Clay Mineralogy

 

Clay minerals are hydrous aluminium silicates, sometimes with variable amounts of iron, magnesium, alkali metals, alkaline earths, and other cations.

 

Clays form flat hexagonal sheets similar to the micas. Clay minerals are common weathering products (including weathering of feldspar) and low temperature hydrothermal alteration products.

Clay-rich shales has been usually called “shales” while non-clay shales have been called “silts”. Petrophysical analysis deals with minerals, not particle size, so it is confusing when a zone is geologically described to be shale when the logs show little clay is present.

Clay minerals include the following groups :

1.   Kaolin group which includes the minerals kaolinite, dickite, halloysite, and nacrite (polymorphs of Al₂Si₂O₅(OH)₄). Some sources include the kaolinite-serpentine group due to structural similarities. Usually occurs in the pore system as discrete particles, which do not attach securely to sand grains, so when become dislodged they clog the pore throats.  

 

 

 2.   Smectite group which includes dioctahedral smectites such as montmorillonite and nontronite and trioctahedral smectites for example saponite.

If in contact with water it swells by retaining a good amount of water between layers, plugging the pore throats.

 

 3. Illite group which includes the clay-micas. Illite is the only common mineral.

4. Chlorite group includes a wide variety of similar minerals with considerable chemical variation. Usually occurs as a pore lining around individual sand grains or in clusters.

CLAY TYPES

 

One 

One of the most controversial problems in formation evaluation is the shale effect in reservoir rocks. An accurate determination of formation porosity and fluid saturation is subjected to many uncertain parameters, all are induced by the existence of shale in pay formation.

Aside from shale effects on porosity and permeability, the electrical properties of reservoir rocks, consequently their fluid saturation are sensitively affected by the existence of shale. The way shaliness affects log responses depends on the proportion of shale, the physical properties of shale, and the way it is distributed in the host layer. 

Shaly material can be distributed in the host layer in three ways : 

-   Laminar: Thin streaks of clay deposited between units of reservoir rock. They do not change the effective porosity, the water saturation or the horizontal permeability of the reservoir layer, but destroy vertical permeability between reservoir layers. 

 -  Structural: clay particles constitute part of the rock matrix, and are distributed within it. It has similar general properties to laminar clays, as they have been subjected to the same constraints. However, they behave more like dispersed clays in respect of their permeability and resistivity properties.

-   Dispersed: clay in the open spaces between the grains of the clastic matrix. The permeability is significantly reduced because clays occupy the pore space and the water wetness of clays is generally higher than that of quartz. The result is an increased water saturation and a decreased fluid mobility.

 There are two types of shale:

-   Effective shale ( montmorillonite and bentonite ) : has significant CEC (cation exchangecapacities), and can be identified by most of the shale indicator tools.

-     Passive shale ( kaolinite and chlorite) : has essentially zero CEC, and recognized only by neutron tool.

Shale is a fine-grained, clastic sedimentary rock composed of mud that is a mix of flakes of    clay minerals and tiny fragments (silt-sized particles) of other minerals, especially quartz and  calcite. The ratio of clay to other minerals is variable. 

 

Shale is characterized by breaks along thin laminae or parallel layering or bedding less than one centimeter in thickness, called fissility. Mudstones, on the other hand, are similar in composition but do not show the fissility.

 

 

 

 

Sedimentary Rocks in the Production of Hydrocarbons

 

There are five types of sedimentary rocks that are important in the production of hydrocarbons:

Sandstones 

Sandstones are clastic sedimentary rocks composed of mainly sand size particles or grains set in a matrix of silt or clay and more or less firmly united by a cementing material (commonly silica, iron oxide, or calcium carbonate).

The sand particles usually consist of quartz, and the term “sandstone”, when used without qualification, indicates a rock containing about 85-90% quartz.

Carbonates, broken into two categories, limestones and dolomites.

Carbonates are sediments formed by a mineral compound characterized by a fundamental anionic structure of CO3^-2. 

-      Calcite and aragonite CaCO3, are examples of carbonates.

-  Limestones are sedimentary rocks consisting chiefly of the mineral calcite (calcium carbonate, CaCO3), with or without magnesium carbonate. Limestones are the most important and widely distributed of the carbonate rocks.

-    Dolomite is a common rock forming mineral with the formula CaMg(CO3)2. A sedimentary rock will be named dolomite if that rock is composed of more than 90% mineral dolomite and less than 10% mineral calcite.

Shales

Shale is a type of detrital sedimentary rock formed by the consolidation of fine-grained material including clay, mud, and silt and have a layered or stratified structure parallel to bedding. Shales are typically porous and contain hydrocarbons but generally exhibit no permeability. Therefore, they typically do not form reservoirs but do make excellent cap rocks. If a shale is fractured, it would have the potential to be a reservoir.

Evaporites

Evaporites do not form reservoirs like limestone and sandstone, but are very important to petroleum exploration because they make excellent cap rocks and generate traps. The term “evaporite” is used for all deposits, such as salt deposits, that are composed of minerals that precipitated from saline solutions concentrated by evaporation. On evaporation the general sequence of precipitation is: calcite, gypsum or anhydrite, halite, and finally bittern salts.

Evaporites make excellent cap rocks because they are impermeable and, unlike lithified shales, they deform plastically, not by fracturing.

The formation of salt structures can produce several different types of traps. One type is created by the folding and faulting associated with the lateral and upward movement of salt through overlying sediments. Salt overhangs create another type of trapping mechanism.

 

 

Defining Flow Units and Container

 

Introduction

To understand reservoir rock–fluid interaction and to predict performance, reservoir systems can be subdivided into flow units and containers. Wellbore hydrocarbon inflow rate is a function of the pore throat size, pore geometry, number, and location of the various flow units exposed to the wellbore , the fluid properties, and the pressure differential between the flow units and the wellbore. 

Reservoir performance is a function of the number, quality, geometry, and location of containers within a reservoir system, drive mechanism, and fluid properties. When performance does not match predictions, many variables could be responsible , however, the number, quality, and location of containers is often incorrect.

What is a flow unit?

A flow unites a reservoir subdivision defined on the basis of similar pore type. Petrophysical characteristics, such as distinctive log character and/or porosity–permeability relationships, define individual flow units. Inflow performance for a flow unit can be predicted from its inferred pore system properties, such as pore type and geometry. They help us correlate and map containers and ultimately help predict reservoir performance.  

What is a container?

A container is a reservoir system subdivision consisting of a pore system, made up of one or more flow units, that responds as a unit when fluid is withdrawn. Containers are defined by correlating flow units between wells. Boundaries between containers are where flow diverges within a flow unit shared by two containers . They define and map reservoir geology to help us predict reservoir performance.

Defining flow units

To delineate reservoir flow units, subdivide the wellbore into intervals of uniform petrophysical characteristics using one or more of the following:

• Well log curve character

• Water saturation (SW–depth plots)

• Capillary pressure data (type curves)

 • Porosity–permeability cross plots

 

The diagram below shows how flow units are differentiated on the basis of the parameters listed above.

Procedure: Defining containers:

Defining containers within a reservoir system is relative to the flow quality of the rock. Flow units with the largest connected pore throats dominate flow within a reservoir system. Follow the steps listed in the table below as a method for defining containers.
·         Correlate flow units between wells in strike and dip-oriented structural and stratigraphic cross sections.
·         Identify the high-quality flow units from rock and log data.
·         Draw boundaries between containers by identifying flow barriers or by interpreting where flow lines diverge within flow units common to both containers.