to optimize planning for oil field development.

Applied Techniques to Integrated Oil and Gas Reservoir Characterization presents challenging questions encountered by geoscientists in their day-to-day work in the exploration and development of oil and gas fields and provides potential solutions from experts. From basin analysis of conventional and unconventional reservoirs, to seismic attributes analysis, NMR for reservoir characterization, amplitude versus offset (AVO), well-to-seismic tie, seismic inversion studies, rock physics, pore pressure prediction, and 4D for reservoir monitoring, the text examines challenges in the industry as well as the techniques used to overcome those challenges.

This book includes valuable contributions from global industry experts: Brian Schulte (Schiefer Reservoir Consulting), Dr. Neil W. Craigie (Saudi Aramco), Matthijs van der Molen (Shell International E&P), Dr. Fred W. Schroeder (ExxonMobil, retired), Dr. Tharwat Hassane (Schlumberger & BP, retired), and others.

• Presents a thorough understanding of the requirements of various disciplines in characterizing a wide spectrum of reservoirs
• Includes real-life problems and challenging questions encountered by geoscientists in their day-to-day work, along with answers from experts working in the field
• Provides an integrated approach among different disciplines (geology, geophysics, petrophysics, and petroleum engineering)
• Offers advice from industry experts to geoscience students, including career guides and interview tips

• Language: English
• Publisher: Elsevier Science
• Release date: Apr 9, 2021
• ISBN: 9780128172377

Book preview

Section I

Geological Architecture of Unconventional and Deep Water Offshore Reservoirs

Outline

Chapter 1 Unconventional and deepwater reservoir architecture

Chapter 1

Unconventional and deepwater reservoir architecture

Oleksandr Okprekyi¹, Zaw Win Aung², Alexey Sokolov³, Rajeshwaran Dandapani⁴, Robert Avakian⁵, Neil W. Craigie⁶, Susan Nash⁷ and Tharwat Hassane⁸,    ¹Sr. Geologist at Burisma, Kyiv, Ukraine,    ²Exploration Geologist at MPRL E&P, Myanmar,    ³Reservoir Engineering, CGG-Vostok, Moscow, Russian Federation,    ⁴Telesto Energy, Chennai, India,    ⁵Oklahoma State University, Institute of Technology, Okmulgee, OK, United States,    ⁶Geological Consultant at Saudi Aramco, Dhahran, Saudi Arabia,    ⁷Innovation and Emerging Science and Technology, University of Oklahoma, Tulsa Metropolitan Area, United States,    ⁸Petrophysical Technical Lead, Beicip-Franlab Asia, Kuala Lumpur, Malaysia

Abstract

Basin analysis covers sedimentary basins, which are areas on the Earth’s surface, where sediments have been deposited. Generally speaking, basins are quite extensive and can cover tens of thousands of square kilometers. Sedimentary basins can be very deep and also shallow. Deep basins are often marked by high pressures and temperatures at depth. Basin analysis is vitally important in oil and gas exploration. It incorporates the processes used to determine where there is a high likelihood of encountering commercial quantities of recoverable hydrocarbons, and thus is integral to prospect generation. In the oil and gas industry, the petroleum geologist determines the possible presence and extent of hydrocarbons and hydrocarbon-bearing rocks in a basin.

Keywords

Basin analysis; sedimentary basin; shale oil and gas; Tar sands; Oil shale; Tight gas reservoir; total organic content; Early shale play; unconventional reservoir; deep water reservoir; data mining

