12: Diagenetic Evolution of Organic Matter Cements: Implications for Unconventional Shale Reservoir Quality Prediction
Published:January 31, 2020
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Wayne K. Camp, 2020. "Diagenetic Evolution of Organic Matter Cements: Implications for Unconventional Shale Reservoir Quality Prediction", Mudstone Diagenesis: Research Perspectives for Shale Hydrocarbon Reservoirs, Seals, and Source Rocks, Wayne K. Camp, Kitty L. Milliken, Kevin Taylor, Neil Fishman, Paul C. Hackley, Joe H. S. Macquaker
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A new model is proposed to predict porosity in organic matter for unconventional shale reservoirs. This model is based on scanning electron microscopic (SEM) observations that reveal porosity in organic matter is associated with secondary porosity developed within organic matter cement that fills void space preserved prior to oil generation. The organic matter cement is interpreted as solid bitumen resulting from the thermal alteration of residual oil retained in the source rock following oil expulsion. Pores are interpreted to develop within the solid bitumen as a result of thermal cracking and gas generation at increased levels of thermal maturity, transforming the solid bitumen to pyrobitumen. The pyrobitumen porosity model is an improvement over existing kerogen porosity models that lack petrographic validation. Organic matter porosity is predicted by first estimating the potential volume of organic matter cement by deriving the matrix porosity available at the onset of oil generation from extrapolations of lithologic specific compaction profiles. The fraction of organic matter cement converted to porosity in the gas window is then calculated by applying porosity conversion ratios derived from SEM digital image analysis of analogous shale reservoirs. Further research is required to refine and test the porosity prediction model.
The impact of diagenesis on conventional sandstone and carbonate hydrocarbon reservoirs has a long history of study that has advanced to a stage where several empirical models have been developed for quantitative reservoir quality prediction. Advanced models combine depositional parameters (texture and composition) and diagenetic kinetic data within a burial history framework. The ability to more accurately predict porosity prior to drilling employing contemporary sandstone reservoir quality prediction models was made possible by modifying prior approaches that relied only on rudimentary laboratory geochemical simulations and empirical correlations to include high-quality petrographic observations to develop and constrain the models (Ajdukiewicz and Lander, 2010).
Diagenetic studies of unconventional shale reservoirs are less well advanced than their conventional reservoir counterparts. However, interest in mudstone diagenesis and reservoir quality prediction has increased with the dramatic growth of shale hydrocarbon production in North America during the past 15 years.
Published shale reservoir porosity prediction models, such as those proposed by Modica and Lapierre (2012), and later modified by Chen and Jiang (2016), are based on a conceptual material (mass) balance model and empirical geochemical data that assume all significant (hydrocarbon-filled) shale reservoir porosity is associated with thermally degraded kerogen.
Petrographic observations by scanning electron microscopy (SEM) reveal that both matrix and organic matter pores are present in shale reservoirs. More important, much of the observed pores in organic matter are not associated with what can be reasonably interpreted as kerogen, but rather occur within secondary organic matter filling matrix pores and other voids, referred to as organic matter cements. These petrographic observations require a reevaluation of the kerogen porosity prediction model.
The aims of this study and organization of this chapter are several fold: (1) provide background of key observations from prior studies leading to two competing models for the origin of organic matter pores, (2) address the need for consistent terminology and classification of organic matter based on SEM observations, (3) describe and contrast the kerogen porosity and pyrobitumen porosity models, (4) propose a new diagenetic model to predict organic matter porosity, and (5) discuss the limitations of the new model and outline areas for future research.
Some of the confusion and debate regarding the origin of organic matter pores is related to inconsistent terminology in much of the existing literature regarding the description and interpretation of organic matter in sedimentary rocks. Terminology often varies by geologic discipline. For example, petrophysicists often partition all forms of organic matter as “kerogen” as a simplification of the total volume of organic matter required for petrophysical modeling. Geochemists use organic solvent extraction to discriminate soluble bitumen from insoluble kerogen. Organic petrologists use a rigorous set of optical criteria for the microscopic identification and classification of various macerals. Therefore, it is important to provide a clear set of terminology and criteria that is appropriate for the method used to examine the rocks. The following defines terminology and classification of organic matter used in this study appropriate for petrographic examination by SEM.
Cement is defined as any solid material formed during diagenesis that tends to bind the grains (particles) together in a sedimentary rock. Organic matter cement is a form of void-filling solid matter occurring within matrix pores, fossil cavities, mineral interstices, and fractures.
Macerals are any microscopically identifiable forms of solid organic matter in sedimentary rocks and coal classified by their optical properties (ASTM, 2014; Hackley and Cardott, 2016), which includes kerogen and solid bitumen.
