Use of geologic model data in reservoir simulation

 

Use of geologic model data in reservoir simulation
Property	Use in Simulation	Status
Structure top	Reservoir depth       Initial reservoir pressure       Original oil in place (OOIP ) and original   gas in place (OGIP) calculations	Required for top layer
Net reservoir thikness,hn	Assignment of cell net thikness values       Horizontal –transmissibility calculations      Pore volume calculations      Calculation of well geometric factors, Gw       OOIP and OGIP calculations	Required
Gross reservoir thikness, hg	Assignment of cell gross thikness values       Gravity head calculations        Initial reservoir pressures Transition-zone calculations. Initial saturation distributions. Vertical-transmissibility calculations	Optional (default may be obtained from net thikness)
Net-to-gross ratio	Assignment to cell hn/hg values	Optional (default may equal 1, hn/hg =1 )
Porosity	Assignment of cell Ⴔ values     Development of porosity /permeability transforms.     Pore volume (PV) calculations.     OOIP and OGIP calculations.	Required for all layers
Horizontal permeability	Assignment of cell permeability values     Horizontal –transmissibility calculations.     Development of porosity /permeability transforms.     Calculation of well geometric factors , Gw  .	Required for all layers
Vertical permeability	Assignment of cell permeability values.     Vertical –transmissibility calculations.	Optional (default may  be obtained from Kv /kh=1)
Initial saturations	Initial saturations distributions.     Transition –zone heights.     OOIP and OGIP calculations.	Optional (default may be obtained from Pc data )
End point saturations	Saturation normalization.     Assignment of cell critical saturation values for saturatioun normalization.	Optional (default may be obtained from kr curves )
Fluid Contacts	OOIP and OGIP calculations.     Initial saturation distributions.     Initial reservoir pressures.	Required

Reservoir Challenges VS Solutions

 

Challenges	Solutions
ü Reservoir Heterogeneity :           -   Lateral and vertical facies changes     -    Depositionnel environnements modelling.	Reservoirs Characterization using integrated seismic interpretation, inversion, geologic modelling with sedimentological studies.
ü  Structure Complexity -    Structural pattern is very complex, especially in the deeper Paleozoic section. -          Multi tectonic phases. -          Seismic data mask by multiples.	Ø  Overcome by sophisticated structural seismic attributes (faults likelihood as example) to detect most of faults trends. Ø  Understanding the geologic and structure setting. Ø  Structure restoration.
ü  Defining potential blocks. ü  Defining the reservoir quality.	Ø  Integrating structural interpretation with seismic attributes, available petrophysical and Engineering data.
ü  Compartimentalization	Ø  Optimized structural configuration. Ø  PVT @Pressure Analysis. Ø  Fault seal Analysis.
ü  Low resistivity pays	Ø  Conductivity of clay and minerals. Ø  Micro porosity and high irreducible water saturation. Ø  Deep invasion of high salinity filtrate.

The Exploration Cycle

 There are  three   basic phases  of prospecting  in which various  mapping techniques  and methods are required . 

1. The first  is  the initial exploration phase of  a property . Generally , few , if any wells have been  drilled  on or near  the prospect  and therefore , prospect evaluation  relies on seismic data , limited well control , a good  geologic concept  , and  comparaison   or analogies  to nearby  properties .For exploration  purposes  the emphasis may be  on defining  major sand units , locating the larger potential fault  traps , and preparing  regional  subsurface maps . 

         The aim of this work is to identify  undiscovered  economic hydrocarbon accumulations .

1. The second phase of prospecting  ocurs after  a field has been  discovered  and several  wells have been drilled . Continously accumulated well log , core , seismic , and performance  data are used  to fully develop  the field  and obtain a good  estimate of  the volume  of recoverable  hydrocarbons . 