Outline

Outline

Basin analysis: overview and uses 4

Uses of basin analysis 4

What is a sedimentary basin? 5

Rift basins 5

Basin analysis workflow: from large-scale to mini-scale 7

Large-scale analysis 7

Medium-scale analysis 8

Small-scale analysis 9

Geological architecture of unconventional reservoirs 12

Unconventional and tight gas sands: what we know now 12

Shale oil and gas 12

Oil shale 13

Tar sands 16

Tar sand extraction and processing 16

Coal-bed methane 17

Tight gas reservoir sands 18

Early shale play production projections and subsequent adjustments 20

Upper Safa formation 21

Techniques for unconventional reservoir evaluation and characterization 22

Geochemical analysis 24

Total organic carbon 24

Level of maturity 25

Petrophysical analysis 27

Log analysis 27

Interpretation analysis 28

TOC logs and values analysis 29

Total original gas in place (TOGIP) 30

Deepwater reservoir 33

References 36

Further reading 36

Basin analysis: overview and uses

Basin analysis is of vitally important in oil and gas exploration. It incorporates the processes used to determine where there is a high likelihood of encountering commercial quantities of recoverable hydrocarbons, and thus is integral to prospect generation (Fig. 1.1). In the oil and gas industry, the petroleum geologist determines the possible presence and extent of hydrocarbons and hydrocarbon-bearing rocks in a basin. Basin analysis is often performed by using reflection seismology and data from well logging.

Figure 1.1 Cross section of sedimentary basin where petroleum system analysis is carried out. From AAPG slide show. Source: Courtesy ExxonMobil and F. Schroeder.

Uses of basin analysis

Basin analysis is used in more than simply generating prospects. Geoscientists have expanded basin analysis by incorporating new technologies and techniques. It can now be used for:

• identifying sweet spots through projecting enrichment along migration pathways;

• determining the best fluids to use in drilling and completions;

• developing a reservoir model, and for estimating recoverable reserves; and

• identifying and avoiding geohazards.

What is a sedimentary basin?

A basin can be form by sag related to a fault (Mukherjee, 2014). Basin analysis covers sedimentary basins, which are areas on the Earth’s surface where sediments have been deposited. Generally speaking, basins are quite extensive and can cover tens of thousands of square km (Fig. 1.2). Sedimentary basins can be very deep and also shallow. Deep basins are often marked by high pressures and temperatures at depth.

Figure 1.2 Geology and hydrocarbon potential of the offshore Indus Basin, Pakistan. Source: Carmichael, S.M., et al., 2009. Geology and hydrocarbon potential of the offshore Indus Basin, Pakistan. Petrol. Geosci. 15, 107–116. https://doi.org/10.1144/1354-079309-826.

Sedimentary basins form because of tectonic activity in the Earth’s crust. Crustal subsidence occurs over time, which results in punctuated episodes of sediment accumulation, deformation, and structural activity. There are several mechanisms that result in sedimentary basins, and they include the following.

Rift basins

These sedimentary basins emerge due to the action of sea-floor spreading. They are very important for oil and gas exploration because they tend to have adequate flow, which generate oil and ongoing thermodynamic/thermochemical processes and this encourage the movement of oil along migration pathways (fractures, faults, connected pore spaces, etc.) (Fig. 1.3).

Figure 1.3 Rift basin. Source: From http://homepage.ufp.pt/biblioteca/RoleOfSaltTectonicsInPetroleumSystemsAngolaGulfOfMexico/Pages/Page1.htm.

Compressional-convergent plate basins: These occur where there is structural movement, which creates normal faults with significant throw, and the subsequent shedding of sediments from uplifts and topographic highs (Fig. 1.4B). It is important to keep in mind that tectonic activity can occur in many different pulses within a basin, and a few pulses may not cover the entire extent of the basin.

Figure 1.4 Conceptual models for depocenter migration and axial sediment supply in fault-bend basins. (A) Progressive right-lateral migration of paired bends on the footwall generates compressional uplift and extensional depression on the hanging wall. Sediments are always supplied from the same direction along the long-axis of the basin. (B) Depocenter fixes along the releasing bend result from the right-lateral migration of sediments deposited on the footwall. A transpressional component would be required to generate the sediment source, and en échelon folds may form along the master faults. Both models generate deposits with axial sediments whose thicknesses are greater than the burial depths. Source: Reproduced with permission from Atsushi Noda.

Technical question and practical solutions

Question 1

If all elements of a petroleum system are in place, can one estimate the possibility of Trap Breaching after hydrocarbons migration from source rock, prior to drilling an exploratory well?