Kerogen is solid organic matter formed during early diagenesis from the preserved remains of the original organic matter (e.g., proteins, carbohydrates, lipids, and lignin) incorporated within sediments during deposition (Tissot and Welte, 1984). Kerogen may occur in structured or amorphous forms as disseminated particles, laminations, or as an organic matrix.
Solid bitumen is residual organic matter from the conversion of oil-prone kerogen to petroleum, or from the conversion of once liquid petroleum to a solid residuum. It is amorphous, with the shape defined by the void it fills. Solid bitumen is distinguished from kerogen during petrographic examination by recognizing the void-filling nature of the organic matter, such as impinging euhedral mineral cements, fossil cavities, and fractures (ASTM, 2014).
Pyrobitumen as used in this study refers to porous forms of solid bitumen observed in SEM images in samples at high thermal maturity (typically >1.0%Ro vitrinite reflectance).
Since the first published petrographic images of organic matter pores in the Barnett Shale by Loucks et al. (2009), several researchers have collected numerous petrographic observations of pores from shale reservoirs utilizing SEM. Camp et al. (2013) provide a compilation of contemporary SEM techniques, case history studies describing the applications of SEM microscopy, and a catalog of SEM images from a wide variety of organic-rich mudstones.
Based on SEM petrographic observations of mudstones from a wide range of thermal maturity, it has become apparent that the origin of pores in organic matter is related to thermal maturation of organic matter and generation of petroleum (e.g., Jarvie et al., 2007; Loucks et al., 2009, 2012; Curtis et al., 2012). This has led to the popularization of the “kerogen porosity” model that attributes organic matter porosity to the presence of thermally degraded kerogen.
Bernard et al. (2012), using a variety of specialized methods, including transmission electron microscopy and synchrotron-based scanning transmission x-ray microscopy, concluded that the organic matter pores observed in the gas-mature Barnett Shale were developed in thermally altered secondary solid bitumen (pyrobitumen residue) rather than in kerogen. The porous pyrobitumen residue was observed filling inter- and intragranular mineral pores (organic matter cement) providing potential petrographic criteria for identifying solid bitumen and pyrobitumen using more commonly acquired SEM imagery. This led to the reexamination and identification of solid bitumen and pyrobitumen in other shale reservoirs (e.g., Milliken et al., 2012; Bernard et al., 2013; Jennings and Antia, 2013; Loucks and Reed, 2014; Camp, 2015; Cardott et al., 2015; Lu et al., 2015; Pommer and Milliken, 2015; Canter et al., 2016).
Lohr et al. (2015) further questioned the validity of the thermal origin of kerogen porosity. Working with a thermal maturation series from a variety of organic-rich mudstones, pores observed in thermally immature (vitrinite reflectance <0.4%Ro) structured and amorphous organic matter (interpreted as kerogen) persisted into the oil and gas windows. They discovered pores previously not observed in SEM images in oil-mature (0.5–1.1%Ro) samples were revealed following solvent extraction to remove soluble solid bitumen (residual oil?). Lohr et al. (2015) conclude that some organic matter pores commonly reported from gas shales (>1.5%Ro) may simply reflect inherited original organic structure (primary pores) rather than pore generated in kerogen because of thermal maturation. The study by Lohr et al. (2015), however, does not address the origin of pores observed in organic matter cement.
The observations of pores in organic matter cements (interpreted as pyrobitumen) has led to an alternate “pyrobitumen porosity” model that explains the origin of nanoporous organic matter by the formation of gas bubbles during thermal cracking of solid bitumen to form pyrobitumen (Bernard et al., 2012; Milliken et al., 2013). Camp (2015) and Cardott et al. (2015) have proposed that allochthonous, solid bitumen networks that occupy former intergranular pore space (organic matter cement) form effective, interconnected organic matter porosity in shale reservoirs.
The process responsible for the formation of porosity in organic matter cements is still under investigation. Attempts to reproduce organic matter pores in the laboratory that could elucidate these processes have so far failed to replicate pores that mimic those commonly observed in natural samples (e.g., Dahl et al., 2015; Ko et al., 2016; Camp et al., 2017; Hooghan et al., 2017).
