Resource Plays Understanding The Technology

Introduction Commercial gas production from shales has become a technical and scientific issue since the successful development of the Barnett shale gas plays in Texas, USA. Since this technical advance in shale gas technology, almost 25% of the total US. gas production is from unconventional gas resources, i.e. coal bed methane (CBM) and shale gas. The interest in shale gas and the technology to produce this vast gas resource is now wide spread, including countries in Asia and Europe. Natural gas produced from widely distributed shales or shale-like rock formations will replace dwindling conventional fossil fuel reserves within the next decades. Natural gas replacing coal and oil consumption also benefits the environment from reduced CO2 release from natural gas burning.

Definition of Shales, Shale Gas, and Shale Liquids Shale is the most abundant sedimentary rock in the lithosphere but, at the same time, poorly classified or defined in contrast to sand-stones and lime-stones (for details, see Spencer et al., 2010). Shales and claystones as their precursors are commonly defined as fine grained sediments. Clay minerals (Al-Si minerals) are fine-grained, platy minerals and usually constitute a dominant portion of the shale rock matrix. Fine-graine quartz fragments and other minerals such as, e.g., pyrite (FeS2) or carbonate (CaCO3), are present in various portions. Sedimentary organic matter, collectively termed kerogen, is often incorporated into shales and is part of the solid shale rock. Figure 2 illustrates the composition of a generic shale rock, with

around 3-10 % of fluid-filled (water, or oil/gas) porosity. By their nature compacted shales have low porosities and particularly low permeabilities. The low permeability is the reason for restricted fluid flow in shales. Figure 3 is an example of the cumulative distribution of pore diameters (nm) in a shale sample: roughly 80% of the porosity displays pore diameters between about 3-20 nm. Considering the water and methane molecule diameters at 0.3 and 0.4 nm, respectively, and typical oil

molecule diameters between 1 and 15 nm it becomes obvious that free fluid flow is restricted in deep shales. Figure 4 illustrates the typical pore size distribution of a shale in comparison to a fine grain sandstone. Three types of shale pores are distinguished: Micro-pores, meso-pores and macro-pores; free fluid flow is limited to the macro-pores. Many parameters control permeability and porosity of shales: degree and timing of compaction, mineralogy of the shale, diagenetic mineral phase changes, quantity and type of sedimentary organic matter (kerogen), and the thermal evolution of the kerogen. Also, the amount and degree of structured (fixed) water occupying mineral surfaces constrain porosity and permeability. Finally, extent and direction of tectonic stress / rock deformation is a factor for shale porosity and permeability. Eventually, a combination of these factors may lead to natural fractures in shales (details are provided in CTI’s seminar on Shale Gas/Liquid fundamentals).

Most shales around the world were deposited in marine or restricted basin settings under conditions that allowed for the preservation of settling biogenic (plankton) remains originating from marine surface waters. Remains of plant debris from continental run-off and benthic organisms ultimately also contribute to organic matter in shales. Diagenetic processes convert this organic matter of biogenic origin into kerogen, the solid organic fraction of shales, and the precursor material of all natural gas and oil in the subsurface. The kerogen content in shales is conveniently measured as weight %TOC (Total Organic Carbon) of the dry shale. Usually, TOC and mineral grain size in sediments are inversely related: the finer the sediment, the higher the TOC. Shales can have initial TOC values ranging from below 1% to more than 30%. The type of sedimentary biomass in shales, and the thermal evolution of the shale upon deep burial are key factors for production of hydrocarbons from the shale rock at depth: The thermally instable kerogen macro-molecule starts to break down at higher subsurface temperature; rearrangement of its molecular structure to achieve thermal equilibrium under increasing temperature leads to the formation and liberation of liquid and gaseous hydrocarbons. Figure 5 illustrates this process of hydrocarbon gas formation from the initial shale composed of mineral matrix, water (in the pores of the shale), and kerogen (stage A in Figure 5), through to the final the stage of intense gas generation within the shale (stage D in Figure 5).

