SPE 114164 Rock Typing — Keys to Understanding Productivity in Tight Gas Sands

This paper presents a work-flow process to describe and characterize tight gas sands. The ultimate objective of this work-flow is to provide a consistent methodology to systematically integrate both large-scale geologic elements and small-scale rock petrology with the physical rock properties for low-permeability sandstone reservoirs. To that end, our work-flow integrates multiple data evaluation techniques and multiple data scales using a core-based rock typing approach that is designed to capture rock properties characteristic of tight gas sands. Fundamental to this process model are identification and comparison of three different rock types — depositional, petrographic, and hydraulic. These rock types are defined as: ● Depositional — These are rock types that are derived from core-based descriptions of genetic units which are defined as collections of rocks grouped according to similarities in composition, texture, sedimentary structure, and stratigraphic sequence as influenced by the depositional environment. These rock types represent original large-scale rock properties present at deposition. ● Petrographic — These are rock types which are also described within the context of the geological framework, but the rock type criteria are based on pore-scale, microscopic imaging of the current pore structure — as well as the rock texture and composition, clay mineralogy, and diagenesis. ● Hydraulic — These are rock types that are also defined at the pore scale, but in this case we define "hydraulic" rock types as those that quantify the physical flow and storage properties of the rock relative to the native fluid(s) — as controlled by the dimensions, geometry, and distribution of the current pore and pore throat structure. Each rock type represents different physical and chemical processes affecting rock properties during the depositional and paragenetic cycles. Since most tight gas sands have been subjected to post-depositional diagenesis, a comparison of all three rock types will allow us to assess the impact of diagenesis on rock properties. If diagenesis is minor, the depositional environment (and depositional rock types) as well as the expected rock properties derived from those depositional conditions will be good predictors of rock quality. However, if the reservoir rock has been subjected to significant diagenesis, the original rock properties present at deposition will be quite different than the current properties. More specifically, use of the depositional environment and the associated rock types (in isolation) to guide field development activities may result in ineffective exploitation. Introduction Unconventional natural gas resources — tight gas sands, naturally-fractured gas shales, and coalbed methane reservoirs — comprise a significant percentage of the North American natural gas resource base and these systems represent an important source for future reserve growth and production. Similar to conventional hydrocarbon systems, unconventional gas reservoirs are characterized by complex geological and petrophysical systems as well as heterogeneities — at all scales. However, unlike conventional reservoirs, unconventional gas reservoirs typically exhibit gas storage and flow characteristics which are uniquely tied to geology — deposition and diagenetic processes. As a result, effective resource exploitation requires a comprehensive reservoir description and characterization program to quantify gas-in-place and to identify those reservoir properties which control production. Although many unconventional natural gas resources are characterized by low permeabilities, this paper addresses only low-permeability sandstone reservoirs, i.e., tight gas sands. The oil and gas industry has long recognized the importance of pore structure (i.e., pore and pore throat dimensions, geometry, size, distribution, etc.) on fluid flow and storage properties in all types of porous media. Understanding the pore structure and 2 J.A. Rushing, K.E. Newsham, and T.A. Blasingame SPE 114164 properties is probably even more critical in tight gas sands since diagenesis often modifies the original pore structure and reduces the average pore throat diameter, typically causing an increase in both tortuosity and the number of isolated and/or disconnected pores. Some forms of diagenesis may actually increase porosity by creating secondary or micro-porosity. Regardless of the type of diagenesis, all tight gas sands retain some underlying traits of the depositional system even though the original rock properties may have been (significantly) altered. However, well productivity cannot be predicted accurately based solely on the rock properties expected for those specific depositional environments and conditions. Because of the importance of understanding pore-scale rock properties, we are proposing a rock typing work-flow process developed specifically for tight gas sands. The concept of rock typing is not new to the petroleum industry. In fact, the petroleum literature is replete with papers describing rock typing techniques for conventional reservoirs. Unfortunately, there is no truly consistent rock type definition — especially for tight gas sands — although there are often similar evaluation techniques and data sources used to identify the rock types. The most widely quoted definition is often attributed to Gunter, et al. [1997a and 1997b], but we note that this definition was first given by Archie [1950] who defined a "rock type" as: ...units of rock deposited under similar conditions which experienced similar diagenetic processes resulting in a unique porosity-permeability relationship, capillary pressure profile and water saturation for a given height above free water in a reservoir. (Archie [1950]) Archie's definition implicitly suggests inclusion of depositional system properties, as well as any diagenetic effects in the identification of rock types. This definition also indicates that rocks should be grouped according to physical properties controlling fluid storage, flow, and distribution. We should also note that Archie's reference to "height above free water" in a reservoir may not be applicable to "basin-centered gas systems" [Masters, 1979] which is defined as ... a basin-centered gas system ...is an abnormally-pressured, gas-saturated accumulation in a low permeability reservoir lacking a down-dip water contact. ([Law 2000]) Many basin-centered gas reservoir systems can also be classified as tight gas sands — however; the characterization of basincentered gas systems typically requires multiphase rock fluid properties (e.g., gas-water capillary pressure, gas-water relative permeability, etc), as well as the role of shale (Is the reservoir dominantly shale? How do the sand/shale sequences interact? etc). Although basin-centered gas reservoir systems are not specifically addressed in this paper, our proposed rock typing approach is applicable to basin-centered gas systems (with extensions, some of which are noted above). In Tables 1 and 2 we summarize: rock type definitions, data sources, and evaluation methodologies for selected reservoir description and characterization studies of sandstone and carbonate lithologies (respectively). Inspection of the compiled references shows that most of