SEM IMAGE OBSERVATIONS
Samples and Methods
Petrographic observations of numerous SEM images representing many of the major productive shale plays in North America (Figure 1) were used to evaluate the merits of the kerogen porosity and pyrobitumen porosity models. Formations represented in the database include the following: (1) Middle to Upper Ordovician Point Pleasant/Utica Formations and Middle Devonian Marcellus Formation in the Appalachian Basin; (2) subsurface equivalents of the Lower Permian (Wolfcampian) Neal Ranch and Lenox Hills Formations in the Delaware Basin; (3) Upper Jurassic Haynesville Formation in the northern Gulf Coast Basin; (4) Upper Cretaceous Eagle Ford Group in the Maverick and central Gulf Coast Basins and (5) Upper Cretaceous Mowry and Niobrara Formations in the Denver, Powder River, and Green River Basins in the Rocky Mountain region.
The SEM images were obtained from fresh core samples. Both secondary and backscattered electron images were acquired from uncoated polished argonion milled surfaces using field-emission scanning electron microscopes at relatively low electron beam energy (10–15 keV) under high-pressure vacuum conditions.
Samples from oil mature (0.94–1.3%Ro) Wolfcampian strata from four wells in the Delaware Basin were examined to characterize porosity, organic matter, and mineral content from type II secondary electron (SE2) images acquired at 10 nanometer/pixel resolution using proprietary computerized digital image analysis by Ingrain (ZoneID®) as described by Walls et al., 2016. Type II secondary electrons originate below the specimen surface and therefore are less influenced than type I secondary electrons by surface topographic irregularities (Huang et al., 2013). The SE2 images provide a limited degree of compositional contrast, but at a higher resolution than backscattered electron images, resulting in images ideal for digital image segmentation into the following components listed in order of increasing grayscale of secondary electron intensity: (1) pores, (2) organic matter, (3) average-density minerals, and (4) high-density minerals (e.g., pyrite). The segmented digital SEM images were used to measure the following: (1) total porosity (PhiT), (2) porosity associated with organic matter (PAOM), and (3) total organic matter (TOM).
Results and Interpretations
Solid organic matter is easily identified in SEM images acquired from flat, smoothly polished surfaces (e.g., Ar-ion milled) by its characteristic low secondary electron yield and low backscattering coefficient; appearing dark gray in standard grayscale images. However, SEM is poorly suited for interpreting specific maceral or kerogen types as described by classical optical petrographic or geochemical methods.
The writer agrees with Lu et al. (2015) that it is often difficult to positively identify various macerals observed in SEM. In the absence of other supporting criteria, such as comparative optical-SEM microscopy (Valentine and Hackley, 2016; Camp, 2017), it is recommended to provide clear descriptive petrographic observations, such as morphology and texture, and avoid the temptation to interpret the type of organic matter that requires additional knowledge beyond that available from standard SEM imagery. The following classification scheme is proposed to improve SEM petrographic descriptions of organic matter.
Proposed SEM Classification of Organic Matter
Organic matter can be classified based on SEM petrographic evidence into three main types: (1) structured, (2) amorphous, and (3) void filling (Figure 2). Additional descriptive terms such as disseminated, laminated, porous, and nonporous can be appended as modifiers (Camp, 2017). The organic components can be further classified similar to the common subdivision of the mineral constituents of sedimentary rocks into grains or particles (structured), matrix (amorphous), and cement (void filling).
Structured Organic Matter (Particles)
Structured, or particulate organic matter is recognized by its distinctive morphology; the edges of which are not defined by bounding mineral grain or cement contacts. The shape of structured organic particles can be highly variable, including angular, platy, rounded, and curvilinear. The surrounding mineral matrix (particularly clays) may be locally deformed, providing evidence of differential compaction around a more rigid particle. Some forms of structured organic matter exhibit distinctive morphology indicative of specific macerals, such as Tasmanites algal cysts and preserved plant cell structures, such as open cellular lumina characteristic of the macerals fusinite and semifusinite.
Amorphous Organic Matter (Matrix)
In contrast with structured organic particles, amorphous organic matter lacks any definitive form. Amorphous organic matter (bituminite) is a primary sedimentary component (maceral) occurring as a diffuse matrix or laminae between mineral grains and structured organic particles. Amorphous organic matter matrix often contains clay- and silt-size mineral grains, which may provide contrast with mineral-free amorphous organic matter cements.
Void-Filling Organic Matter (Cement)
Organic matter cements are distinguished from other forms of organic matter in SEM images based on petrographic identification of cement as a solid, void-filling or pore-occluding material. Void-filling organic matter is thus interpreted as secondary in origin, and its identification is restricted to where there is clear evidence of a prior void, such as within primary pores, fossil cavities, vugs, microfractures, partings, authigenic inter- and intra-crystalline pores, and exfoliated clays (Figure 3).