Technical solution provided by Oleksandr Okprekyi

Sr. Geologist at Burisma

Definitely. However, it depends on how you will know that all elements of a petroleum system are in place. Is it an area adjacent to an existing field and that is our guess? Is it an offset area? And this is only a hypothesis based on gross analogues. Is it an already drilled area? In any case, if all the elements are in place, we should consider whether the elements are malleable due to the ongoing burial environment, increasing overburden pressure, formation pressure, temperature, new tectonic movements, etc. One can assess this possibility based on the context of available analogues, outcrops, and contemporary seismic data and other than seismic predrill data.

Technical solution provided by Zaw Win Aung

Exploration Geologist at MPRL E&P, Myanmar

Based on my experience through the prospect evaluation workflow via 3D seismic data, there are reasons to leak (breach) the hydrocarbon (HC) from a candidate prospect. Our asset blocks are located in a complex fold belt induced by translational movement of India along the Myanmar plate complex. There are several folds and faults with multiphase structural deformation that dominate with syntectonic deposition of mass flow deposits and turbidities channels deposits throughout the area.

I would focus on seal capability being noticeable in good quality seismic data in terms of trap effectiveness. I have two examples for you as follows; these two are more critical in our study basin (Rakhine Offshore Basin, Myanmar):

1. Subtle faults affected by tectonism: Even though we have all elements in place, we need to investigate the possible seal failure related to minor faults in structural crest, which can be seen on seismic data but not interpretable. In this case, we have to check other indications like leakage paths (strange amplitude responses along and next to the fault).

2. Cap rock lithology: Some prospects have a good seal supported by very transparent seismic characteristics (shale/clays). Some show fair amplitude (likely silty clay, which can leak HC from reservoir) but are not as bright as your underlying reservoir. Based on this, you can evaluate the degree of risk in your prospect.

Technical solution provided by Alexey Sokolov

Reservoir Engineering Team Lead at CGG

The problem of trap breaching could be addressed by direct assessment of factors causing breaching. As breaching is mostly driven by faulting, it is possible to derive appropriate metrics for corresponding common volume elements based on faults crossing the trap and their character in order to update chance of success. Leaking petroleum might be trapped up section in known and/or better pronounced reservoirs or appear as hydrate association on the sea bottom. Data on petroleum seeps and slicks on the surface might provide additional insights on the trap breaching.

Basin analysis workflow: from large-scale to mini-scale

Large-scale analysis

This is essentially reconnaissance a work, which can be done on both frontier basins and those that have been developed. It is often a good idea to return to a basin and conduct a reevaluation of the basin, especially if new data are available, and if new processing methods can result in a new way of viewing existing seismic, drilling, completion, and production information. The steps define Basin analysis workflow: from large-scale to mini-scale.

Step 1: Define the extent of the basin. The basin framework can be determined by the most important regional structural features. Note the tectonic framework as well, and to locate the basin within plate movement.

Step 2: Identify the main structural features and the depocenters. Depending on the extent to which the basin has been developed, it may be possible to incorporate well data. If not, initial basin analysis generally requires the use of satellite imagery, seismic, gravity, magnetic, and information from outcrops. Outcrop information is often correlated with seismic data (e.g., Misra et al., 2015; Misra and Mukherjee, 2018) in order to create a preliminary subsurface basin model, which includes major structural features as well as an idea of sediment depths. This is a good stage to start studying the sediments very closely in order to propose depositional environments and depositional models. By proposing working hypotheses with respect to the depositional environments of each of the formations and basin thermal history, it is possible to start to determine which ones could be good source rocks, or reservoir rocks.

Step 3: Incorporate petroleum system information. It is often possible to conduct tests on cores or to calculate total organic content (TOC) using the Passey method. Favorable levels of TOC and types of kerogen can indicate where there is the possibility of finding economically viable recoverable reserves of hydrocarbons. The next step would be to continue with geochemical methods and determine maturation by using vitrinite reflectance (VR) or other tests. Further, obtaining thermal information can provide information useful in deciding whether the thermal history was adequate for maturation and the generation of hydrocarbons.