the technical literature addressing rock typing studies does include some or most of the aspects suggested by Archie's definition. We also observed the following rock types common to several studies: ● Lithofacies are defined by Porras, et al. [1999] and Perez, et al. [2003] as "mappable stratigraphic units, laterally distinguishable from the adjacent intervals based upon lithologic characteristics such as mineralogical, petrographical, and paleontelogical signatures that are related with the appearance, texture, or composition of the rock." Similar rock types have also been defined as geological facies or simply facies. This definition has been applied to studies of both carbonate and sandstone reservoirs. Both lithofacies and geological facies are identified from either log-based analyses or core-based descriptions and incorporate large-scale elements within the geologic framework. ● Petrofacies are defined by Porras, et al. [1999] as "intervals of rock with a similar average pore throat radius, thus having similar fluid flow characteristics." Other similar definitions have been referred to as petrophysical rock types, reservoir rock types, and static rock types. Common to all of these rock type definitions is an attempt to correlate the pore structure (i.e., pore and pore throat dimensions, geometry, size, distribution, etc.) to physical rock properties such as effective porosity and absolute permeability. Pore system characteristics are typically identified using mercury-injection capillary pressure measurements. ● Electrofacies are again defined by Perez, et al. [2003] as "a similar set of log responses that characterizes a specific rock type and allows it to be distinguished from other. Electrofacies are obviously influenced by geology and can often be assigned to one or another lithofacies, even though the correspondence is not universal." The electrofacies rock type is similar to the lithofacies in that it is attempting to identify and group rocks based on large-scale geologic features as manifested by the log responses. Based on our literature search, use of the electrofacies rock types appear to be confined to just carbonate reservoirs. Although all rock typing approaches evaluated from the petroleum literature (and summarized in Tables 1 and 2) use similar data sources and evaluation methodologies, none of these studies proposes a comprehensive methodology that is developed specifically to capture rock properties characteristic of tight gas sands. Therefore, the overall objective of this paper is to propose a work-flow process that provides a systematic rock typing process to integrate both large-scale geologic elements and small-scale rock petrology with the physical rock properties in low-permeability sandstone reservoirs. Essential components of our process model are identification, specification, and comparison of three rock types (i.e., the depositional, petrographic, and hydraulic rock types). SPE 114164 Rock Typing — Keys to Understanding Productivity in Tight Gas Sands 3 Table 1 — Summary of Selected Rock Typing Studies and Definitions for Sandstone Reservoirs Reference Formation/ Location Rock Type Definitions Data Sources / Evaluation Methodologies Davies, et al. [1991] Travis Peak sands, East Texas Salt Basin No specific definitions ● Depositional environments, sand body geometry, dimensions from core descriptions ● Texture, composition, lithology from microscopic imaging ● No quantitative porosity-permeability ranges; provided qualitative indicators Porras, et al. [1999] Santa Barbara and Pirital Field sands, Eastern Venezuela Basin Lithofacies, petrofacies ● Physical core descriptions of both large-scale & small-scale features; microscopic imaging of texture, composition, lithology, diagenesis ● Core-based measurement of porosity, permeability; dominant pore throat diameter from mercury-injection capillary pressure data Davies, et al. [1999] Wilmington Field Pliocene-Age sands No specific definitions ● Depositional environments, sand body geometry, dimensions from core descriptions ● Texture, composition, lithology from microscopic imaging ● No quantitative porosity-permeability ranges; provided qualitative indicators Boada, et al. [2001] Santa Rosa Field, Eastern Venezuela Basin Lithofacies, petrofacies ● Physical core descriptions of both large-scale & small-scale features; microscopic imaging of texture, composition, lithology, diagenesis ● Core-based measurement of porosity, permeability; dominant pore throat diameter from mercury-injection capillary pressure data Leal, et al. [2001] Block IX sands, Lake Maracaibo Basin, Venezuela Lithofacies, petrofacies ● Physical core descriptions of both large-scale & small-scale features; microscopic imaging of texture, composition, lithology, diagenesis ● Core-based measurement of porosity, permeability; dominant pore throat diameter from mercury-injection capillary pressure data Madariage, et al. [2001] Sandstone/ C4 & C5 sands, Lagunillas Field, Lake Maracaibo Basin, Venezuela Lithofacies, petrofacies ● Physical core descriptions of both large-scale & small-scale features; microscopic imaging of texture, composition, lithology, diagenesis ● Core-based measurement of porosity, permeability, electrical properties; dominant pore throat diameter from mercury-injection capillary pressure data Porras, et al. [2001] Tertiary & Cretaceous sands, Santa Barbara Field, Eastern Venezuela Basin No specific definitions ● Physical core descriptions of both large-scale & small-scale features; microscopic imaging of texture, composition, lithology, diagenesis ● Core-based measurement of porosity, permeability; dominant pore throat diameter from mercury-injection capillary pressure data Soto, et al. [2001] K1 sands, Suria & ReformaLibertad Fields, Apiay-Ariari Basin, Columbia No specific definitions ● Core-based measurement of porosity, permeability; dominant pore throat diameter from mercury-injection capillary pressure data ● Used fuzzy logic to predict rock types in uncored wells Marquez, et al. [2001] LL-04 sands, Tia Juana Field, Lake Maracaibo Basin, Venezuela Lithofacies, petrofacies ● Identification of stratigraphic units and lithofacies from log analysis ● Physical core descriptions of small-scale features; microscopic imaging of texture, composition, lithology ● Core-based measurement of porosity, permeability; up scaled permeability using NMR log measurements Ali-Nandalal & Gunter [2003] Pliestocene-age sands, Mahogany Field, Columbus Basin, Venezuela Geological facies, Petrophysical rock types ● Facies identified using coreand log-based analyses of primary sedimentary structures ● Core-based measurement of porosity, permeability and electrical properties Ohen, et al. [2004] Shushufindi Field sands, Oriente Basin, Ecuador Geological facies ● Facies identified using coreand log-based analyses of stratigraphy, structure, depositional environment ● Core-based measurement of porosity, permeability and water saturation Acosta, et al. [2005] El Furrial Field sands, Venezuela Geological facies, Petrophysical rock types ● Facies identified using coreand log-based analyses of stratigraphy, structure, depositional environment ● Core-based measurement of porosity, permeability and water saturation; pore characteristics from mercury-injection capillary pressure data Guo, et al. [2005] Napo formation sands, Oriente