The external shape of void-filling organic matter is defined by the shape of the void that it fills. Mineral cements, recognized by euhedral crystal terminations, are often observed lining or partially filling primary intergranular pores and fossil cavities, such as within foraminifera chambers. Identification of mineral cements provides definitive petrographic evidence for preexisting voids and thus identification of void-filling organic matter.
It is often difficult to distinguish amorphous forms of organic matter as matrix or cement, particularly in high-magnification SEM images when the field of view is insufficient to positively identify the physical form of the encapsulating void. In some instances, amorphous and structured organic matter (interpreted as kerogen) appear to grade into amorphous organic cement (Figure 4), suggesting the secondary organic matter cement was derived from the conversion of adjacent primary kerogen to oil.
COMPARISON OF ORGANIC MATTER POROSITY MODELS
Kerogen Porosity Model
The kerogen porosity model is based on the hypothesis that the dominant hydrocarbon storage in shale reservoirs is confined to pores within kerogen macerals and that kerogen pores evolve during the thermal maturation of labile (oil-prone) kerogen (Modica and Lapierre, 2012). The kerogen pores are thought to represent the space (volume) remaining within the kerogen following generation and expulsion of oil from the kerogen maceral based on the principle of material (mass) balance as originally proposed by Jarvie et al. (2007) for the Barnett gas shale. Kerogen porosity is thought to regularly increase in a predictable manner with increasing thermal maturity during the transformation of kerogen to oil. This evolution of increasing kerogen porosity is thought to continue until all of the available labile kerogen is consumed, such that no additional pores develop in the gas window; approximately 1.1–1.2%Ro vitrinite reflectance for a typical type II kerogen (Modica and Lapierre, 2012, their figure 9, p. 100).
Predicting the amount of kerogen porosity requires knowledge of four model elements: (1) initial total organic content (TOC), (2) proportion of labile kerogen, (3) level of thermal maturity, and (4) kerogen kinetics relating transformation ratio to thermal maturity (Modica and Lapierre, 2012).
A limitation of the kerogen porosity prediction model is the inability to accurately estimate initial kerogen content and composition, which are often based on extrapolations from present-day geochemical measurements obtained from pyrolysis experiments from thermally mature samples. Recognizing that TOC measurements may include retained free oil (and solid bitumen), Chen and Jiang (2016) proposed adding an expulsion efficiency factor to improve the results of the mass balance model. Comparing results of the two methods to estimate initial TOC from a data set of the Duvernay Formation, Chen and Jiang (2016) showed that results could vary by as much a 2.5 wt% with resulting difference in estimated kerogen porosity of about 5%.
Chen and Jiang (2016) used secondary electron SEM images to illustrate the evolution of kerogen porosity at different levels of thermal maturity as indicated by pyrolysis Tmax measurements. However, it appears that some of the porous organic matter resides within secondary, void-filling organic matter cement rather than within kerogen macerals based on the presence of euhedral mineral crystals outlining a partially mineral-cemented pore (Chen and Jiang, 2016, their figure 8E, p. 416). The authors did not attempt to measure the organic matter porosity from the SEM images to verify their calculated kerogen porosity values. The SEM images clearly reveal a wide variation in organic pore development and pore size within the same field of view, consistent with observations from other formations (e.g., Curtis et al., 2012).
Pyrobitumen Porosity Model
Camp (2015, 2016) introduced a pyrobitumen porosity model based on petrographic observations of the Eagle Ford Formation that reveal a significant proportion of the organic matter porosity observed with SEM is contained within void-filling organic matter cement. Organic matter cements are often the most pervasive type of cement observed in thermally mature shale reservoirs and appear to have a greater volumetric impact on reservoir quality than mineral cements. Organic matter cements appear to form well-connected three-dimensional organic networks that when porous are interpreted to provide an effective, interconnected hydrocarbon storage and permeable flow pathway.
The origin of the now solid organic matter cements is interpreted as a residual product of a once liquid oil that filled pores and other voids during primary migration that is retained within the source rock following oil expulsion (Cardott et al., 2015). This interpretation is supported by the presence of organic matter cements in very small submicron-size pores and occasional interpreted flow structures. Wispy, deformed entrained clays within organic matter cements are interpreted by Wood et al. (2015) as evidence of fluid flow during secondary migration of oil that was subsequently altered forming pore-occluding solid bitumen within the Montney tight-gas siltstone reservoirs. Similar interpreted flow structures are also observed within organic matter cements in some shale reservoirs (Figure 5), suggesting the now solid void-filling organic matter originated as a liquid.