The shale in-situ generation of hydrocarbons – in particular of methane gas – increases the internal pore pressure, occasionally to the level of natural rock fracturing. Under this environment of high internal pressure from gas generation, the fluids are partly expelled from the shale in the process of primary migration (stage D in Figure 5). Primary migration within the shale is largely controlled by the pressure differentials within the shale and capillary forces restricting flow. Pressure

release from hydrocarbon expulsion will ultimately provide equilibrium conditions between expelled and remaining hydrocarbons in the shale. In summary, shale gas / shale oil environments are characterized as follows:

A shale gas/oil reservoir is a regionally vast continuous gas/oil reservoir in fine-grain rocks. The gas/oil is self-sourced (in-situ generated) from the organic matter which is part of the

rock’s matrix (Figure 5). There is no requirement for a conventional trap or cap rock to contain formed oil or gas

because the oil/gas is trapped in a rock of low porosity – low permeability: hydrodynamic flow is not possible.

Gas vs. oil in a shale is the result from both the kerogen-type and the thermal history of the shale. Thus, investigations into the kerogen-type and the shale’s thermal evolution are important parameters for production. Shale Organic Matter (Kerogen)-Type and Quantity Economical volumes of gas and/or liquids from shales can only develop in shales which:

Contain initial TOC > 2% Contain sufficient “initially active” TOC vs. “initially inert” (dead) TOC Have attained sufficient thermal alteration (maturation) from overburden for in-situ oil/gas

generation. Shales can contain different types of kerogen, usually assigned Type I-IV. The various types can be conveniently classified by their % Carbon, Hydrogen, and Oxygen element yields in the kerogen; expressed as atomic H/C and O/C ratios, these ratio pairs vary considerably, ranging from very high (initial) H/C and low initial O/C ratios (Type I in Figure 6) to very high O/C and very low H/C ratios Type IV in Figure 6). Crossplots of H/C vs. O/C ratios in kerogen are used to classify different kerogen-types as shown in Figure 6.

The varying H/C –O/C ratio values for the different types reflect different organic source material and different sedimentary environments as described below:

Type I Kerogen originates from very restricted, lacustrine, and most often anoxic environments, resulting in a kerogen of very high H/C ratio and consequently the largest potential for hydrocarbon generation, first as liquids (oil), later as gas.

Type II Kerogen is most abundant and common in many shales, reflecting the classical marine-derived plankton-bacteria organic matter type. Most of the world’s oil originates from the two Types I and II kerogen.

Type III is the kerogen derived from land-plant debris from continental run-off into

sedimentary basins. Kerogen-Type III has a lower H/C ratio, thus generates lower amounts of hydrocarbons, preferably in the form of methane gas, CH4.

Type IV Kerogen represents residual (“dead”) organic matter from partial oxidation and

alteration processes during or shortly after sediment deposition. This material has no or very low capacity for any hydrocarbon generation. Due to the initially high O/C ratio (from partial oxidation), this material is prone releasing CO2 in the course of its diagenesis.

The determination of the kerogen-type and its quantity is an essential first evaluation step for shale gas/oil production: sufficient shale gas/oil requires sufficient amount of kerogen; The kerogen-type is key to the expected products, gas or oil (gas or liquid HC). Today, kerogen-typing is seldom done using the old, cumbersome method of elemental analysis as shown in the famous “van Krevelen Diagram” Figure 6. Instead, optical-microscopy (Figures 7a and 7b) and, in particular, the rapid pyrolysis /oxidation lab method (“Rock-Eval Pyrolysis”, Espitalie et al., 1977) are used. Isolated kerogen or whole shale rock microscopy is usually carried out in the reflected light modus using normal light or UV-irradiation. Under UV-irradiation the so-called “liptinitic organic particles” show prominent fluorescence (unless over-mature, see below). “Liptinite” is sedimentary organic matter high in initial atomic H/C ratio and prone to generate liquid hydrocarbons (oil). Land-derived former woody material is mostly recognized from normal reflected light microscopy as “vitrinite”. Upon burial sedimentary woody debris converts to vitrinite . “Vitrinite” appears grayish in reflected light microscopy and is gas prone. “Vitrinite” is the bulk constituent of humic coals – which are known to generate methane gas and partially store it in the coal matrix as Coal Bed Methane (CBM). “Inertinite” is high-reflecting organic particle debris and corresponds with the Kerogen-Type IV discussed above.