Basin, Ecuador Petrophysical rock type ● Core-based measurement of porosity, permeability and water saturation; pore characteristics from mercury-injection capillary pressure data Shenawi, et al. [2007] Formation unknown, location unknown Geological facies, Petrophysical rock types ● Facies identified using log-based definitions of shale content, lithology (density log) ● Core-based measurement of porosity, permeability and water saturation; pore characteristics from mercury-injection capillary pressure data 4 J.A. Rushing, K.E. Newsham, and T.A. Blasingame SPE 114164 Table 2 — Summary of Selected Rock Typing Studies and Definitions for Carbonate Reservoirs Reference Formation/ Location Rock Type Definitions Data Sources / Evaluation Methodologies Neo, et al. [1998]; Grotsch, et al. [1998]; Marzouk, et al.. [1998]; Al-Aruri, et al. [1998] Lower Cretaceous-age Thamama I, II, II reservoirs, offshore Abu Dhabi Depositional facies, Lithofacies, Petrophysical rock types ● Depositional environments, lithologies identified from core-based descriptions and log-based analysis ● Petrophysical properties including lithology, grain size & distribution from microscopic imaging; porosity, permeability determined from core analysis; pore structure & geometry determined from mercury-injection capillary pressure data Mathisen, et al. [2001] Upper & lower Clearfork formations, North Robertson Unit, Gaines Co., TX Lithofacies, Electrofacies ● Geological interpretations & log response to identify basic lithofacies ● Log-based descriptions based on similarity of log responses reflecting differences in mineralogy & lithofacies Lee, et al. [2002]; Perez, at al. [2003, 2005 C1a, C1b, C2a,, C2b, C3-C5 zones, Northwest Extension carbonate buildup, Salt Creek Field, Kent Co., TX Lithofacies, Electrofacies ● Identified lithofacies using core-based descriptions & microscopic imaging ● Identified electrofacies using log-based descriptions based on similarity of log responses reflecting differences in mineralogy & lithofacies Aplin, et al. [2002] Lower Cretaceous-age Thamama Group, onshore U.A.E. Lithofacies, Reservoir rock type ● Identified lithofacies using log-based similarities in micro-resistivity curves; calibrated to core-based descriptions ● Identified reservoir rock types from core-based physical descriptions, microscopic imaging; evaluated porosity, permeability from core measurements; determined pore structure & dimensions from mercurycapillary pressure data Al-Habshi, at al. [2003] Upper Zakum Formation, Field "B", onshore Abu Dhabi Lithofacies ● Identified lithofacies from geological interpretations, log and core analyses, and paragenetic sequence analysis ● Determined physical properties from core measurements; identified diagenesis from microscopic imaging; determined pore structure & dimensions from mercury-injection capillary pressure data Bieranvand [2003] Upper Cennomanian carbonate reservoir Lithofacies, reservoir rock types ● Identified lithofacies from geological interpretations and core-based physical descriptions ● Evaluated permeability & porosity from routine core analysis; quantified pore structure using mercury-injection capillary pressure data Al-Farisi, et al. [2004] Offshore Abu Dhabi carbonate Electrofacies ● Evaluated rock fabric & texture from core studies; measured permeability & porosity from routine core analysis, measured pore structure from mercuryinjection capillary pressure data ● Up scaled core-based rock types to electrofacies using log response Meyer, et al. [2004] K1-K4 intervals, Upper Khuff Formation, offshore Abu Dhabi Lithofacies, Static rock types ● Depositional environments, lithologies identified from geological interpretations, core-based descriptions and log-based analysis ● Identified static rock types based on pore types determined from microscopic imaging and mercury-injection capillary pressure data Varavur, et al. [2005] No information Lithofacies, Petrophysical rock types ● Identified lithofacies from geological interpretations and core-based physical descriptions; lithofacies defined based on depositional texture, grain-size, sorting, diagenesis ● Evaluated permeability & porosity from routine core analysis; quantified pore structure using microscopic imaging and mercury-injection capillary pressure data Rebelle, et al. [2005] Lower Kharaib formation, onshore Abu Dhabi Lithofacies, Petrophysical rock types ● Identified lithofacies from geological interpretations and core-based physical descriptions; lithofacies defined based on depositional texture, lithology, diagenesis ● Evaluated permeability & porosity from routine core analysis; quantified pore structure using mercury-injection capillary pressure data Frank, et al. [2005] Shuaiba formation, Al Shaheen Field, offshore Qatar No definitions ● Identified rock types using routine core measurements, microscopic imaging, mercury-injection capillary pressure data, NMR characteristics ● Up scaled rock types using NMR logs Creusen, et al. [2007] Natih formation, Oman Primary rock types, Rock type associations ● Primary rock types identified on pore scale using microscopic imaging as well as routine porosity & permeability measurements ● Rock type associations reflect collections of primary rock types, pore types and size distribution SPE 114164 Rock Typing — Keys to Understanding Productivity in Tight Gas Sands 5 We begin the next section with the definitions of the rock types that we propose for our reservoir description and characterization work-flow process model. We then discuss the desired data types and measurement techniques for identifying each rock type. In this discussion, we include physical and chemical phenomena which affect the sand quality and continuity. Finally, we illustrate application of the work-flow process using a field case example derived from the Bossier tight gas sand play in the East Texas Basin. Rock Type Definitions for Tight Gas Sands Although valid for most conventional oil and gas reservoirs, the rock type definition given by Archie [1950] is too general for tight gas sands since the processes resulting in similar rock properties may not be unique, especially when the rocks have been subjected to significant diagenesis. Accordingly, we integrate three rock types — depositional, petrographic, and hydraulic [Newsham and Rushing, 2001; Rushing and Newsham, 2001]. Each rock type represents different physical and chemical processes affecting the rock properties during both depositional and paragenetic cycles. We define the tight gas sand rock types as follows: ● Depositional rock types are defined within the context of the large-scale geologic framework and represent those original rock properties present at deposition. The original rock properties will vary depending on many factors, including the depositional environments, sediment source and depositional flow regimes, sand grain size and distribution, type and volume of clay deposited, etc. Depositional rock types are based principally upon core-derived descriptions of genetic units representing similar depositional energy, environments, and morphology resulting in unique rock texture, sedimentary structure, and stratigraphic sequence. Depositional rock types help us to define the geological architecture and to describe large-scale reservoir compartments. Mapping the distribution of depositional