The origin of pores in organic matter cement is thought to be a result of secondary thermal cracking of solid bitumen to form pyrobitumen (Bernard et al., 2012). This process may be similar to the development of pores observed in “sponge coke” resulting from the refining of heavy crude oil (Picon-Hernandez et al., 2008), although the pressure, temperature and time involved during the coking process is quite different than natural thermal maturation. The amount and distribution of organic matter cements, and their secondary internal pores, is mainly a function of the available pore space preserved prior to oil generation and primary migration, and the degree of thermal maturation.
PROPOSED DIAGENETIC MODEL
Predicting the amount of porosity in organic matter using the pyrobitumen porosity model involves estimating the amount of organic matter cement and the fraction of the organic matter cement converted to pores. The development of organic matter porosity follows an evolutionary process that can be divided into five main diagenetic stages: (1) preoil generation, (2) oil generation, (3) organic cementation, (4) organic porosity generation, and (5) postgas neometamorphism. The evolution of organic matter porosity development is illustrated with a hypothetical model.
Stage 1: Preoil Generation
The potential amount of organic matter cement is a function of the amount of matrix porosity preserved at the onset of oil generation following porosity loss because of mechanical compaction and early mineral cementation. Lithologic-specific compaction profiles, combined with burial history models, are used to predict the matrix porosity at the depth of the onset of oil generation. This represents the pore space available to be saturated with oil, which is later converted to organic matter cement (solid bitumen) following the pyrobitumen porosity model.
Compaction profiles have long been used to predict porosity in sedimentary rocks. This method works reasonably well in the shallow portions of basins, up to a depth of 2–3 km (6600–9800 ft), that have not experienced significant uplift and erosion (Osborne and Swarbrick, 1997).
Variation in sediment compaction profiles has been shown to be a function of sediment grain size and composition, and therefore, it is important to select an appropriate compaction model that is analogous to the specific mudstone under study. Kominz et al. (2011) demonstrated predictable exponential decrease in porosity with depth relationships for a variety of sediment compositions up to a burial depth of 1800 m (5900 ft) based on Ocean Drilling Program core data. Fabricius et al. (2008) provide porosity-depth relationships for Cretaceous chalks of varying mineralogy that provide useful data for shale reservoirs of similar composition, such as the Eagle Ford and Niobrara Formations.
Fluid retention, most notable in rapidly buried low-permeability mudstones, can result in the generation of overpressure because of disequilibrium compaction (Osborne and Swarbrick, 1997) and preservation of porosity that is abnormally high compared to normally compacted sediments at the same depth and composition. The generation of overpressure during compaction of shale reservoirs could conceivably have a significant impact on the preservation of matrix porosity available for organic matter cementation. Most of shale formations in this study are interpreted to have been deposited as condensed stratigraphic intervals during marine transgressions overlying drowned carbonate platforms, an environment not conducive for rapid burial and overpressure generation. Overpressure observed in many of the shales used in this study is likely the result of hydrocarbon generation, an event occurring after most of the porosity loss during compaction.
A wide variety of mineral cements, including authigenic calcite, dolomite, quartz, pyrite, apatite, feldspar, illite, and kaolinite, have been documented by recent diagenetic studies of various mudstones (e.g., this volume). Precipitation of many of these cements likely coincides with mechanical compaction such that compaction profiles from actual sediments can be useful analogs to provide a reasonable approximation of porosity loss owing to both compaction and cementation during the preoil generation stage of diagenesis. However, it is important to recognize that some cements (particularly carbonates) may form prior to any significant porosity loss because of compaction that limits the use of compaction profiles to predict porosity loss for early cemented rocks.
The temperature-dependent initiation of quartz overgrowths has been used to model porosity loss due to quartz cementation in sandstone reservoirs (Lander et al., 2008). Other well-known thermokinetic reactions, such as the conversion of smectite to illite and opal to chert, may provide useful insights for mudstone reservoir quality prediction; however, this approach remains untested. Because calibrated thermokinetic models for mudstone porosity prediction are generally lacking, an alternate approach is employed by approximating the amount of porosity remaining following compaction and mineral cementation from extrapolating mudstone compaction curves (porosity vs. depth) to the depth (temperature) of the next diagenetic stage of primary oil generation.
A hypothetical model is illustrated by Figure 6. Three end-member lithology types representative of the formation of interest were selected: (1) clay, (2) silt, and (3) diatomite. A burial history model calibrated with vitrinite reflectance data was used to estimate the depth of burial for the thermal maturity thresholds corresponding to the onset of oil generation (0.6%Ro), late oil (1.0%Ro), and dry gas (2.0%Ro). For the siltstone model, the initial sediment porosity of 70% is reduced to 20% at the onset of oil generation modeled at a burial depth of 3000 m (9800 ft) (Figure 6a). This represents the maximum amount of potential organic matter cement assuming 100% organic cementation.