Figure 8 below is an example of applied microscopy analysis to classify and quantify the kerogen in a shale. Gas-prone Vitrinite (V), oil-prone Liptinite (L), and “dead” Inertinite (I) yields are plotted in a ternary diagram along with TOC magnitude data. Shale samples high in both TOC and Liptinite (L) are oil-prone, samples rich in Vitrinite (V) and TOC are dominantly gas-prone.

The Rock-Eval analysis is the third common method for kerogen classification (and the degree of the thermal stage, see below). It involves a sequence of analytical steps carried out on a small rock sample sealed within the instrument unit:

1. First, any (“free”) HC present in the pore system of the rock are flushed out and quantified. 2. The second sequence involves the pyrolytic release of HC and CO2 (“generation” of HC and

CO2 from the shale’s kerogen) over a temperature ramp from 300 to 550oC when the kerogen is thermally cracked. The endpoint of the pyrolysis at 550oC leaves an “exhausted” kerogen in regard to HC and CO2 generation.

3. A third steps involves the oxidation of the shale-TOC at high temperature. These data, pyrolytic HC (basis for the Hydrogen-Index), pyrolytic CO2 (basis for the Oxygen-Index) and TOC from high temperature oxidation are used to identify kerogen-types in shales as described below and in Figure 9.

The Hydrogen-Index (HI; mg generated HC/TOC) and the Oxygen-Index (OI; mg generated CO2/TOC) from Rock-Eval analysis, shown in Figure 9, are analogues to the atomic H/C and O/C ratios in Figure 6. Rock-Eval analysis of shales provides fast and inexpensive results regarding the amount of free HC in the rock’s pore system, the TOC yields, the kerogen-type, and the remaining HC generation potential of the shale. The latter result, the remaining potential, can be of interest to estimate shale gas yields in deeper parts of a basins where direct sample access is not possible.

Shale Organic Matter Maturity Besides organic matter (OM) quantity and kerogen-type (Figures 6, 8, and 9), the shale’s “thermal maturity” plays a key role for HC production from shales. Investigations showed that both subsurface temperature and geologic time spent at or near maximum subsurface temperature play a

role in the “evolution of maturity” of the shale: The higher the subsurface temperature and the longer the geologic time at this temperature, the higher the thermal maturity of the shale. Shale maturity in conjunction with organic matter type plays the dominant role in the shale’s gas/oil ratio (GOR), and - as will be discussed at a later point – is also of prime importance for production performance. Shales need to be exposed to higher subsurface temperatures over elevated geologic time to generate and produce oil and gas from the kerogen. Observations from world-wide case studies suggest a minimum subsurface temperature of 50-60oC for the onset of hydrocarbon generation (Hunt, 1979 and 1995; Tissot and Welte, 1984); depending on the kerogen-type and geologic time constraints intense oil generation is maintained in the 100-150oC window; beyond this temperature threshold, oil generation fades due to its thermal instability in favor of thermally stable methane gas. Finally, the kerogen’s total hydrocarbon generation capacity is exhausted at a level between 250-300oC subsurface temperature. At this point, the remaining kerogen is “burnt out” and has turned into a carbon-like residue with very low atomic H/C – O/C ratios. In Figure 6 the complete thermal evolution of the shale’s kerogen can be tracked from the initial kerogen with (type-dependent) high atomic H/C – O/C values towards the endpoint at over-mature conditions with a residual kerogen of very low H/C-O/C ratios. The thermal evolution pathways for the kerogen-types in Figure 6 (and Figure 9) first affect initial O/C (OI) yields due to the CO2- and CO-elimination from the kerogen macro-molecule at relatively modest subsurface temperatures. At higher temperatures the H/C ratio (HC/TOC; HI) is progressively lowered due to the formation and subsequent release of hydrocarbons from the kerogen. This thermal kerogen cracking along with HC generation is associated with considerable structural change of the kerogen towards a hydrogen-poor mature and overmature kerogen structure:

KerogenImmature = KerogenMature + oil

KerogenMature = KerogenLate/Overmature + gas Figure 10 illustrates in general terms the temperature dependence of hydrocarbon generation in the subsurface from the major kerogen-types. Note the onset for oil and gas generation, the max. oil and gas generation, and termination of generation are all kerogen-type specific due to kerogen-type specific kinetics involved. The present temperature and depth level of a shale is not necessarily an indicator of its maturity: Maximum burial and maximum subsurface temperature exposure may have occurred at some time in

the geologic past. Therefore, maturity indicators – reflecting the time-temperature evolution of a shale – are required to assess the true shale maturity. Two indicators for a shale’s organic maturity are commonly used: Vitrinite reflectance (%Ro) and the temperature point of maximum HC release (Tmax) from Rock-Eval analysis within the pyrolysis temperature window 350-550oC . Vitrinitic particles as shown in Figure 7a and present as land-derived debris particles in most shales experience a systematic light reflectance increase as seen (and measured) under the microscope with increasing shale organic maturity. The extent of light reflectance of vitrinite corresponds with the time-temperature evolution of the shale: at low maturity vitrinite reflectance is low, typically in the 0.2-04% range. At increasing maturity the reflectance increases and may attain values of 2-3% or higher for extreme maturity ranges at deep depths.

Figure 11 is an illustration of a vitrinite reflectance (%Ro) profile in a well with sediments presently experiencing their deepest burial; on a %Ro log scale versus depth (m) a steady increase of %Ro with depth is observed. Also outlined in Figure 11 is an oil-prone shale at about 3.8 km depth (Jersey Harbour Shale) with an average measured Ro around 0.8%, the maturity range for intense oil generation as deduced from Figure 10. Oil generation from the kerogen commences at Ro levels around 0.5%, reaches a maximum at levels around 0.8-0.9%, and is terminated at around Ro 1.4% when gas generation may reach a peak (Figure 10). Usually, late gas generation from a kerogen is terminated at around Ro 3.0% when the kerogen attains a highly condensed, aromatic carbon-like molecular structure of high reflectance under the microscope.

The pyrolysis temperature point of maximum HC release (Tmax, oC) from a shale in Rock-Eval lab analysis is also extensively used as a maturity indicator. Although a less precise measurement on a per sample basis compared to vitrinite Ro

measurements, the maturity assessment is reliable when many samples are taken to form a statistical average. Tmax from Rock-Eval analysis can be used to assess shale maturity level from the fact that increasing maturity levels of shales require increasing pyrolysis temperatures in the Rock-Eval apparatus to further thermally crack the kerogen. Figures 12a and 12b conceptualize this kinetic effect: a pyrolysis temperature of, e.g., 360oC may be required to release pyrolytic hydrocarbons (HC) from a low mature shale’s full HC potential, whereas a late-mature shale needs 500oC to release its remaining HC potential. Figures 12a and 12b illustrate the Rock-Eval “free HC” yields and the pyrolysis “HC generation” curves from two shales at different maturity levels throughout the 250-550oC pyrolysis temperature ramp. The low mature shale sample (Figure 12a) has low amounts of free (already formed and present) HC, but produces large amounts of HC from the 350-550oC pyrolysis at a relatively low Tmax value, e.g. Tmax. 360oC. For the late-mature shale (Figure 12b) abundant free HC are present in the pores, but due to the late maturity stage the remaining HC potential is low. The pyrolytic HC generation curve is shifted to higher temperatures at (e.g.) Tmax 500oC to release this remaining, last HC potential. Rock-Eval Tmax shale maturity data can be converted to %Ro values, and vice versa by applying proper algorithms.

Rock-Eval pyrolysis is fast, effective and inexpensive. As a consequence, there are tens of thousands of Rock-Eval data on record from around the world to assess basic geochemical parameters for shale HC productivity. These parameters include:

Type of Kerogen present in the shale Quantity of Kerogen (%TOC) present in the shale Approximate quantity of HC in the shale’s pores and in adsorbed stage Remaining HC potential of the shale Thermal maturity of the shale Estimates on gas (Sg) and oil (So) saturation of the shale’s pore system Basic geochemical data to reconstruct the initial TOC and HC-potential of now mature and

late-mature shales at time of deposition. Presence of two-phase HC fluids in shale (in conjunction with HC phase behavior study)