rock types should also define the extent of the reservoir "container," i.e., gas-in-place. ● Petrographic rock types are also described in the context of the geological framework established from the depositional rock types, but are based on a pore-scale microscopic imaging (i.e., thin section descriptions, x-ray diffraction analysis, and scanning electron microscopy imaging of the current pore structure [Neasham, 1977a; Davies, 1990; Pittman and Thomas, 1991]). Constituent mineral distribution, composition and habitat influence the petrographic rock type classification, so the description includes rock texture and composition, clay mineralogy, and diagenesis. Both the framework and matrix components have a "cause and effect" relationship on the diagenetic processes — resulting in preservation, loss, or enhancement of rock properties. Although there is some debate in the industry concerning the impact of the timing of hydrocarbon generation and migration into the reservoir relative to deposition (i.e., the paragenetic sequence) on reservoir quality [Bloch, et al., 2002], the petrographic rock type attempts to quantify these effects. ● Hydraulic rock types are also quantified on the pore scale but represent the physical rock flow and storage properties as controlled by the pore structure. The hydraulic rock type classification provides a physical measure of the rock flow and storage properties at current conditions — i.e., reflecting the current pore structure as modified by diagenesis. The size, geometry, and distribution of pore throats, as determined by capillary pressure measurements, control the magnitude of porosity and permeability for a given rock. High-pressure mercury-injection capillary pressure measurements may be calibrated to absolute permeability measurements [Swanson, 1981; Thompson, et al., 1987; Pittman, 1992b; Huet et al., 2005] to help develop permeability-porosity relationships. Correct identification of hydraulic rock types should allow us to develop unique permeability-porosity relationships as a function of the dominant pore throat dimensions. We note that all three rock types should be similar if the rocks have been subjected to little or no diagenesis. For example, we would expect to observe the permeability-porosity relationships for depositional rock types (derived from geologic models of the depositional environments and processes) to be applicable to petrographic and hydraulic rock types as well. However, as diagenetic effects increase in severity and occurrence, the original rock texture and composition, pore geometry, and physical rock properties will be modified. Under these conditions, we would expect to see no or very poor correlations among the permeability-porosity relationships derived for each of the different rock types. Ultimately, we would then rely upon the permeability-porosity functions developed for the hydraulic rock types since they reflect the current rock properties. Physical and Chemical Processes Controlling Tight Gas Sand Properties The low permeabilities (and porosities) associated with tight gas sands can be attributed directly to a large distribution of small to very small pores and/or a very tortuous system of pore throats connecting those pores. Further, both small pores and tortuous pore throat systems can result from several processes — including initial deposition of fine to very fine grained sediments, the presence of various types of dispersed shales and clays in the pores [Neasham, 1977b], and/or post-depositional diagenesis that alter the original pore structure. [Holland, 1982; Keighin and Sampath, 1982; Walls, 1982b; Dibble, et al., 1983; Pallatt, et al., 1984; Randolph, et al., 1984; and Luffel, et al., 1991 Therefore, successful exploitation of a tight gas sand reservoir requires a basic understanding of the rock pore structure and properties as well as the processes affecting those properties. 6 J.A. Rushing, K.E. Newsham, and T.A. Blasingame SPE 114164 Complicating any description and characterization program is the fact that not all low-permeability sandstone reservoirs are alike, so each program should be designed to address a specific reservoir or field. However, there are common physical and chemical processes controlling tight gas sand properties, so identification of these processes can help to create common elements in a particular description and characterization program. In this section, we provide an overview of basic sandstone reservoir properties and their impact on flow and storage capacities. We also discuss various physical and chemical processes and their effect on rock properties. Following Berg [1986], we divide our discussion of rock properties into two categories — i.e., primary and secondary properties. Primary properties reflect the depositional environment — energy, and sediment flow regimes, including an evaluation of sediment composition and texture as well as sedimentary structure and reservoir morphology. Secondary properties represent diagenesis — which is defined as any post-depositional process (either physical or chemical) causing changes in initial rock properties. We should note that diagenesis is very important since it is the principal cause of both low permeability and low porosity in tight gas sands. Sediment Composition. The composition of sandstone reservoirs is typically divided into three basic components — grains, matrix, and cements. Grains or framework grains refer to the larger, solid components in the rock. These components form the basic small-scale units of sandstone reservoirs. The original grain composition is controlled by the composition of the sediment source (i.e., provenance) as well as the physical and chemical processes under which the sediments are created and transported to the geologic basin. Often referred to as detrital grains, the grain composition of most sandstone reservoirs consists primarily of quartz, feldspars, and rock fragments [Berg, 1986]. Following deposition and burial, the framework grains are often altered by the physical effects of compaction as well as various chemical processes, i.e., diagenesis. We typically refer to the resulting materials as authigenic grains. We should note that knowledge of the original grain composition is important since it governs the type and severity of diagenesis. For example, some minerals are more brittle and may be more susceptible to compaction and/or failure during burial and the associated increase in stresses. Other minerals may be more reactive to natural fluids within the pores and may be altered (sometimes significantly) by adverse chemical reactions. The matrix — the second common component in a sediment — refers to the finer materials deposited between the larger grains and typically includes both clays and shales. Clays may also be classified as either detrital or authigenic. Detrital clays originate either from the sediment source material during deposition, or may form from biogenic processes shortly after deposition [Wilson, 1982]. Authigenic clays are formed by some type of chemical process, either by precipitation from formation fluids or regeneration of detrital clays. According to Wilson [1982], clay regeneration refers to "processes in which clays develop by alteration of precursor clays." The principal clay minerals observed in sandstone reservoirs are