Step 4: Determine the structural, depositional, and postdepositional history (e.g., Mukherjee and Kumar, 2018), at basin level. Determining the timing of major structural events is extremely important for determining the timing of hydrocarbon generation, and then, the expulsion and migration through faults, fracture networks, and porous connected sediments. It is also a good time to identify possible structural traps, by defining reservoir rock, seals, and migration pathways into the possible trap.

Once the large-scale analysis has been completed, it is very important to start identifying subbasins, subbasin level depocenters, and local structural movements. The medium-scale analysis is important in narrowing down the scope and starting to rank the sediments and subbasins in terms of relative prospectivity.

Medium-scale analysis

Deposition that results from continued episodes of tectonic activity (mainly subsidence or uplift) and the compartmentalization of the basin into subbasins and mini-basins is important for starting to pinpoint likely areas for oil and gas.

Step 1: Identify subbasins and mini-basins.

Step 2: Create cross sections that reflect the stratigraphic architecture, that incorporate available information and data. Use 2D, 3D, and 4D seismic in order to identify faults, thicknesses of sediments, and the changes through time.

Step 3: Include any field location information in the study. Select the most prospective subbasins and start to map major depositional events. An example is the Cretaceous onlap of the Gulf of Mexico (Fig. 1.5). Keep in mind that separating out the sand-prone sediment system will aid in age-specific studies that incorporate the time sequence and movement over the deposits.

Step 4: Begin to map hydrocarbon types, as well as reservoir fluids. Then place these within a framework of structure, so that it is clear where the major faults and structural features exist, as well as fracture networks at as low as nanoscale. Where possible combine this information with thermal flows in order to gain an idea of maturation, expulsion, migration, and then the possible diagenesis patterns due to hydrothermal fluids. Diagenetic alteration is critical because alteration can both enhance and destroy porosity (sparrycalcity). Chert can clog pore space, but dolomitization can result in enhanced intercrystalline porosity. Possible seals and traps (structural and stratigraphic) can be identified, and the relative likelihood of commercial deposits can be assessed. This is the point in the analysis when it is possible to start creating a time-focused (chronostratigraphic) model of the sediments. Sequence boundaries (unconformities or correlative conformities) correlate to depositional sequences. They can help one map where the transgression surface occurred, and also the point of maximum flooding. The resulting genetic depositional sequences are extremely helpful in being able to map the lateral extent and thicknesses of different formations.

Figure 1.5 Regional seismic lines showing characteristic style of salt tectonics in (A) onshore proximal part of Gulf of Mexico and (B) offshore distal part of Gulf of Mexico. Source: Data from Fonck, J.M., Cramez, C., Jackson, M.P.A., 1997. The 5th International Conference of Brazilian Geophysical Society.

Small-scale analysis

While many geoscientists have looked at the small-scale analysis (e.g., Koji et al., 1990; Movahedasl, 2015) stage as the one in which drillable prospects are identified. Yet, with new techniques of data mining, geochemical analysis, geomechanical modeling, and microseismic analysis, it is possible during this stage to identify sweet spots for acquisition or drilling, plan fluids for drilling and completion, and to develop a reservoir model appropriate for enhanced oil recovery.

Structural movement and migration pathways: Movement along faults, the opening and closing of fractures and fracture networks, along with nanoscale structural behavior due to hydrocarbon generation (gas) and expulsion can be used for proposing migration pathways and pinpointing areas of comparative enrichment. Being able to map facies patterns can also identify relative permeability and porosity, and the ultimate storage capacity in the reservoir. Thus initial and very preliminary reserve potentials can be estimated. Large-scale analysis of surface lineaments (Dasgupta and Mukherjee, 2019) as correlated to different subsurface structural features can provide new insights. Using a combination of well log information, petrophysics, and microseismic data can also help develop mini-basin models that can pinpoint likely geohazards.