Stage 2: Oil Generation
The amount of organic matter cement is also a function of the degree of oil saturation during oil generation and primary migration. The amount of oil generated is primarily a function of temperature and kerogen type (Tissot et al., 1987). As oil is generated, it begins to fill the available matrix pore space within the source rock until a critical saturation threshold is reached resulting in expulsion from the source rock.
Scanning electron microscopic observations reveal that not all matrix pores contain organic matter cement, and some matrix pores are only partially occluded with organic matter cement (Figure 7). The amount of organic matter cement is a reflection of the effectiveness of the source rock to generate sufficient amounts of oil to saturate the matrix pore space and the connectivity between matrix pores. Figure 8 illustrates well-preserved clay mineral pores surrounding structured organic matter. Most of the matrix pores are devoid of organic matter cement in this oil-mature sample. This suggests that the structured organic matter may be gas-prone or inert kerogen, resulting in an insufficient amount of oil generated to saturate the available matrix pore space.
Further research is required to develop a model to predict the degree of oil saturation based on a combination of source rock geochemistry and petrography. Based on digital image analysis of Wolfcamp Shale SEM images, an organic saturation index (OSI) was calculated by dividing the total organic matter cement by the total porosity less organic matter cement. The amount of organic matter cement is measured by the sum of total organic matter (TOM) plus the pores associated with organic matter (PAOM). Total porosity less organic matter cement is a useful petrographic measurement similar to the intergranular volume measurement used in sandstone and mudstone petrology (Milliken and Olson, 2017) that represents the total porosity prior to organic matter cementation. The total porosity prior to organic matter cementation is measured by the sum of total porosity (PhiT) and TOM.
The OSI measured from the Wolfcamp SEM images ranged from 3 to 97%. In the hypothetical siltstone model, the 20% available matrix porosity at the onset of oil generation, representing the maximum potential organic matter cement, is reduced by the OSI to 18%, assuming an OSI of 90% (Figure 6b).
Stage 3: Organic Cementation
Organic matter cements have been observed in SEM images occluding interparticle pores between coccolithopohre fragments and in foraminifera chambers in the Eagle Ford Formation by at least 0.45–0.5%Ro vitrinite reflectance (Wawak and Gentis, 2013, p. 189–190; Camp, 2015; Pommer and Milliken, 2015. Fishman et al. (2013) illustrated secondary void-filling amorphous organic matter filling radiolarians and pore spaces between microcrystalline quartz aggregates in chert beds from the Woodford Formation at less than 0.5%Ro vitrinite reflectance. Schieber (2013) described amorphous organic matter commonly infilling crystallites in pyrite framboids in the New Albany Shale at less than 0.6%Ro vitrinite reflectance.
Some of the solid organic matter cements observed in SEM images within the oil-generative window may represent artifacts of devolatilized oil as a result of core extraction, sample preparation, and SEM vacuum-pressure conditions, and therefore may not reflect the physical properties of the organic matter at reservoir subsurface pressure and temperature. Observations of oil bleeding from retrieved cores and oil production from tight-oil reservoirs within the oil-maturity window document the presence of mobile liquid oil.
Canter et al. (2016) illustrate what they interpret as oil seeping along microfractures and bleeding from pores under vacuum conditions during SEM imaging and have proposed criteria to distinguish apparent organic matter pores associated with viscous (altered) oil from true organic matter pores in secondary organic matter (solid organic matter cement).
However, it is clear that organic matter cements form true solids in the subsurface sufficient to preserve voids (organic matter pores) commonly observed in the gas-generative window. The timing and nature of the transformation of liquid residual oil to solid bitumen remains a topic of debate. In the proposed model, matrix porosity is thought to decrease as the residual oil becomes bituminized during late oil generation before organic matter pores develop in the gas window. It is possible that the bituminization process is gradational, and not a step-wise process, such that liquid oil and solid bitumen cements coexist in the late oil generation window.
The transformation of residual oil to solid bitumen (organic matter cement) is shown in the hypothetical model (Figure 6b) to reduce the 18% organic-filled portion of the matrix pore space to essentially zero prior to reaching the late oil stage (1.0%Ro) coinciding with the thermal-maturity level of the first appearance of pores within organic matter cements as discussed in the following section.