kaolinite, smectite, illite, and chlorite. Clays can vary widely in the structure or morphology of both the individual and aggregate particles. Regardless of their structure, the presence in the rock pores generally reduces both permeability and primary porosity; however, the magnitude of these reductions depends on clay type, structure and location in the pores. Wilson and Pittman [1977] have identified detrital clay morphologies commonly observed in sandstone reservoirs as laminae, clasts, grain coats, burrow fills and linings, and dispersed flakes. Wilson and Pittman also note that only the last three clay types listed appear to significantly affect rock permeability (i.e., smectite, illite, and chlorite). Similarly, Neasham [1977b] has identified three general types of dispersed authigenic clays and their impact on porosity and permeability. He has observed that discrete (not inter-grown) particles have the smallest adverse impact, while both pore-lining and pore bridging clay morphologies may significantly reduce rock permeability. All of these observations reinforce the importance of a comprehensive pore-scale program to identify clay type, origin, and the factors controlling its occurrence. The last major component common for many tight gas sands is the grain cement. The term cement typically refers to any mineral that forms during diagenesis and is precipitated after deposition of both grains and matrix components [Berg, 1986]. As the name implies, cement joins minerals together in a competent mass in the rock and fills the pore system, thus reducing both permeability and porosity. The most common cement compositions in tight gas sands are silica and carbonate. Silica is precipitated as overgrowths or layers on quartz grains. Silica overgrowth cements may form soon after deposition but often continue to develop with increased pressure and temperature during burial. Carbonate cements are often precipitated early after deposition and tend to fill pore spaces between framework grains. Authigenic clay minerals may also act as cements by helping to bind rock particles together. We should note that, although we have listed "shale" as a matrix component, it may also be classified as a principle sand component (i.e., a grain), or it may occur as a cementing material. Similar to clays, the shale structure and morphology as well as the manner in which it is distributed in the sand pores has a direct impact on rock properties. Structural shale occurs as discrete grains commonly originating from rip-up clasts (materials eroded from surrounding shale) and rock fragments that have been altered from diagenesis. Structural shale will adversely impact rock permeability and porosity if it is present in significant quantities. Laminar shale occurs as thin layers and will primarily affect the vertical permeability. Dispersed shale is defined as that material found within the (sand) pores. The origin of dispersed shale can be either as detrital material transported during the depositional process or authigenic minerals resulting from precipitates. Of all shale types, dispersed shales will most adversely affect rock permeability and porosity as it often lines or fills the pores and pore throats. SPE 114164 Rock Typing — Keys to Understanding Productivity in Tight Gas Sands 7 Sediment Texture. Important textural attributes in sandstone reservoirs include grain size, sorting, packing, shape, and grain orientation. Texture is a key component in our pore-scale description and characterization program since it not only affects initial rock properties present at deposition, but texture can also impact the rate, magnitude, and severity of diagenesis. Grain size and distribution, sorting, shape and packing also govern the type and magnitude of the original porosity present following sediment deposition, but before significant diagenesis has occurred. Generally, clean coarse-grained materials will have larger, better connected pores, while small-grained sands will have smaller and less well connected pores. Depending on the type and morphology, the presence of smaller matrix materials (i.e., clays and shale) in clean coarse-grained sands will tend to reduce both permeability and primary porosity. Grain size and sorting may also have an indirect impact on diagenesis. Stonecipher, et al. [1984] have suggested that slow movement of fluids through a low-permeability sediment promotes cementation from a higher retention of precipitates in the pore spaces, while higher flow rates result in more leaching. Consequently, we would expect shaly, fine-grained sediments (with associated low permeability) to be subjected to a higher degree of cementation than a cleaner, coarse-grained sandstone. Conversely, the original permeability in cleaner coarse-grained sands may actually increase as a result of leaching as regional fluids flow through the system. Other (minor) sandstone textural traits include grain shape and orientation. Grain shape is usually expressed as sphericity and roundness. Sphericity is defined as a measure of the grain's deviation from a spherical shape, while roundness is a measure of the roundness of the grain edges [Berg, 1986]. As an example, consider a cube-shaped object which has a high degree of sphericity but not much roundness. Both sphericity and roundness appear to be related to grain size. Grain orientation refers to the preferred direction of the grain's long axes. Neither grain shape nor orientation are measured routinely — moreover; the contribution of either property (grain shape or orientation) has not been established to any degree of certainty. Sedimentary Structure. Evaluation of sedimentary structure is an important element of the depositional rock typing process since the type of sedimentary structure may help in identifying depositional environment. Included in this evaluation is identification of bed geometry, bedding planes and contacts between beds, and bedding plane orientation. Understanding sedimentary structure is also an important component in optimizing field development activities since bed geometry and dimensions may impact both vertical and lateral continuity which would, in turn, dictate field well spacing and the type of wellbore architecture. For example, significant vertical heterogeneity may determine how effectively horizontal wellbores will recover the hydrocarbons. According to Berg [1986], sedimentary structure can be divided into primary and secondary elements. Primary sedimentary structures can be furthered divided into three quantitative and/or qualitative descriptive terms. First, sand bedding may be qualitatively described as either stratified or cross-stratified which define the bed inclination relative to the larger sand unit. Secondly, bed thickness is defined qualitatively as either thinor thick-bedded. The final descriptive term provides a qualitative indication of how parallel a bed or layer may be relative to either other adjacent layers or to larger bed structures. Primary sedimentary structures have been identified in a wide variety of depositional environments ranging from eolian to deep marine environments. Elements of secondary sedimentary structures refer to the presence and magnitude of bed or soft-sediment deformation which happens after deposition, but before lithification [Berg, 1986]. Bed deformation may be caused by physical