SPECIAL CORE ANALYSIS
  Special Core Analysis involves tests that are supplementary to the basic core analysis program. Special core analysis results are used not only in calculating water saturation from open hole logs, but also in modeling the distribution of connate water saturation in the reservoir and the displacement of oil by either gas or water. Among the laboratory measurements required are primary drainage and primary imbibition capillary pressure, and gas-oil and water-oil relative permeability.
 
 
 
  Recommended SCAL DATA for Typical Reservoirs  
 
TEST DATA 1 2 3 4 5 6 7
Capillary Pressure
Formation Resistivity Factor
Resistivity Index
Cation Exchange Capacity
Acoustic Velocity
Water Permeability
Gas-Oil Relative Permeability      
Water Flood Test (Basic,WFS, or Kw/Ko)            
Gas-Water Relative Permeability            
Overburden Permeability and Porosity
Pore Volume Compressibility        
Sieve Analysis (Poorly Consolidated Rock)  
X-Ray (Clay Identification)
Scanning Electric Microscope
Residual Gas After Water Drive            
Wettability            
Formation-Injection Water Compatibility            
Reservoir Mechanism 1 2 3 4 5 6 7
  		 
 
Legend		  
 
1 Gas Drive
2 Gas Cap Expansion
3 Water Drive Oil
4 Undersaturated Oil
5 Gas and Gas Condensate
6 Low Permeability Gas
7 Water Drive Gas
Major Test Required
Other Tests
 
     
 
 
  • Capillary Pressure
  
  Capillary pressure results from interaction of force acting within and between fluids and their bounding solids. These include both cohesive forces (surface and interfacial tension) and adhesive (liquid-solid) forces. In hydrocarbon reservoirs, this applies to oil and water distributed in the pores of the reservoir rock. Capillarity controls the static distribution of fluids in the reservoir prior to production and remaining hydrocarbons after primary production. Laboratory cappilary pressure curves are used to define initial water saturation as a function of height above-water contact.
A number of applications of capillary pressure concept as follows: 		 
  » Reservoir rock quality  
  » Pay versus non pay  
  » Expected fluid saturation  
  » Seal capacity  
  » Depth of the reservoir fluid contacts  
  » Thickness of the transition zone  
  » An approximation of the recovery efficiency during primary or secondary recovery  
  » Calculation of relative permeability in the absenceof measured data  
  Capillary pressures in porous materials is estimated by using mercury injection porosimetry technique. The method consists of injecting mercury at increasing pressure into a sample which has been previously evacuated; this process is known as primary drainage (the "wetting" phase is the vacuum). Recording mercury pressures and saturations alows generation of a capillary pressure-saturation curve. By next lowering the pressure in stages, an imbibition process can be simulated and the equivalent capillary pressure can be generated. A second series of pressure increases will simulate a secondary or re-drainage process; again a capillary pressure curve can be plotted. The end saturation for the primary drainage process gives an estimation of the primary drainage and the imbibition processes gives an indication of the recovery efficiency for the hydrocarbon in a reservoir (again assuming the reservoir to be water wet).  
  Mercury injection porosimetry data are used to determine pore size distributions of core samples. By using suitable scaling parameters, oil/brine capillary pressure curves may also be deducted from mercury injection capillary pressure curves. We can measure mercury injection capillary pressure curves and infer pore size distribution data.  
 
Three methods in evaluating capillary pressure:
» Mercury Injection (to 60,000 psia)
» Centrifuge (Standard & High Speed)
» Porous-Plate (at confining pressure)
   
 
 
  Capilary Pressure can also be measured by centrifuge in this method, Capillary Pressure is calculated by saturationing core with water (or oil) and spin under air or oil at increasing speed. The water or oil displaced from sample was measured volume trically using a stroboscope at equilibrium condition.  
   