Stage 4: Organic Porosity Generation
Based on the petrographic observations of various organic-rich shales at increasing levels of thermal maturity, it is apparent that the development of porosity in organic matter (excluding primary pores in kerogen) is a result of the thermal degradation of organic matter. Loucks et al. (2009) described the first appearance of organic matter pores in the Barnett Shale between 0.8 and 1.35%Ro. Reed and Loucks (2015) later confirmed that the presence of pores in organic matter is rare below 0.7%Ro equivalent but documented a few pores inorganic matter occurring between framboidal pyrite crystallites as low as 0.52%Ro equivalent calculated from pyrolysis Tmax measurements. Curtis et al. (2012) described the onset of organic porosity development in the Woodford Shale between vitrinite reflectance of 0.9 and 1.23%Ro. Based on a compilation of published data from a variety of U.S. shales, Han et al. (2017) showed that the onset of organic pore development appears to coincide with thermal maturity level at about 0.8%Ro.
Degree of Organic Porosity Development
Although well-developed organic matter porosity is often observed at high (gas-mature) thermal maturity, there is no clear relationship between increasing thermal maturity and increasing porosity. In fact, the degree of porosity development in organic matter can vary considerably, even within the same sample and same field of view (Figure 9). Curtis et al. (2012) noted that the pore development within organic matter in the Woodford Formation in the Anadarko Basin was not uniformly developed regardless of the thermal maturation level and reported up to 50% porosity in organic matter in some shales (Curtis et al., 2010). Loucks et al. (2009, 2012) reported the abundance of pores in organic matter ranged from 0 to 41% from SEM measurements of a variety of formations. Milliken et al. (2013) reported porosity within organic matter visible in SEM ranged from 0.4 to 30.9% from two wells in the Marcellus Formation in the Appalachian Basin. The variability in organic matter pore development was postulated to be caused by variation in organic matter composition (kerogen type) or local compaction.
An organic porosity conversion ratio (PCR) was calculated after Driskill et al. (2013) to measure the fraction of original solid organic matter converted to porosity by dividing the PAOM by the sum of the PAOM and TOM:
The organic PCR is also referred to as the apparent transformation ratio (ATR) by Walls et al. (2016); however, this terminology is not recommended to avoid any implications regarding the process of organic matter porosity development or confusion with the established transformation ratio term used in organic geochemistry. The organic PCR ranged between 0.7 and 28.7% (average 13.9) (Figure 10) for images with SEM-measured organic matter content greater than 1%.
The predicted average organic matter porosity is calculated by the product of the volume of organic matter cement and the mean PCR. For the hypothetical model, the Wolfcampian shale’s 14% mean PCR was applied as an analog value, resulting in a predicted mean organic matter porosity of 2.5% for the siltstone example (Figure 6b).
Stage 4: Late Gas Neometamorphism
Highly porous organic matter has been reported from samples of the Marcellus Formation at thermal maturity levels between 2.99 and 4.5%Ro vitrinite reflectance (Laughrey et al., 2011; Piane et al., 2018), reaching the semianthracite stage of organic metamorphism (late prehnite–pumpellyite metamorphic stage). The organic matter has transformed to an amorphous (noncrystalline) form of proto-graphite, which is highly conductive (Walters et al., 2014; Clennell et al., 2017), resulting in a low-resistivity log response characteristic of wells drilled in the northern Alleghenian fold-and-thrust belt in north-central Pennsylvania. The few well completion attempts in this region have failed to produce significant amounts of gas and were plugged and abandoned. Isotopic gas analysis of the produced gas is consistent with gas generated at the elevated thermal maturity (Laughrey, 2014). The failure of the wells to flow gas at commercial rates, however, does not appear to be because of a loss of organic matter porosity based on the abundance of observed pores in SEM images.
The proposed pyrobitumen porosity prediction model offers a more simplified approach than the numerous calculations required by the kerogen porosity models developed by Modica and Lapierre (2012) and Chen and Jiang (2016) by reducing the number of variables that are difficult to reliably measure or estimate. The validity and utility of the proposed pyrobitumen porosity prediction model requires further testing and calibration with measurements of organic matter porosity obtained from SEM images, or other methods.
The available mudstone compaction curves used to predict the preserved porosity prior to oil generation typically do not include organic-rich rocks or sapropel sediments, resulting in unrealistic predictions of no organic matter porosity, such as in the diatomite compaction curve illustrated by example model (Figure 6). Observations from biosiliceous organic mudstones, such as the Monterey, Mowry, and Woodford Formations, reveal the presence of organic matter cements filling voids between microcrystalline quartz interpreted as recrystallized diatomite and radiolarite. Excluding the volume of organic matter results in an underestimation of the organic matter porosity. Error may also be introduced by extrapolating compaction profiles beyond the limits of the measured burial depths of the porosity data. In the proposed model, porosity loss owing to concurrent mineral cementation is assumed to be accounted for by the mechanical compaction profiles. Further research is required to document how much of the preoil generation porosity loss may be due to cementation and develop predictive models required to revise the “pure” compaction trends.
