Reservoir Characteristics and Petroleum

It is note quite sufficient   to say that to be  a reservoir , a rock requires porosity  and permeability . Reservoir behavior relative to oil  and gas accumulation and production certainly involves  porosity and permeability , but its performance is based  upon several  important engineering  factors . 

Porosity : 

Porosity represents the amount of void space in a rock and is measured as a percentage of the rock  volume. Connected  porosity where void space  has flow-through potential is called effective porosity .

Noneffective porosity is isolated .Summation of effective and noneffective  porosity produces  total porosity , which  represents all of the void space  in a rock . 

Pore space in rocks at the time of deposition  is original , or primary porosity . It is usually a function  of the amount of space between rock -forming grains . Original porosity is reduced by compaction and groundwater -related diagenetic processes .

Grownd water solution , recrystallization , and fracturing cause secondary porosity , which develops after sediments are deposited . 

Effective , noneffective , and total porosity

 

Permeability : 

A rock that contains connected porosity and allows the passage of fluids through it is permeable .Some rocks are more permeable than others because their intergranular  porosity , or fracture porosity , allows fluids to pass through them easily .

Permeability is measured in darcies . A rock that has a permeability  of 1 Darcy permits 1 cc of fluid with a viscosity  of  1 centipoise (viscosity  of water  at 68⁰ F) to flow through one square centimeter of its surface for a distance of 1 centimeter in 1 second with  a pressure drop of 14.7 pounds per sequare inch . 

Permeability is usually expressed in millidarcies since few rocks have a permeability of 1 Darcy . Intergranular material  in a rock , such as clay  minerals or cement , can reduce permeability and diminish  its reservoir potential . It is evident , however that mineral grains must  be cemented to some degree to form coherent rock and that permeability will reduce to some extent in the process . 

Fluid flow through Permeable Sand 

 

Clay cement and porosity and permeability 

Relative Permeability : 

When water , oil , and gas are flowing through  permeable reservoirs , their rates of flow will be altered by the presence  of the other fluids . One  of the fluids will flow through a rock at  a certain rate by itself . However , in the presence of one or both of the other fluids , its rate of flow can be changed .

The flow rate of each fluid is affected by the amounts of the other fluids , how they reduce pore space , and to what extent they saturate the rock. Comparison of the flow rate of a single fluid through a rock its that same flow rate , at the same pressure drop , in the presence of another  fluid determines the relative permeability of the system .

When rock pores decrease in size , the surface tension of fluids in the rock increases . 

If there are several fluids in the rock , each has a different surface tension , which exercises a pressure variation between them .This pressure is called capillary pressure and is often sufficient to prevent the flow of one fluid in the pressure of another .    

Relative permeability From Clark , 1969. Copyright 1969, SPE-AIME

 

Core Analysis

Objective :

The  objective of every coring operation is to gather information that leads to more efficient oil or gas production . 

some specific tasks might include the :

Geological objectives : 

• Geologic maps 
• Fracture orientation 
• Lithological information  :

• Rock type
• Depositional environment  
• Pore type  
• Mineralogy/ Geochemistry  

  Petrophysical  and reservoir engineering :

• Capillary pressure data  
• Permeability information :  

• Permeability / Porosity  correlation 
• Relative Permeability

•  Data for refining log calculations :

• Electrical properties 

• Grain density

• Core Gamma Log 

• Mineralogy and cation exchange capacity   

• Enhanced oil recovery studies
• Reserve estimate : 

• Porosity

• Fluid saturations

 Drilling and completions : 

• Fluid/ formation compatibility studies 
• Grain size  data for gravel pack design 
• Rock mechanics data 

 Why Core Analysis is important for Development Plan ? 

 Exploration :

• Exploration of structures  and determination of their physical  characteristics. 

•  Estimate of production  possibilities  for wildcats, extension wells  and edge wells .

Well completion and workover operations : 

• Selection of intervals for testing . 

• Interpretation of tests during drilling -Comparison results -Explanation of test anomalies etc.  