Hydrothermal fluid movement: By understanding where heated fluids spent the most time in the reservoir, and understanding their chemical composition (as well as the lithology of the reservoir rock), it is possible to project where there may be porosity enhancement via dissolution or secondary dolomitization. Likewise, it is possible to project where porosity was destoryed due to precipitation/mineral filling of pore spaces and fracture networks. New thermal sensors and data mining techniques are helpful for finding relationships between vast data sets.

Small-scale depositional modeling with typing of grains/mineralogy, along with reservoir fluids: Being able to map facies patterns can help identify the lithologies and their chemical composition. This analytical process will assist in selecting drilling and completion fluids to avoid formation damage. It is possible to fine-tune this process with new geochemical tests and fingerprinting using isotopes.

Fine-scale depositional elements can help one determine chronostratigraphic relationships, and thus identify connected reservoirs, especially in clastics. Microfossils can also be very helpful in carbonates, particularly where there are correlations between the paleoecological environment and reservoir quality.

Question 2

What kind of data, other than seismic predrill data, can be examined (in general) to help ascertain the hydrocarbon potential in poorly known basin? I have an analogue subbasin with oil in this formation. I wonder what methods in particular could I use to better understand my plays, like aero-magnetic survey, etc.?

Technical solution provided by Alexey Sokolov

Reservoir Engineering Team Lead at CGG

Magnetic and gravity data could identify magnetic and density anomalies that can likely confirm/refute petroleum prospects. Gravity and magnetic methods are best suited for detecting steep discontinuities like basement faults since they respond quickly to lateral variations in rock properties, while seismic methods mostly detect stacked rock variations and low-angle discontinuities such as layer boundaries. Studying outcrops might greatly help with understanding of areal extents of potential oil and gas-bearing formation in question. Geochemical screening, like seeps (onshore) and slicks (offshore), is also very useful in understanding the activity of petroleum system(s). Even a mere fact of seeps and/or slicks present is very helpful, not to mention chemical analyses revealing origin and properties of the oil and gas. Data from drilled wells provide important insights, if available. You could also use the data from the wells in the known subbasin to create seismic models to apply to the new basin assuming that the rocks and geological histories are similar.

Technical solution provided by Zaw Win Aung

Exploration Geologist at MPRL E&P, Myanmar

Grav–Mag is fundamental to delineating the potential basin and system elements in a frontier area. You can reduce exploration risks and uncertainties especially in offshore area with seabed coring and related geophysical surveys (subbottom profiler data and multibeam echo sounder bathymetry, backscatter, and water-column data) for potential seeps and sampling for geochemical analysis to evaluate the HC maturity in your basin.

Technical solution provided by Oleksandr Okprekyi

Sr. Geologist at Burisma

A number of supportive methods can be applied, which do not replace seismic, but help decrease necessary CAPEX in the exploration areas.

Gravimetric survey is a geophysical method, which is usually used to study the figure and structure of the Earth. Gravimetric works well in the area of any intrusion presence like salt domes, volcanoes because of a high density contrast of the contiguous rocks (anhydrite vs sandstones, etc.). Negative gravity anomalies occur in a case of the relatively low rock density and positive anomalies—in the case of the relatively high rock density. Of course, it is not always an easy task to perform a proper interpretation of available gravimetric data. However, a skilled interpreter can usually give a fork of possible solutions that minimize possible risk. That is why it is a decent approach in underexplored area and it costs far less than a common seismic survey. Some of the modern gravimetric surveys pretend to reveal not only different sorts of structure anomalies, but occurrence of fracture zones as well, which can help in relatively studied areas to delineate carbonates, tight but fractured sandstones, etc.

A magnetic survey might be used along with gravity. This method measures natural variations of the magnetic field of the Earth; and one can explain these magnetic features and anomalies with geological scenarios. Magnetic and gravimetric methods are very responsive to the lateral variation of the rock properties and that is why that might be good means in detecting not only intrusions, but steep and highly thrown faults as well.

Geochemical survey: The theory is based on the continuous hydrocarbon transportation upward, hence geochemical anomaly may occur over every hydrocarbon accumulation in the subsurface (increase in C2–C12 content, aromatic hydrocarbons, etc.). Gas, condensate, and oil are characterized by different prevailing hydrocarbon components. That is why it is a good option to focus on different anomalies for gas, condensate, or oil accumulations. However, it is often not feasible as we do not know the type of hydrocarbons we will find in underexplored areas. So any anomalies might be interpreted as a positive sign.