or biological processes. Physical sand deformation is an artifact of several processes (e.g., including sliding, slumping, etc.) that tend to affect the original bedding geometry present at the time of deposition. Deformation may be described as either contorted or sheared bedding. Contorted bedding is characterized by bed folding, while sheared bedding refers to bed movement along planar surfaces. Often called bioturbation, biological sand deformation is caused by burrowing organisms or plant root growth. Burrowing organisms are often characteristic of marine shelf environments. Depending on the cause, bioturbation may also help to identify the depositional environment. Reservoir Morphology. Reservoir morphology defines the sand-body dimensions, geometry, orientation, heterogeneity, and continuity as developed by depositional and post-depositional processes. Both sand quality and quantity are controlled by primary and secondary depositional environments and processes. Quantification of the morphology helps define the reservoir architecture and compartments, and ultimately, to determine the original reservoir volume or "container." For example, the gas-in-place volumes and producing characteristics for a "blanket" sand will be much different than for a reservoir characterized by "lenticular" sands. Reservoir morphology will also affect the optimum well spacing to for field development. Depositional environment and post-depositional diagenesis both have a significant bearing on morphology, including reservoir compartmentalization and heterogeneity. Reservoir compartments refer to intervals or sections of the sand deposits that are mostly or completely isolated (i.e., not in pressure communication) from other parts of the reservoir. Compartments may be created by significant changes in the depositional environment or by post-depositional processes (i.e., diagenesis and/or tectonic activity creating sand pinch-outs, no-flow barriers, etc). Reservoir heterogeneities, which are typically manifested by lateral and vertical variability in permeability and porosity within the same sand body, are mostly caused by post-depositional diagenesis. Most diagenetic processes do not cause completely isolated reservoir compartments — but such processes may yield complex and/or poor quality flow paths, which may result in low productivity for a given reservoir system. 8 J.A. Rushing, K.E. Newsham, and T.A. Blasingame SPE 114164 Diagenesis. Diagenesis — defined as any post-depositional process causing changes in the initial rock properties — is very important since it is the principal cause of both low permeability and low porosity in tight gas sands. Diagenesis may be either a physical or a chemical process, or it might be a combination of several different types of processes. In fact, diagenesis is frequently caused by very complex interactions between the sediment minerals and pore fluids at elevated reservoir pressure and temperature conditions. Initial diagenetic events are linked directly to the prevailing local depositional environment as well as the sediment composition. Subsequent diagenesis is typically more widespread, often crossing multiple facies boundaries as a result of regional fluid migration patterns [Stonecipher and May, 1990]. The primary diagenetic processes commonly observed in tight gas sands are: mechanical and chemical compaction, cementation, mineral dissolution or leaching, and clay genesis. Mechanical compaction is caused by grain rearrangement, ductile and plastic rock deformation, and fracturing/shearing of brittle materials. Mechanical compaction may be mitigated somewhat by abnormally high pore pressures which tend to reduce stresses transferred to the grain materials. Chemical compaction refers to changes in grain size and geometry caused by chemical reactions enhanced by pressure conditions, i.e., pressure solution. Generally, both mechanical and chemical compaction will reduce both absolute permeability and primary porosity. Permeability is reduced when pore throats are partially or completed closed, while porosity is lowered from a reduction in the primary pore volume. Cementation is a chemical process in which minerals are precipitated from pore fluids and bind with existing grains and rock fragments. The most common cement compositions in tight gas sands are silica and carbonate. Silica is precipitated as overgrowths or layers on quartz grains. Silica overgrowth cements may form soon after deposition but often continue to develop with increased pressure and temperature during burial. Carbonate cements are often precipitated early after deposition and tend to fill pore spaces between framework grains. Authigenic clay minerals may also act as cements by helping to bind rock particles together. Most cements tend to reduce both permeability and porosity. However, the presence of authigenic grain coats and rims retards quartz cementation and the associated reduction in permeability and porosity by blocking potential nucleation sites for quartz overgrowths on detrital quartz grains [Bloch, et al., 2002]. We should note that authigenic grain coats and rims seem to reduce or prevent precipitation of quartz cements only, but do not affect precipitation of carbonate, sulfites, or zeolites cements [Pittman, et al., 1992a]. Another type of chemical diagenesis is mineral dissolution. A common source of quartz dissolution is pressure solution caused by stress concentrations at grain contacts which results in silica dissolution, diffusion, advection of silica for reprecipitation in adjacent pores, and an associated loss in porosity. Pressure solution processes can only occur at higher temperatures. Another type of mineral dissolution is the leaching of certain mineral grains and cements, often resulting in an increase in primary porosity and/or creation of secondary porosity. A common source of secondary porosity creation is dissolution of carbonate cements which are often precipitated early after deposition and tend to fill pore spaces between framework grains. Clay genesis refers to authigenic clays created or generated after deposition. Common authigenic clays found in tight gas sands include chlorites, mixed-layer smectite/illites, and illites. Authigenic chlorites typically develop under iron-rich conditions and commonly occur as pore lining (or coating) clays. Since these clays often do not completely cover the detrital grain surfaces, quartz overgrowths may develop on many grains, thus reducing the original primary porosity. We should note that chlorite generally has high micro-porosity between individual crystals. Smectite clays have been observed in sandstones that contain significant amounts of volcanic rock fragments. According to Wilson [1982], clay pore linings that originally consisted of smectite will be transformed to mixed-layer smectite/illite as the sands are buried deeper and the temperature increases. Continued burial may result in a complete transformation to authigenic illite clays. Illites may also form from kaolinite. In fact, illite clays develop either through precursor detrital or authigenic clays [Wilson, 1977, 1982]. Illite crystals can occur either as fibrous, sheet-like or plate structures. Illite fibers tend to break easily and accumulate in pore throats, causing a reduction or loss of permeability. Illite sheets and