• Determination of the best combinations for order of completions when there are several horizons . 

• Selection of intervals and choice of depths if plugs , packers , cement plugs  etc.  are installed to keep out water and gas influxes . 

• Selection of intervals for perforations or acidizing . 

• Estimation of completion efficiency . 

• Selection of intervals for recompletion . 

Field Development : 

• Determination of optimal spacing . 

• Determination of the location  of new wells . 

• Definition of field boundaries . 

• Estimate of production for determination of field equipment . 

• Definition of contact zones for the various fluids . 

• Structural  and stratigraphic correlations . 

• Sampling and bases of interpretation for other well logging . 

• Selection of intervals for optimum completion . 

Well and reservoir evaluation :

• Determination of net pay zone . 

• Estimate of initial productivity 

• Estimate of water production rates and injection pressures . 

• Estimate of decompression zones invaded bay water or gas , and simultaneous  production of various  zones . 

• Estimate of probable recovery . 

• Estimate of oil or gas  reserves in place . 

• Estimates for equitable shares in unitization operations . 

• Reservoir engineering and programming for maintaining pressure or secondary recovery . 

• Forecasts for optimum well completion and maximum future recovery .  

 

 Core Analysis Tests : 

The  experiments done on core sample are as following :

• Routine Test
• special test
• Geo-mechanics tests 
• Formation damage tests

1. Routine Test : 

• Porosity measurements 
• Permeability measurements
• Saturation's measurements 
• Grain density 

These measurements are made to correct the well logs results and use this correction in non-cored  intervals , as example :

• Tyne the Archie's equation  constants (a, m ,n) until having matching to core saturation.
• Get a correlation between porosity and permeability .
• Rock Typing .

2. Special Test : 

•  Relative permeability : used for multiphase modelling in case of having saturation less than 100 % .

• Capillary pressure : used to determine the thickness of transition zone and the saturation distribution in this interval .

• Wettability : used a criteria in EOR applications screening .

• Rock compressibility : used especially for material balance calculations to estimate oil recovery and also in geomechanically applications . 

• Acoustic properties : used to tune the Archie's equation constants to estimate the saturation and porosity from ell logs.

• Other tests like XRD  and SEM . 

3. Geomechanics Test : 

Geomechanics has an important role to play in assessing formation integrity during well construction and completion and in the response of the reservoir  to oil production , water injection and depletion .
The tests most commonly used to determine  fundamental rock mechanics parameters are described including : 

• Unconfined compressive strength 

• Thick Wall Cylinder .

• Tensile Strength.

• Triaxial Tests .

• Pore Volume Compressibility .

• Elastic Moduli.

• Particle Size Analysis . 

Application of Core Analysis Data: 

 

• Permeability Modelling .  

• Facies distribution modelling .

• Production prediction . 

• Residual Oil Saturation targeted by EOR . 

•  STOIP calculation . 

•  Sand control . 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   

Introduction to the Petroleum Industry

The oil and Gas Industry is divided into 3 categories : 

•  Upstream
• Midstream
• Downstream 

 

What does Upstream , Midstream and Downstream mean in the oil Industry ? 

Upstream Oil and Gas : 

is E&P (Exploration and Production ) , involves the drilling off exploration wells and drilling into established wells to recover oil and gas .

• Exploration 
• Field Development 
• Production Operation 

 

Midstream : 

involves  the transportation , storage , and processing of oil and gas . Once resources  are recovered , it has to be transported to a refinery , which is often in completely different geographic region compared to the oil and gas reserves . Transportation can include anything from tanker ships to pipelines and trucking fleets .

• Transportation 
• Storage  and distribution 

 

Downstream : 

Refers to the filtering of the raw materials obtained  during the upstream phase . The marketing and commercial distribution  of these products to consumers and end users in a number of forms including natural gas , diesel oil , petrol , gasoline , lubricants  , kerosene , jet fuel , asphalt , heating oil , LPG ( Liquefied Petroleum Gas ) as well as a number of other types of petrochemicals .

• Refining 
• Marketing              

 

 

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.