More petrographic measurements of porosity within the organic matter and mineral matrix are required to provide statistical data from a variety of formations and rock types to better model the hydrocarbon saturation index and the degree of organic porosity development that is required to predict the volume of organic matter cement and organic matter porosity. Current automated digital image segmentation techniques cannot differentiate organic matter cement from other forms of organic matter. Images need to be carefully reviewed prior to calculating organic PCRs to ensure that there is sufficient organic matter present (>1%) and to avoid images that lack organic matter cement.
Porosity measurements from SEM images are often compared with other porosity measurements such as bulk core analysis and petrophysical calculations from borehole wireline logs. Discrepancies between the various methods are related to the inherent limitations of the porosity measurement technique (Saidian et al., 2016; Perry et al., 2017). The proposed method of estimating organic matter porosity is obviously limited to the size of pores detectable by state-of-the-art SEM imagery from Ar-ion milled specimens, ideally about 5–10 nm. Smaller pores are detectable by other methods, such as He-ion microscopy, and pore size distributions are calculated from mercury capillary injection. Including this smaller pore fraction may minimize differences between porosity measured by SEM and other methods. Cavanaugh and Walls (2016) compared porosity measurements between conventional field emission SEM at 10 nm pixel resolution with He-ion microscopy at 0.5 nm pixel resolution and concluded that the volume of pores less than 10 nm in diameter measured by He-ion microscopy was negligible.
The impact on reservoir quality by metamorphism leading to the conversion of organic matter to graphite is currently poorly understood. Petrographic observations of organic mudstones at high thermal maturity (>3–4%Ro) reveal the presence of organic matter porosity similar in morphology and magnitude with organic matter pores observed in productive shale reservoirs at lower thermal maturity. This neometamorphic zone is often recognizable by low resistivity log responses because of increased conductivity of the organic matter. Failure to recognize the resistivity response with respect to the high level of thermal maturity could lead to erroneous petrophysical calculations of high water saturation.
Present methods for predicting shale reservoir quality prior to drilling typically rely upon preparing porosity and other contour maps based on petrophysical models calibrated with core measurements. The reliability of this method is dependent on the density, distribution, and quality of the well data. The petrophysical models may become unreliable in areas with little subsurface data control because of lateral geological variation. In areas with little to no well control, map-based methods are insufficient, requiring alternate methods to predict reservoir quality.
The proposed shale reservoir porosity prediction model is an attempt to improve upon the existing kerogen porosity prediction models that are based on a conceptual geochemical material balance model and empirical correlations that have yet to be rigorously tested. The new proposed model is constrained by detailed petrographic observations that identify porous organic matter occurring within a network of interconnected secondary void-filling organic matter, or organic matter cement. The organic matter cement is interpreted as a thermally altered residue (referred to as pyrobitumen) derived from residual oil and solid bitumen retained within mineral matrix pores following oil expulsion from oil-prone source rocks. The primary control of the amount and distribution of organic matter porosity is, therefore, a function of the available matrix pore space at the onset of oil generation, and level of thermal maturity.
The amount of preserved matrix porosity following mechanical compaction and mineral cementation is a function of grain size and composition that is predicted from porosity-depth measurements for various mudstone rock types. This is a significant departure from the existing kerogen porosity models that specifically exclude any contribution of mineral matrix porosity, or the impact of lithology and mineral diagenesis to the evolution of organic matter porosity development.
Although the proposed porosity prediction model requires further calibration and validation, the new model does provide useful insights to the process and controls of the diagenetic evolution of organic matter cements and shale reservoir porosity supported by petrographic observations. Hopefully, this chapter will inspire further research on mudstone diagenesis that could positively impact future exploration and development strategies for shale hydrocarbon reservoirs.
I wish to acknowledge the constructive reviews by Mark Rudnicki and Katherine Whidden, and the editorial guidance by Joe Macquaker for correcting errors and suggested revisions that helped to improve this chapter. I also wish to thank Paul Hackley, Maria Mastalerz, Joe Curiale, and Brian Cardott for their helpful suggestions regarding organic petrology terminology. Lastly, I thank Stephanie Perry for her encouragement and assistance in compiling the Wolfcamp SEM data, Kevin Horn for his help in preparing the figures, and Anadarko Petroleum Corporation for permission to publish this chapter.