plates may also reduce permeability by blocking pore throats. Similar to chlorites, illite plates may have micro-porosity which could add to the total pore volume. Both reservoir pressure and temperature affect the type, magnitude and severity of diagenesis. Many diagenetic reaction rates double with each 10 Deg C increase in temperature [Wilson, 1994]. Moreover, increasing temperatures increases the solubility of minerals and causes the pore waters to become saturated, thereby increasing precipitation and formation of cements. As we have discussed previously, the primary impact of increasing reservoir pressure is mechanical compaction which tends to reduce the primary pore volume. However under some conditions, abnormally high pore pressures may also mitigate mechanical compaction by reducing applied stresses on individual grains. Data Sources and Evaluation Techniques for Rock Typing Tight Gas Sands In this section, we outline the recommended data types and measurement techniques for describing and characterizing tight gas sands using our rock typing approach — and we propose rock-type-specific programs with the goal of identifying depositional, petrographic, and hydraulic rock types. Depositional Rock Types. As we have defined previously, depositional rock types are described within the context of the large-scale geologic framework and represent those original rock properties present at deposition and before significant postdepositional diagenesis has occurred. The original rock properties will vary depending on many factors, including the depositional environments, sediment source and depositional flow regimes, sand grain size and distribution, type and volume SPE 114164 Rock Typing — Keys to Understanding Productivity in Tight Gas Sands 9 of detrital clay and shale deposited, etc. Therefore, the data acquisition and evaluation program is designed to both qualify and quantify those factors. Depositional rock types are based principally on geologic interpretations and physical descriptions of whole core. Identification of depositional rock types begins with a description of the small-scale geological reservoir architecture. These descriptions are usually derived from interpretations of the structural framework and stratigraphy. Within this framework, genetically related rock packages — both reservoir and non-reservoir rock — are identified and described. For this paper, we define genetic units as collections of rocks grouped according to similarities in composition, texture, sedimentary structure, and stratigraphic sequence as influenced by depositional environment, energy, and morphology. We may then infer the depositional flow regime as well as the dominant depositional processes controlling sand-body geometry and orientation from this description. An important aspect of this rock typing step is developing an understanding of the vertical sequencing of the genetic units. Knowledge of the vertical distribution of depositional rock types helps to define the depositional environment which then leads to a description of the reservoir geometry and flow properties. Interpretation of vertical or stratigraphic sequences also provides an understanding of the overall reservoir architecture which will then allow us to use geological concepts and models to predict locations of the deposition rock types with the best production potential. Key aspects of the sedimentary rock that may be derived from core descriptions include lithology, texture, biogenic features, and identification of sand beds and sedimentary structure. As we describe later in the section petrographic rock typing, rock lithology may include the mineralogy, composition and color, while texture comprises grain size and distribution, grain shape, rock fabric, and evidence of sorting. Identification of biogenic features, including the type, ages, mode of occurrence and trace fossils, provide clues on the depositional processes. A study of the sedimentary structure and beds will describe bed geometry, identify bedding planes and contacts between beds, and quantify bedding plane orientation. Since depositional rock types are based principally on core-derived descriptions of genetic units, comprehensive core acquisition and evaluation programs are critical for describing these rock types. It is worth noting that core data is also necessary for identifying petrographic and hydraulic rock types. We strongly recommend large-diameter, conventional whole core that should ideally be obtained throughout the entire vertical section, including both reservoir and non-reservoir rock. Complete vertical sections are used for interpreting genetic units into a depositional sequence and predicting depositional environment and architecture. Core data will also help to develop an understanding of reservoir geometry, continuity and distribution of rock types and properties. Although sidewall cores and cuttings can be used to evaluate some rock properties, their small scales make it very difficult to identify any large-scale geologic properties accurately. Consequently, we recommend using sidewall cores only to supplement a whole core program, rather than as the primary source of rock material. Petrographic Rock Types. Petrographic rock types are described on the pore-scale but within the context of the large-scale geologic framework identified from the depositional rock typing evaluation step. The primary tools used for describing petrographic rock types are microscopic imaging techniques — i.e., thin section descriptions, x-ray diffraction analysis, and scanning electron microscopy imaging. Included in these evaluations are descriptions of sediment source, rock composition and texture, mineralogy, and clay types. An important component of the petrographic rock typing is an assessment of the types of diagenesis and the potential impact on rock flow and storage capacity. We also recommend supplementing the microscopic image processes with pore geometry and other properties as identified from mercury-injection capillary pressure measurements. Thin Section Analysis. Thin section studies utilize optical techniques to identify rock texture, composition, and quality (i.e., certain aspects of the pore structure and volume). Thin sections are typically constructed of ultra-thin slices (30 microns thickness) of rock in which the pore volume is impregnated under a vacuum with a low-viscosity blue or red fluorescent epoxy resin. Most minerals will transmit light at a thickness of 30 microns, so we are able to evaluate the pore structure, framework grains, and matrix material from transmitted polarized light microscopy. In some instances, stains may be added to help with identification of specific minerals. Thin section analyses allow us to assess the rock composition including the type and quantity of framework grains, pore-filling matrix, and cementing materials. Common framework grains (i.e., quartz, feldspars, mica, etc.) can be identified and differentiated based on differences in optical properties. The composition of most common cementing minerals can also be determined providing the cement crystal sizes are greater than about 0.015 mm. Similarly, we cannot assess the composition of most clays and shales because of microscope magnification limitations. However, we can usually evaluate the relative quantity and the primary location of clays and shales in the rock pores. We can also quantify the average framework grain size as well as the distribution of grain sizes from thin section analysis. Thin section analysis also allows us to identify the types of porosity in the rocks including both primary and secondary intergranular porosity, detrital matrix porosity, micro-porosity, and grain fracture porosity. Inter-granular porosity exists as pore spaces between the rock framework grains. Micro-porosity and secondary porosity, which are often important storage components in many tight gas sands, may also be observed using an epifluorescent material and reflected light microscopy. Fracture porosity, also much smaller than inter-granular porosity, is created from micro-fractures in the rock material. 