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.

Porosity

Sand grains and particles of carbonate materials that make up sandstone and limestone reservoirs usually never fit together perfectly due to the high degree of irregularity in shape. 

The void space created throughout the beds between grains, called pore space or interstice, is occupied by fluids (liquids and/or gases). 

The porosity of a reservoir rock is defined as that fraction of the bulk volume of the reservoir that is not occupied by the solid framework of the reservoir. The ratio of a volume of void spaces within a rocks to the total bulk volume of that rock is commonly expressed as a percentage ; i.e , all the collective void space is referred to as pore volume so that percent porosity (∅) is calculated as :

Porosity (Ⴔ)= (Volume of void space /total volume of rock) 

Porous sandstone 

The porosity range: 

 The porosity of porous materials could have any value, but the porosity of most sedimentary rocks is generally lower than 50% porosity represents the amount of void space in a rock and is measured as a percentage of the rock volume. 

Porosity is expressed as a percentage on a log. When used in calculations, however, it is important that porosity be expressed in decimal form.

Porosity is determined from conventional core and well log data. Typically, core data are more accurate because porosity is measured directly. Exceptions are unconsolidated sandstone and vuggy /fractured reservoirs . In unconsolidated sandstones , well log values of porosity are considered to be more accurate than disturbed core samples . 

In formations with vugs and fracture, it is challenging to obtain a representative core sample. The recommended approach is to compare core and log porosities at the same depth for each well that has been both cored and logged. The log porosities are adjusted to match the core data either by adjusting the inputs into the log calibration . If there are insufficient data to match core and log data directly, then the overall average core porosity can be compared with overall average log porosity . Some judgment is required to ensure that an appropriate comparison is made. For example is not valid to calibrate log data coming from one rock type (e.g., shaly sandstone ) 

Porosity is one of the more reliable reservoir measurements. Once an average porosity is determined, it is not recommended to adjust the average porosity by more than 0.01-0.03 .One exception to this rule of thumb is highly heterogeneous reservoirs with limited porosity data . Generally, porosity is a decreasing function of depth.  

In  a sandstone , this value is typically  much lower due to cementation and compaction . 

In a carbonate , it is possible to greatly exceed the theoretical  maximum porosity . Tis may be  achieved if the carbonate is highly fractured along with vuggy porosity .  

It is often said that porosity is: 

- Low if Ⴔ <5%

- Poor if 5% <Ⴔ <10%

- Moderate if 10% Ⴔ <20%

- Good if 20% <Ⴔ <30%

- Excellent if Ⴔ> 30%

Effective vs . noneffective porosity 

FACTORS GOVERNING THE MAGNITUDE OF POROSITY : 

The porosities of petroleum reservoirs range from 5% to 40% but most frequently are between 10% and 20%. The factors governing the magnitude of porosity in clastic sediments are:

a)      Uniformity of grain size (Well Sorted Rock ) :

Uniformity or sorting is the gradation of grains. If small particles of silt or clay are mixed with larger sand grains, the effective (intercommunicating) porosity will be considerably reduced. These reservoirs are referred to as dirty or shaly. Sorting depends on at least four major factors: size range of material, type of deposition, current characteristics, and the duration of the sedimentary process.

Very well sorted 

Poorly sorted 

Porosity relation  to arrangement  and shape  of rock  grains 

  b)      Degree of cementation or consolidation:

The highly cemented sand stones have low porosities, whereas the soft, unconsolidated rocks have high porosities. Cementation takes place both at the time of lithification and during rock alteration by circulating groundwater. The process is essentially that of filling void spaces with mineral material, which reduce porosity.

Cementing materials include: calcium carbonate, magnesium carbonate, iron carbonate, iron sulfides, limonite, hematite, dolomite calcium sulphate, clays, and many other materials including any combination of these materials.

Effect of cementation on porosity 

        c)   Amount of compaction during and after deposition:

c)   The amount of porosity is principally caused by the arrangement and shape of the rock grains, the mixing of grains of different sizes and shapes, and the amount of cementing material present

      Compaction tends to lose voids and squeeze fluid out to bring the mineral particles close together, especially the finer-grained sedimentary rocks. This expulsion of fluids by compaction at an increased temperature is the basic mechanism for primary migration of petroleum from the source to reservoir rocks. Whereas compaction is an important lithifying process in claystones, shales, and fine-grained carbonate rocks, it is negligible in closely packed sandstones or conglomerates.

Generally, porosity is lower in deeper, older rocks, but exceptions to this basic trend are common. Many carbonate rocks show little evidence of physical compaction.