In these newly  discovered fields , the geologic study may include  the mapping  of all recognized  faults  , the preparation  of structure , contour maps , interval  isopach maps , and net sand  and net pay isopach maps  for all known  hydrocarbon bearing  reservoirs , in addition  to a variety  of cross sections . These maps and cross sections  may be used  to estimate reserves , justify  additional  development  drilling , or establish  a field depletion plan . 

1. The third  and final phase of prospecting  occurs in maturely  developed properties . With increasing amounts  of log  and performance  data , volumetrics are compared to performance  to refine the geological  maps and ultimate  reserve estimates .

  All  the geologic , geophysical , and engineering  information  is used  to help identify  any            hydrocarbons  that remain . In any   integrated study  being conducted in a mature  area  with the   purpose of identifying  economic reserves  not capable   of being  recovered  by existing                producing    wells , to identify  additional  potential overlooked  in previous studies or to plan     secondary  or  enhanced  recovery projects .

The most detailed maps  are required , as well as the analysis of  reservoir  performance  data .  This detailed  work requires   a team  effort  consisting  of team  members  experienced in      various  disciplines , including geology , gophysics , and petroleum  engineering .It is during this  final phase  of prospecting  that many companies have  failed to recognize  and approve the kind of integrated , detailed interdisciplinary  work required to find all  the remaining oil and gas . 

Exploration : 

Exploration's  mission is to acquire access to new petroleum resources .

• Identifies and evaluates new areas 
• Acquires rights to explore 
• Identifies leads 
• Matures leads to propects 
• Selects prospects for drilling 
• Drills wildcats and appraisals 
• Shares evaluation with Development on development . 

Lead & Prospect : 

Lead	Prospect
Suggests the potential for a wildcat location	Sufficiently defined to be drilled
Substantial uncertainty remains in the potential size and chance of success	Uncertainty remains in the potential size and chance of success
Key elements of the petroleum system may not be supported by any hard data	Major elements of the petroleum system are defined

https://www.geo-skill.com/2020/08/geological-considerations-and-types-of.html

 

Abnormal Hydrostatic Pressure

Abnormal hydrostatic pressure is a departure from normal fluid pressure that is caused by geologic factors. The term “geopressure” was introduced originally by Shell Oil Company to refer to overpressured intervals in the U.S. Gulf Coast. “Geopressure” is gradually being replaced by the more descriptive terms  “overpressure” and “underpressure.”

Causes : 

Abnormal fluid pressure may be caused by any of the following : 

• Uplift 
• Burial 
• Rock compaction  or dilation 
• Abnormal heat flow 

Abnormal pressures develop when fluid is unable to move into or out of the local pore  system  fast enough  to accommodate  to be new environment .Such a pore system must be isolated from the surrounding  system  by impermeable barriers  for abnormal pressure to exist . 

The table below shows the generally accepted major causes of abnormal fluid pressure . 

    

Overpressure	Underpressure
Uplift	Burial
Heat increase	Heat decrease
Compaction of hydrocarbons	Dilation of pores

 

 Multiple simultaneous  causes : 

More than one mechanism  may operate  simultaneously  or sequentially to create abnormal pressure. For example , burial of a sealed  compartment  carries a trapped fluid  pressure into  a deeper environment .The  pressure in the compartment  compared  with the surrounding  environment  would  slowly raise the pressure in the compartment to normal .

It may not be possible to predict  the existing condition  of the pressure system in examples like this because  the combined effects of all the variables are often  not well known in advance . 

1. Causes of Overpressure : 

When a  fluid pressure is higher than estimated from the normal hydrostatic  fluid gradient  for  a given depth , it is called  overpressure .For this situation to occur , the fluid must  first be trapped within a rock unit (pressure compartment ) ;

Overpressure  can be caused by uplift , increased heat , compaction , generation of hydrocarbons , or  a combination of these factors .

Uplift : 

A unit can be uplifted into  a regime of lower normal pressure .The encapsulated fluid then is at a pressure higher  than that  found  at the new depth in surrounding formations where the fluid is under normal constraints .

The diagrams below illustrate this situation .  