Electrical methods: Measure resistivity, which is the inverse of conductivity. This approach is supposed to be a good one in delineating fluid accumulations, characterization of leakage problems, etc.

Remote sensing: Remote sensing techniques such as aerial photography or satellite imagery may be used to allocate geological elements (e.g., Dasgupta and Mukherjee, 2017), which may correspond to the prospective hydrocarbon accumulations.

Question 3

Which technique would be better 1D or 2D/3D, to model maturity of source rock? Which software would you recommend for 1D and 2D/3D?

Technical solution provided by Oleksandr Okprekyi

Sr. Geologist at Burisma

Obviously, the most reliable techniques would be the best. A decent 1D model is much better than an inaccurate 3D model. Complex 3D models are particular about the amount and quality of the input data, which is definitely limited during exploration of a new area. Usually we have limited understanding of present-day geometry including tectonic and lithological elements which may prevent HC migration to particular basin zones, the local stratigraphic elements and reservoir properties, boundary conditions, etc.

In case we have a necessary amount of input data for the proper 3D modeling, it is doubtful, whether we still need modeling maturity of the source rock. In any case, if a good 3D model is unavailable, good 1D model worth a lot as well. Today a number of available software packages model maturity of the source rock. Which one is better? The one you know the best. It is not easy to recommend any of these, because I have experience only with PetroMod (by Schlumberger), but I cannot say it is better or worse than others, as I have no experience with them. I know Halliburton, Basin-Franlap, and Paradigm have similar products. You will need to choose according to your finances and preferences.

Technical solution provided by Zaw Win Aung

Exploration Geologist at MPRL E&P, Myanmar

To answer this question, it depends on the data you have. In my opinion, a 1D model is enough to determine the maturity of source rock and generation window if you have limited data. In one further step, we can input thrust and folds in 2D model and migration pathways in 3D model.

Technical solution provided by Alexey Sokolov

Reservoir Engineering Team Lead at CGG

The mostly regarded maturation parameter is VR (Ro). A fast track technique, called Easy Ro, to determine Ro was published by Sweeney and Burnham (1990), and was further modified by Suzuki to Simple Ro. Both allow quick snap for VR (Ro) then split in maturation windows. It uses the thermal transfer index and windowed conversion proposed by Goff. You will need to supply burial history and a temperature profile. There are more complex techniques published to determine Ro incorporating pressure history and TOC as well as complex petroleum cracking schemes. I suggest you start with a simplified approach and do complex calculations only if motivated by available data that contradicts known facts. There are also about 25 other maturation parameters identified by extensive research. Look for Vitrinite Reflectance as Maturity Parameter by Mukhopadhyay and Dow (2007), for further details.

Geological architecture of unconventional reservoirs

Unconventional and tight gas sands: what we know now

Unconventional reservoirs typically fall into four main categories. All are fairly imprecise and ambiguous but have become convenient labels for reservoirs. Until the early year 2000, unconventional reservoirs were considered uneconomic and more or less unproducible by conventional means (which meant vertical drilling and only one or two stages for hydraulic fracturing). Now, unconventional reservoirs have become the new conventional. Since at times the majority of wells drilled, at least in the continental United States, are horizontals wells 15,000 ft in horizontal length, with 40 or more stages. The original categories of unconventional reservoirs are discussed in the following sections.

Shale oil and gas

This category refers to hydrocarbons produced from shale reservoirs. Shale play are called shale out of convenience, but even though they contain clay minerals and, they are not technically shales. Instead, they are simply extremely fine-grained clastics, often with clay minerals, subarenites, and carbonates, to the point that they are often referred to as mudstones, a rather imprecise denomination which also fails to capture what they are. So, for convenience, it is a good idea to confine oneself to the notion that they are fine-grained clastics typified by extremely low permeability, with extreme heterogeneity with dramatic lateral facies changes and variations. Production occurs through fracture networks, which are usually a combination of natural fractures, and induced fractures, which have been propped open by proppants (Fig. 1.6). This proppants were introduced during the completion phase.