Sedimentation process : Layer A is compacted by layer B 

d)      Grain  Packing:

With increasing overburden pressure, poorly sorted angular sand grains show a progressive change from random packing to a closer packing. Some crushing and plastic deformation of the sand particles occur.

Grain packing and its effect on porosity 

ENGINEERING CLASSIFICATION OF POROSITY:

During sedimentation and lithification, some of the pore spaces initially developed became isolated from the other pore spaces by various diagenetic and catagenetic processes such as cementation and compaction. Thus, many of the pores will be interconnected, whereas others will be completely isolated. This leads to two distinct categories of porosity, namely, total (absolute) and effective, depending upon which pore spaces are measured in determining the volume of these pore spaces. The difference between the total and effective porosities is the isolated or non-effective porosity.

Absolute porosities is the ratio of the total void space in the sample to the bulk volume of that sample, regardless of whether or not those void spaces are interconnected. A rock may have considerable absolute porosity and yet have no fluid conductivity for lack of pore interconnections. Examples of this are lava, pumice stone, and other rocks with vesicular porosity.

Total porosity is all void space in a rock and matrix whether effective or noneffective.

Effective porosity is affected by a number of lithological factors including the type, content, and hydration of the clays present in the rock, the heterogeneity of grain sizes, the packing and cementation of the grains, and any weathering and leaching that may have affected the rock. Many of the pores may be dead-ends with only one entry to the main pore channel system. Depending on wettability, these dead-end pores may be filled with water or oil, which are irreducible fluids. Experimental techniques for measuring porosity must take these facts into consideration. In order to recover oil and gas from reservoirs, the hydrocarbons must flow several hundred feet through the pore channels in the rock before they reach the producing wellbore. If the petroleum occupies non-connected void spaces, it cannot be produced and is of little interest to the petroleum engineer. Therefore, effective porosity is the value used in all reservoir engineering calculations. It represents the ration of the interconnected pore space to the total bulk volume. Other terminology such as secondary porosity, water-filled porosity, vuggy porosity, and fracture porosity.   

Effective porosity is the interconnected pore volume available to free fluids. 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. 

GEOLOGICAL CLASSIFICATION OF POROSITY

As sediments were deposited in geologically ancient seas, the first fluid that filled pore spaces in sand beds was seawater, generally referred to as connate water. A common method of classlfying porosity of petroleum reservoirs is based on whether pore spaces in which oil and gas are found originated when the sand beds were laid down (primary or matrix porosity), or if they were formed through subsequent diagenesis (e.g., dolomitization in carbonate rocks), catagenesis, earth stresses, and solution by water flowing through the rock (secondary or induced porosity).

The following general classification of porosity, adapted from Ellison, is based on the time of origin, mode of origin, and distribution relationships of pores spaces.

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.