  The Instrument is designed for the testing at reservoir pressure and temperature. The CCD camera system measures the displaced fluid volume automatically. The Instrument is provided with computer control and data collection and capillary pressure data reduction program  
 
 
  • Relative Permeability Measurements  
  Relative permeability is a direct measure of the ability of the porous system to conduct one fluid when one or more other fluids are present. Relative permeability is defined as the ratio of the effective permeability at the given fluid saturstion to the absolute permeability at 100 percent fluid saturation. Temperature, flow velocity, saturation history, wettability changes and the mechanical and chemical behaviour of the matrix material may all play roles in changing the functional dependence of the relative permeability on saturation. The best defined of these dependences is the variation of relative permeability with saturation history; relative permeability curves show hysteresis between drainage processes (wetting phase decreasing) and imbibition processes (wetting phase increasing).
There are two basic methods of obtaining relative permeability data : steady state and unsteady state. For the steady state method and a two fluid system, the two phases are injected at a certain volumetric ratio until both the pressure drop across the core, and the composition of the effluent, stabilize. The saturations of the two fluids in the core are then determined, typically by weighing the core or by performing a mass balance calculations for each phase. The relative permeability is calculated from the flow equations.
These data are used to evaluate formation sensitivity to water used for drilling, coring, ==== and injection permeability reduction may be due to clay particle migration or clay ====.
In order to enlarge the pore spaces and there by increase the Permeability, Acids can be injected into the formalin under high pressure. After treatment, The acids are pumped and the well swabbed and the returned to production. = evaluate the effectiveness of a purposed acid treatment, Laboratory flow studies can be performed on core simples == the ===. The rest condition closely resamble actual ==== hole pressures and temperatures for the well being considered for treatment. In addition, the effect of various acid stimultation ddivis can be studied.		  
 
 
  • Wettability Test  
  Wettability has been recognized as one of the most important parameters for a reservoir. It is measure of the preference the rock exhibits for either oil or water in a rock-oil-brine system. Wettability is the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. The only scientifically proper method of measuring wettability is to obtain a contact angle between the two fluids and the rock. If the contact angle measured through a fluid is less than 90o, a neutrally wet situation is said to exist. However, direct measurements are rarely pratical with actually reservoir materials. Actual reservoir materials are sometimes approximated by "pure" smooth surfaces : glass (silica) for sandstones or calcite crystals for carbonates. When two immiscible fluids are in contact, due to the interfacial tension forces, the interface will be curved with higher pressure on the concave side than on the convex side.  
  » Amott Procedure
» USBM 		 
 
 
  • Formation Resistivity Measurement  
  These measurements define parameters (a, m, and n) required in downhole electric log calculation of water saturation. Three types of tests that commonly performed are:  
  » Formation Factor
» Resistivity Index
» Cation Exchange Capacity
  
  Formation factor is defined as the ratio of the resistivity of the 100 percent brine-saturated core to resistivity of the saturating brine. It is also a function of porosity and the pore geometry of the rock (F=1/phi^m). Core plugs selected for this test, are evacuated and pressure-saturated with simulation formation brine. Formation factor data is determined at ambient conditions for 100 percent brine saturated samples. However, a reservoir condition, at specific both temperature and net overburden pressure can be simulated.

Resistivity Index is defined as the ratio of rock resistivity at any condition of gas, oil, and water saturation to its resistivity when completely saturated with water. It is also a function of water saturation and the pore geometry (I=Rt/Ro=1/Sw^n). It is determined at various equilibrium saturation obtained during the capillary pressure determination using simulated formation brine as saturating fluid. In this process, the samples are desaturated using semipermeable cell and equilibrium brine saturations are determined at preselected pressure. Then resistivity of the partially saturation samples is determined. The visual best fit line is drawn through the data points. The slope of theis line relating saturation and resistivity index yield saturation exponent "n".

The clay mineral presents in a natural rock act as separate conductor and are sometimes referred to as conductive solids. The conductivity of clay is related to the cation exchange capacity (CEC). The higher the CEC, the lower the formation factor at any salinity. CEC is determined on formation sample and varies with the type and quantity of clay. This ion exchange may alter formation porosity, reduce permeability, reduce formation resistivity and result in erroneously high-calculated water saturation from downhole logs. The CEC can be determined by the following methods:

» Conductometric Titration
» Ammonium Acetate Titration
» Methylene Blue Titration
  
     
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