Figure 1.6 Unconventional reservoirs. Source: From http://theconversation.com/coal-seam-gas-is-just-the-latest-round-in-an-underground-war-35164.

Drilling and completion techniques involve placing horizontal wells at an ideal distance from each other to optimize the fracture connectivity and to make efficient use of the drilling infrastructure. In the case of the Bakken shale, which is found in the Williston Basin and North Dakota, there are often several productive zones in a single lease, which allows stacked pay with the potential for additional economically viable production. Examples of shale gas include the Marcellus, which is located primarily in Pennsylvania, Ohio, and West Virginia, and the Haynesville, which is found in the Gulf of Mexico region in the southern United States. The Marcellus has been a good producer of dry gas, but the decline rates have been steep and pipelines, processing plants, and other infrastructure must be built. In the case of the Haynesville, it has been difficult to economically produce the gas as less than $8 per mmcf due to depth, high heat and pressure.

Oil shale

Often referred as kerogen oil, oil shale is basically undermature petroleum which must be heated in order to achieve pyrolysis and to liberate the hydrocarbons. It tends to be in very fine-grained sedimentary rock and the high level of organic matter makes it possible to use different processes in order to release it. Oil shale of lacustrine origin is often associated with continental margins in rift basins. The reservoirs tend to be marked by extreme heterogeneity. Oil shale deposits are found in North America in Utah and Wyoming (Green River formation), where they are generally produced using a process of crushing, heating, and chemically treating the oil shale which can be done either in situ or in a processing facility (Fig. 1.7).

Figure 1.7 Example of shale oil includes the Utica Shale, the Eagle Ford, the Woodford, and the Bakken. Source: From http://info.drillinginfo.com/5-top-bakken-shale/.

An in situ process developed by Shell involves heating the hydraulically fractured formation and then, once the synthesized oil has been generated, pumping it to the surface (Fig. 1.8). Oil shale processes are also found in China, Brazil, and Estonia. The advantages of creating synthetic oil from kerogen include national security and a secure supply if there are no nearby conventional oil and gas reserves. The disadvantages are numerous in that the process is expensive due to the need for energy to heat the rock and water used in the processing. Furthermore, the process tends to produce a number of contaminating byproducts.

Figure 1.8 The shell in situ conversion process. Source: Based on material provided by Shell Exploration and Production company. http://ostseis.anl.gov/guide/oilshale/.

Question 4

I know that shale does not have any effective porosity; if this is the case how come shale is the main hydrocarbon source? How can the hydrocarbon escape from shaly formations?

Technical solution provided by Alexey Sokolov

Reservoir Engineering Team Lead at CGG

1. On how shale is the main hydrocarbon source, deposition of shale mostly happened in relatively tempered environments (lacustrine, lagoonal, and in deep, quiet water). Thus a relatively large amount of organic content is also deposited here. In contrast, sandstone that eventually forms a good reservoir is generally associated with relatively rapid depositional flows (rivers, estuarine, deltaic environments, etc.) that forces thin organic particles to be taken away. The shale is exposed to important condition such as temperature in order to generate mature hydrocarbons—typically no less than 60°C (early oil), and no higher than 200°C (late gas). Immature conditions produce water and carbon dioxide. Overmature conditions produce coke residue.

Note that shale does not have effective porosity in the way that we calculate effective porosity for conventional reservoirs (usually there is a shale volume term (Vshale) in the equation, and we start with the assumption to begin with, that the effective porosity in shale is zero). Shale can be both the hydrocarbon source and the hydrocarbon reservoir, but you have to look at the mineralogical and sedimentary details of the formation to determine exactly where the source and reservoir are (and they may be closely intermingled). It is important to remember all that you have learned about conventional reservoirs (clastics and carbonates with porosity), but also to understand that many of the concepts that we use regularly in those environments have different definitions in the world of shales organic