Besides these two basic maturity measurements, %Ro vitrinite from reflected light microscopy, and Tmax from Rock-Eval, a number of other geochemical maturity parameters for shale fluid extracts, crude oil and natural gas were established over the last decades. These may be applied in critical cases to compare kerogen maturity with the maturity of the oil or gas present in the shale: Resource gas and oil is not always necessarily of local, in-situ origin. Examples exist in silty shales and tight sands with increased permeability where some or all of the produced HC fluids may represent a migration product (for details see CTI seminar on Resource fundamentals). Shale Maturity Modeling Often, mature and late mature shales prospective for gas/liquid production are outside the measurable data range because samples are not available due to great burial depth. Samples from the same shale formation at low or less mature situations may be collected but then measured sample results have to be projected into deeper basin settings assuming the overburden geologic history. HC generation modeling and basin modeling are the tools required to assess resource plays in deep basins. As mentioned before both temperature and geologic time play a role in the evolution of a rock’s organic maturity. Therefore, HC generation is linked to this evolution. The temperature regime of a basin has the dominating effect on maturity gains. It can be shown that a 10% temperature increase (from, e.g., 100oC to 110oC) over a time interval of 1 m.y. has the same cumulative maturity effect as the shale remaining at 100oC for another 4 m.y., a 400% time increase. Based on measured or assumed kinetic constraints so-called TTI (Time-Temperature-Index) maturity values can be calculated for the buried shale based on the subsidence history of the basin. When seismic data are available and the shale depositional conditions are extrapolated or assumed, the

shale’s thermal maturity and its HC in-situ saturation can be modeled from TTI values. Calculated and modeled TTI values can be converted into (calculated) %Ro and/or (calculated) Tmax. data.

Figure 13 illustrates the burial history of a shale (Doig Formation, Western Canadian Sedimentary Basin, WCSB) from time of deposition to today’s burial stage along with the temperature-depth profile for the region. The shale was exposed to its maximum temperature of 160oC about 40 m.y. ago. TTIArr calculations (Hunt, 1995) define the shale as late mature, corresponding to 1.5% Ro for the shale. The shale underwent oil generation about 80 m.y. until about 50 m.y. ago. Gas generation started later at higher maturity 60 m.y. ago. At maximum burial (max. temperature at 160oC), about 40 m.y. ago, previous oil cracked down to wet gas and condensate. This modeled event sequence is consistent with reservoired gas/condensate occurrences under high gas over-pressure in the closed source/reservoir compartment in the Brassey area, NE British Columbia (Canada). Maturity assessments – either from direct measurements via rock sampling, or from maturity modeling – are important information for HC production from shales; as will be outlined below, optimum resource production is linked to elevated and selected maturity ranges. Production Constrains on Resource Plays: Maturity, Kerogen Conversion, Shale in-situ HC-Generation and Natural Fractures Liquid or gas production from shales is only possible from fully mature shales rich in sedimentary organic matter. HC saturation of the shale’s pore system is essential for economic production and usually only achieved at fully mature conditions with the generation of bulk HC from the kerogen. Since free fluid flow in compacted, mature shales is limited intense shale in-situ HC generation leads to internal pressure built-up which is often preserved over geologic time in closed compartment cells including this “hot” shale. Excessive high fluid pressure from HC generation displaces most of the mobile water, leading to near complete HC saturation of the shale’s pore system. Thus, high internal gas pressure favors increased production from the shale.

High maturity of the shale effects production from the shale as maturity leads to secondary porosity and permeability in shales, two important factors controlling HC production. Figure 14 illustrates this porosity/permeability evolution from the partial conversion of the solid kerogen into gaseous and liquid HC; inevitably, the kerogen volume shrinks in the course of maturity as HC are formed. Reduced kerogen volume in the shale translates to increased porosity and permeability at depth.

In the example of a water-free shale environment and high internal HC pressure, this secondary, enhanced porosity/permeability is preserved and becomes effective for both GIP (gas in place) volume and production rates. The effect and extent of enhanced porosity/permeability can be estimated from geochemical data and constraints ahead of the drill bit.