Heat increase: 

Perhaps the most common way that pressure is increased is for the encapsulated fluid to be heated .The trapped fluid , unable to expand into adjacent pore systems , rises in pressure. Fluids outside  the area of trapping are free to adjust to the heating , so they remain at about normal pressure .

Compaction : 

As an  encapsulated rock mass is buried , it tends to compact .Under  normal conditions , as the porosity is reduced  , the interstitial fluid is expelled. When  the fluid cannot escape , the pressure within the encapsulated  rock mass risks .The higher fluid pressure  takes on some of the overburden load , limiting  the amount  of compaction .In such cases , the fluid is overpressured  and the rock matrix is undercompacted .

2. Causes of Underpressure :

Under pressure exists when a fluid pressure is lower than estimated from the normal hydrostatic  fluid gradient  for that depth at which it occurs .For this situation to exist , the fluid must be trapped within a rock unit .

Underpressure can be caused by burial or heat decrease .

Burial : 

If the encapsulated unit is buried deeper , its original pressure is carried to  a higher  pressure environment .If the rock  cannot compact , the trapped pressure is abnormally  low for the new depth .As long as a rock unit remains encapsulated  by impermeable rocks , it becomes underpressured by burial as faulting or as downwarp occurs .

The diagram below illustrate this phenomenon .

Heat decrease : 

The major factor causing underpressure is the cooling of pore fluids as they are uplifted and the overburden erodes .For example , drain a bottle filled with hot water and immediately seal the bottle back up by screwing  on the cap .The bottle  will be underpressured  as it cools to room temperature .This same phenomenon  occurs  when an encapsulated rock unit is uplifted  into a region of lower temperature .However , predicting pressure in uplifted rock unit is difficult .Because uplift brings a rock unit from a region of high pressure  to a region  of low pressure, the uplifted unit may be at a higher -than-expected pressure , a lower -than-expected pressure , or normal pressure , depending on the state of equilibration . 

Pressure Regimes

Oil and gas are fluids. Pressure is one the main elements characterizing the physical behavior of fluids in the subsurface. Understanding pressure concepts and their applications is critical to effective petroleum exploration. This section discusses different pressure regimes, mainly concentrating on formation fluid pressures.it also discusses the characteristics and behavior of fluids (liquids and gases) and how an understanding of fluid pressure can be applied to oil and gas exploration.

Pressure is a measure of force per unit area. Pressure in the subsurface is a function of the densities of rocks and fluids. 

1. Normal Hydrostatic Pressure:

Fluids  :  Afluid is “a substance (as a liquid or gas) tending to flow or conform to the outline of its container” (Webster, 1991). Thus, the explorationist should think of oil, gas, and water as fluids to understand their behavior in the subsurface. 

Fluid pressure : is that pressure exerted at a given point in a body of fluid.

Hydrostatic pressure:   Normal hydrostatic pressure is the sum of the accumulated weight of a column of water that rises uninterrupted directly to the surface of the earth. Normally pressured fluids have a great degree of continuity in the subsurface through interconnected pore systems. 

Abnormally pressured fluids can occur where fluids are completely isolated in containers (compartments) that are sealed on all sides.

Hydrostatic mud pressure :  The geological definition of “hydrostatic” differs from the engineering definition. Engineers use “hydrostatic” to refer to the pressure exerted by the mud column in a borehole at a given depth. Hydrostatic mud pressures are found on DST (drill-stem test) reports and on scout ticket reports of DSTs.

Properties of hydrostatic pressure :  

Normal hydrostatic pressure has the following properties (Dahlberg, 1994): 

        •  Amount of pressure increases with depth. 

        •  Rate of pressure change depends only on water density. 

        •  Vector representing the direction of maximum rate of pressure increase is vertical (i.e., the fluid is not flowing laterally). 

        •  The pressure–depth relationship is completely independent of the shape of the fluid container.