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

Primary Porosity:	Secondary Porosity Secondary porosity:	Fracture porosity
Amount of pore space present in the sediment at the time of deposition, or formed during sedimentation.  It is usually a function of the amount of space between rock-forming grains.        1. Intercrystalline: voids between cleavage planes of crystals, voids between individual crystals, and voids in crystal lattices. Many of these voids are sub-capillary, i.e., pores less than 0.002 mm in diameter. The porosity found in crystal lattices and between mud-sized particles has been called “micro-porosity” by Pittma. Unusually high recovery of water in some productive carbonate reservoirs may be due to the presence of large quantities of microporosity . 2. Intergranular or interparticle: voids between grains, i.e., interstitial voids of all kinds in all types of rocks. These openings range from sub-capillary through super-capillary size (voids greater than 0.5 mm in diameter). 3. Beddingplanes: voids of many varieties are concentrated parallel to bedding planes. The larger geometry of many petroleum reservoirs is controlled by such bedding planes. Differences of sediments deposited, of particle sizes and arrangements, and of the environments of deposition are causes of bedding plane voids. 4. Miscellaneous sedimentary voids: (1) voids resulting from the accumulation of detrital fragments of fossils, (2) voids resulting from the packing of oolites, (3) vuggy and cavernous voids of irregular and variable sizes for at the time of deposition, and (4) voids created by living organisms at the time of deposition. Primary porosity is dominant in clastic-also called detrital or fragmental-sedimentary rockssuch as sandstones, conglomerates, and certain oolitic limestones	Post depositional porosity.  Such porosity results from groundwater dissolution, recrystallization and fracturing. It is the result of geological processes (diagenesis and catagenesis) after the deposition of sediment. The magnitude, shape, size, and interconnection of the pores may have no direct relation to the form of original sedimentary particles. Induced porosity can be subdivided into three groups based on the most dominant geological process 1. Solutionporosity: channels due to the solution of rocks by circulating warm or hot solutions; openings caused by weathering, such as enlarged joints and solution caverns; and voids caused by organisms and later enlarged by solution. 2. Dolomitization: a process by which limestone is transformed into dolomite according to the following chemical reaction: limestone dolomite 2CaCo~ + Mg2+ -+ CaMg(Co3) + Ca2+ (3.2) Some carbonates are almost pure limestones, and if the circulating pore water contains significant amounts of magnesium cation, the calcium in the rock can be exchanged for magnesium in the solution. Because the ionic volume of magnesium is considerably smaller than that of the calcium, which it replaces, the resulting dolomite will have greater porosity. Complete replacement of calcium by magnesium can result in a 12-13% increase in porosity . 3. Fracture porosity: openings created by structural failure of the reservoir rocks under tension caused by tectonic activities such as folding and faulting. These openings include joints, fissures, and fractures. In some reservoir rocks, such as the Ellenburger carbonate fields of West Texas, fracture porosity is important. Porosity due to fractures alone in the carbonates usually does not exceed 1% [7]. 4. Miscellaneous secondary voids: (1) saddle reefs, which are openings at the crests of closely folded narrow anticlines; (2) pitches and flats, which are openings formed by the parting of beds under gentle slumping; and (3) voids caused by submarine slide breccias and conglomerates resulting from gravity movement of seafloor material after partial lithification. In carbonate reservoirs, secondary porosity is much more important than primary porosity: Dolomites comprise nearly 80% of North American hydrocarbon reservoirs.  However, it is important to emphasize that both types of porosity often occur in the same reservoir rock.	Results from the presence of openings produced by the breaking or shattering of a rock.  All rock types are affected by fracturing and a rocks composition will determine how brittle the rock is and how much fracturing will occur.   The two basic types of fractures include natural tectonically related fractures and hydraulically induced fractures.  Hydraulic fracturing is a method of stimulating production by inducing fractures and fissures in the formation by injecting fluids into the reservoir rock at pressures which exceed the strength of the rock.  Hydraulic fracturing can tremendously increase the effective porosity and permeability of a formation.

VISUAL DESCRIPTION OF POROSITY IN CARBONATE ROCKS : 

The role played by the visual description of pore space in carbonate rocks has changed considerably since the development of a method for classifying carbonate reservoir rocks in 1952 by Archie.

The development of well logging technology has provided the petroleum industry with effective and direct methods to measure the in-situ porosity of a formation.

The visual description of the pore geometry, however, is still needed to estimate the effects of

•  The grain size;
•  The amount of inter-particle porosity;
•  The amount of unconnected vugs;
•  The presence of fractures and cavities;

-         The presence or absence of connected vugs on the porosity-permeability relationship and other petrophysical parameters of naturally fractured reservoirs.

  Lucia presented field classification of carbonate rock pore space based on the visual description of petrophysical parameters of a large number of samples. He also discussed basic geological characteristics necessary for the visual estimation of particle size and recognition of interparticle pore space, and connected and unconnected vugs. Lucia proposed a field classification of carbonate porosity as follows:

• For fine particle size (d, less than 20 pm), the displacement pressure, PD, is greater than 70 psia;
• For medium particle size (20 .c d, .c 100 pm), the PD is in the range of 15-70 psia;
• For large grains (d, > 100 pm), the displacement pressure is less than 15 psia. The term PD is the extrapolated displacement pressure, which is determined from the mercury capillary-pressure curves , shows the relationship between PD and the average grain size as a function of the inter-granular porosity for non-vuggy rocks with permeability greater than 0.1 mD. This relation-ship is the basis for dividing particle size into the three groups.

QUANTITATIVE USE OF POROSITY : 

Calculating reservoir oil content  the initial oil-in-place, the initial gas-in-place, and The initial gas deviation (also called compressibility)

Core-log porosity integration: 

• If we have core data, we overlay it on the log porosity data.
• We double check that both logs are on depth.
•  If the core porosity is matched with log porosity, then our parameters are optimal.
•  If the core data is not matched with the porosity from log, then we need to do corrections for the porosity from log.
• Either test the parameter or cross plot the porosity from log with the one from log. In general , a  regression line shows  that the log porosity is 0.01 less than the core porosity, which may be due to slight different in Matrix density or fluid density.