The precise determination of shale maturity is also important for the question of a single vs. dual fluid phase in the shale. Shales at presently deep, maximum burial have HC present in a single fluid phase. This may change in the course of cooling and uplift where two phases, gas and liquid, may evolve from lowered temperature and pressure. Production from a single HC phase is more effective. Precise maturity, geochemical source rock data along with the geologic history, and HC phase behavior can predict the expected fluid phase and expected production efficiency. Due to physical constraints in extremely narrow pore network systems the shale in-situ hydrocarbons are present in different forms:

Adsorbed HC + Absorbed (Sorbed) HC + free HC = Total HC in place Also, with the large inner surface area of the fine-grain mineral matrix of the shale, HC are adsorbed to surfaces and absorbed in remaining water and in particular into the kerogen-network itself. By convention, the non-free but producible HC in resource plays are termed “Sorbed HC”. Depending on the present temperature in the resource play, kerogen-type and content, the maturity, mineralogy, the geometry of the pore system, and natural fractures, the ratio of sorbed to free gas varies. Free gas in the macro-pores is the first gas produced, followed by the slow process of gas desorption over time as the resource is produced and internal pressures are lowered. Often, the portion of free gas quickly available for production is of economic importance for pay out of

investments. As outlined in ShaleResource, a high conversion rate of the solid kerogen into oil and gas is of multiple benefits: increased porosity and permeability with higher GIP, also resulting into higher production rates; in addition, the ratio of free to sorbed gas is shifted in favor to the free gas! The Bakken Shale in the Williston Basin may serve as a demonstration for successful wells in the infant year of resource plays in the late 1980’s early 1990’s. Figure 15 displays the maturity of produced oils versus the production rates grouped in categories from none to

excellent. In this case a set of geochemical oil maturity parameters was established to assess the maturity of produced Bakken-Shale oils. Production performance is significantly controlled by the maturity/kerogen conversion of the Bakken resource. Similar observations have been made for the Barnett gas resource of Texas (Jarvie et al. 2007).

The Environmental Impact The knowledge of natural fractures and faults in the shale rock and their extension into adjacent formations above is important to resource plays, too. Major faults penetrating the resource horizon and extending into formations above may act as fluid escape routes, leaving a locally depleted target

behind. Small, limited fractures from either tectonic events or natural rock fracturing from HC over-pressure are usually beneficial for resource plays. Figures 16a and 16b show seismic examples of fault/fracture systems present in two areas. Area Figure 16b clearly indicates faults extending to the near-surface acting as a migration avenues for ascending HC gases. In contrast, the background seepage in Figure 16a does not suggest HC ascension despite the faults. This may be due to absence of any commercial HC at depth or tight fault planes. GEL surveys (GEL-Intro) applied on a regional scale over the usually vast area of a shale resource can outline potential sweet spot areas for shale resource plays; also, areas of potential gas escape assisted by faults can be documented. Furthermore, GEL baseline surveys can document the level of active gas seepage to the surface before and after shale frac applications. These data can be crucial in cases of dispute over the possible environmental impact from resource development programs (see also GEL Baseline).

CTI Services in Resource Plays. As a geochemical service company with a long-standing history and the staff’s formal training and expertise in HC source rocks, CTI provides a full and extensive geochemical consultation service to assess resource plays for their GIP/OIP and the production merits:

Field service to collect samples from outcrops, cuttings or cores.

A complete organic and inorganic geochemical field and lab program required for resource play assessment.

Critical review of existing, public data; data error identification and correction.

Reconstruction of initial kerogen content and initial type prior to HC generation to

compare areas and plays in different maturity regimes.

Determination of the in-situ or migrated HC in resource plays.

Conduction of HC generation, HC migration, and HC correlation studies.

Determination of the maturity level of produced resource fluids.

Calculations on secondary porosity enhancement due to kerogen/oil thermal stabilities.

Calculation of GIP and OIP in the area of interest.

HC generation and HC timing modeling.

GEL seep gas surveys to highlight/downgrade drilling locations for resource plays (see also Seep-Intro; GEL-Intro; GEL-in-Depth)

Environmental seep baseline surveys and groundwater analysis to establish

benchmarks for pre-frac near-surface conditions in resource plays (GEL Baseline).

Seminars on petroleum geology/geochemistry and resource play fundamentals.

Seminars on the potential environmental impact from fossil fuel production

In-house consultancy for the client to develop resource plays CTI supports the client to identify sweet spots within vast resource areas. Please contact CTI with any further questions.