10 J.A. Rushing, K.E. Newsham, and T.A. Blasingame SPE 114164 We should note that thin section analyses provide a two-dimensional view of a three-dimensional system, so we cannot view all of the complexities in the pore structure. Another limitation is that of particle size. The standard thin section sample size is approximately 20 mm, so we cannot view any rock fragments greater than that. Limitations on the magnification capabilities of typical petrographic microscopes control our ability to identify the composition of rock fragments smaller than most clays and shales. X-Ray Diffraction Analysis. X-ray diffraction (XRD) is more of a qualitative technique that provides information on the average rock composition from a determination of the mineral atomic structure. All materials with a crystalline structure (particularly clays and shales) exhibit a unique x-ray diffraction pattern — so XRD irradiates samples with x-rays and allows us to identify rock composition from the diffracted energy characteristics. X-ray diffraction analysis is frequently used to identify the type of clays present in a rock sample. There are typically two XRD analyses required for rock samples — bulk and clay-sized particles. Bulk or whole rock x-ray diffraction analysis is conducted on the entire rock sample to identify the relative quantity of all minerals. We should note that bulk XRD analysis is accurate for mineral quantities greater than about 10 percent, but cannot accurately identify mineral volumes much less than that. The most common application of bulk XRD analysis is to identify the relative volumes of the primary framework grains, carbonates, and total clay. We should note that bulk XRD analysis is not recommended for evaluating the presence and quantity of individual clay components. Clay-sized or fine-fraction x-ray diffraction analysis is used to evaluate the fine and very fine-grained portion of the rock sample, and is the recommended technique for identifying the type and quantity of specific clay mineral components. The volume of clays present is determined from a comparison of bulk and clay-size XRD analyses. Scanning Electron Microscopy. Scanning electron microscopy (SEM) analyses are an excellent tool for evaluating the rock pore and pore-throat system, as well as the degree of connectivity among all pores. SEM can also provide information on mineralogy, clay content, and both pore-filling and pore-lining cements and clays. We may also identify natural fractures, diagenetic features, and fossil content. Rock samples are analyzed by first coating them with a conductive material and then bombarding them with electrons in a vacuum. Black and white images may be constructed from measurements of secondary electron emissions. The scanning electron microscope can magnify images at various levels up to 100,000 times. Consequently, SEM analysis is routinely used to analyze small grains and crystals, particularly clays and other very small pore filling materials. Mercury-Injection Capillary Pressure Measurements. Capillary pressure data from mercury injection is an effective technique to quantify pore geometry — particularly the size and distribution of pore bodies and throats [Purcell, 1949; Wardlaw and Taylor, 1976]. Mercury is a near-perfect non-wetting fluid phase, but it will enter the rock pores only when pressure is applied. Larger pore spaces are saturated initially, but mercury progressively invades smaller pore spaces as pressure is increased. If a sufficiently high pressure is reached, then the entire connected pore system, including even the smallest pore throats, can be completely saturated. The magnitude of the entry or displacement pressure reflects the largest connected pore throat in the system. In addition, the curvature and rate of increase of the capillary pressure data characterize the size and distribution of the pores. We may also identify bi-modal pore size distributions from the shape of the capillary pressure data. Hydraulic Rock Types. Similar to the petrographic rock typing step, hydraulic rock types are also quantified on the pore scale but represent the physical rock flow and storage properties as controlled by the pore structure. Hydraulic rock type classification provides a measure of the rock flow and storage properties at current conditions, i.e., reflecting the current pore structure as modified by diagenesis. The primary tools for identifying hydraulic rock types are routine core analysis which includes measurements of total and effective porosity, absolute permeability, and pore size and distribution from mercuryinjection capillary pressure data. Total and Effective Porosity. Porosity, which is a measure of the rock's storage capacity, is affected not only by the primary depositional processes but also by all subsequent diagenetic processes. Porosity is typically classified into two fundamental types — effective and total [Amyx, Bass and Whiting, 1960]. Effective porosity quantifies only that pore volume that is connected, while total porosity is a measure of all pore volumes, regardless of their connectivity. In conventional sandstone reservoirs with little or no diagenesis, effective porosity is often slightly less than total porosity. However, effective porosity in tight gas sands is typically much lower than the total porosity because of diagenesis. The type and magnitude of diagenesis governs the connectivity of the primary porosity. Unlike conventional sandstone reservoirs that are characterized mostly by a primary inter-granular porosity system, tight gas sands may exhibit several other types of porosity — including both primary and secondary inter-granular porosity, detrital matrix porosity, micro-porosity, and grain fracture porosity. Inter-granular porosity exists as pore spaces between the rock framework grains — micro-porosity (which is typically associated with clays and shales), is usually much smaller than intergranular porosity. Unfortunately, we cannot uniquely distinguish among various porosity types or quantify these porosity types directly with physical measurements — we can, however, use microscopic imaging to estimate relative percentages. There are several laboratory methods to measure effective porosity in tight gas sands. Common to all techniques are measurement of two of the three volumes associated with porosity calculations, i.e., bulk (Vb), matrix or grain (Vm), and pore (Vp) volumes [Amyx, Bass and Whiting, 1960. Porosity, written in terms of these three volumes, is: SPE 114164 Rock Typing — Keys to Understanding Productivity in Tight Gas Sands 11