Static vs. dynamic fluid : 

Fluid pressure is nondirectional if the fluid is static. If a pressure imbalance exists in any direction, the fluid moves in the direction of lower fluid pressure. The diagrams below illustrate balanced and unbalanced pressures.

2. Geostatic and Lithostatic Pressure : 

Definition:  The geostatic pressure at a given depth is the vertical pressure due to the weight of a column of rock and the fluids contained in the rock above that depth. Lithostatic pressure is the vertical pressure due to the weight of the rock only. 

Geostatic variables : 

Three variables determine geostatic pressure: 

• Densities of formation waters as related to salinities 

• Net thickness of different lithologies, e.g., sandstone, shale, limestone 

• Porosities of different lithologies

Calculating geostatic pressure : 

We can calculate geostatic pressure using the formula below:

PG = [weight of rock column] + [weight of water column] 

PG = [ρm × (1 – φ) × d ] + [ρw ×φ×d]

where: 

PG = geostatic pressure (psi) 

ρm = weighted average of grain (mineral) density (sandstone and shale = 2.65 g/cm3, limestone = 2.71 g/cm3) 

ρw = weighted average of pore-water density (g/cm3)

φ = weighted average of rock porosity 

d = depth (ft) 

To calculate weighted averages, use 1000-ft (300-m) increments

Geostatic gradient : 

Geostatic gradients vary with depth and location. The gradient increases with depth for two reasons: 1. Rock bulk density increases with increasing compaction. 2. Formation water density increases because the amount of total dissolved solids (TDS) in the water increases with depth. For example, in the Cenozoic of Louisiana, the geostatic gradient is 0.85 psi/ft at 1000 ft and 0.95 psi/ft at 14,000 ft.

3. Normal Hydrostatic Pressure Gradients: 

Definition: The hydrostatic pressure gradient is the rate of change in formation fluid pressure with depth. Fluid density is the controlling factor in the normal hydrostatic gradient. 

Factors controlling fluid density: 

Fluid density changes with depth as a result of changes in the following factors:

• Temperature 

• Pressure 

• Fluid composition (including dissolved gases and solids) 

• Fluid phase—gaseous or liquid 

These factors must be taken into account when estimating fluid pressure at depth. The small amount of dissolved gas contributes little to the density and can be ignored in the exploration state.

Factors controlling oil density:

Oil density varies greatly because of the large variety of oil compositions and quantity of dissolved gases. Also, oil composition is inherently much more variable than formation water composition.

Factors controlling gas density :

Gas density is strongly affected by pressure, temperature, and composition. In the reservoir, gas may be in the liquid phase; if so, we should treat it as a very light oil. Predicting gas phase can be complicated. Consult an experienced reservoir engineer when making this prediction.

Ranges of fluid density and gradient variation: 

Oil-field liquids and gases occur in a wide range of compositions. The table below shows typical density ranges and gradients for gas, oil, and water. However, because exceptions occur, have some idea of the type of fluid(s) expected in the area being studied and use appropriate values. 

Fluid	Normal density range (g/cm3)	Gradient range (psi/ft)
Gas (gaseous * )	0.007-0.30	0.003-1.130
Gas (liquid )	0.2-0.4	0.090-0.174
Oil	0.4-1.12	0.174-0.486
Water	1-1.15	0.433-0.5

(*) Varies with pressure , temperature , and composition .

 

Well Name /Designation

1.  The original name will be set by  the geology or exploration  departement  .There are three categories of well which need to be coded : 
2. Wells with the same Well Head and the Same Target 
3. Wells with the same  Well Head  and Different Targets 
4. Wells with Different Well Heads and the Same Target 

What is a Reservoir System?

The term “reservoir” creates confusion between different disciplines: 

• Explorationists apply the term to mean a porous and permeable rock regardless of the fluid it contains. 
• Reservoir engineers apply the term to mean a rock that contains hydrocarbons and associated fluids. 

This difference in meanings can cause problems for multidisciplinary teams unless the terminology is clear.