Giáo trình bài tập chapter5

• + Sulin classification : Water is divided based on Ion ratio, which specifying different generation conditions, and especially in oil and gas formation water... • The fluid pressure

CHAPTER 06

THE SUBSURFACE

ENVIRONMENT

UA-2011

1- GROUND WATER AND

1- GROUND WATER AND

TEMPERATURE

1.1 ᾶ GROUND WATER

1.1.1 ᾶ Origin of ground water

1.1.2 ᾶ Chemistry of ground water

1.2 ᾶ TEMPERATURE

1.2.1 ᾶ Subsurface Temperature

1.2.2 ᾶ Regional thermal Variations

1.2.3 ᾶ Local thermal Variations

04 Types of GW

Meteoric water

Infiltration of rainwater

Distribution @ shallow depth

Total mineralization: Low

concentration of dissolved salt and pH, and Eh

04 Types of GW (cont.)

Juvenile water

Primary of magmatic origin

Brought to near ᾶ surface environment

dissolved in magma

Usually mixed with either connate or

meteoric water

Mixed water

meteoric, juvenile and connate waters

Usually between the near – surface meteoric water, juvenile and the deeper, more saline connate water

1.1 2 ᾶ Chemistry of ground water

Connate water, meteoric water and mixed water can be differentiated on the basics of their chemistry

Way can be done:

Fig 01

Deep connate water show a wide range of

Eh and pH depending on their history and how much theyᾼve mixed with meteoric water

and more strongly reducing than seawater

The Eh and pH of pore fluids control the precipitation and dissolution of cements such as the carbonates and ion oxides, as well as the alterations of clays minerals in

understand the relationships of Eh and pH

to diagenesis and the evolution of porosity

Chemistry of ground water

(cont.)

Second: Salinity

)-Fig.02 The rate of increases varies from

basin to basin, even from place to place

within a particular basin

Typical seawater has a salinity of about

35ppthousand (3.5%)

The salinity of GW range from near zero (in

600ppthousand (60%) in connate water

within evaporate formation

Fig 02

Reversal hydrochemical profile have been observed due to two possible causes:

1 Meteoric can be trapped beneath an

᾿Paleoaquifer῀ with relative low salinity as

unconformity

2 Overpressure: In shale sequences, formation water is trapped

In shale, the increases in salinity with depth

is less noticeable than in sandstones:

Water moves upwards in compacting

sediments, shale acts at semipermeable

membranes preventing salt escaping from

the sands

Four major sub environment:

circulating meteoric water Salinity fairly uniform;

2 Zone 2 (1 → 3km) gradually increases with depth Saline formation water is ionized;

3 Zone 3 (3km) Chemically reducing

environment, in which hydrocarbons form Salinity uniform with increasing depth; may even decline

if overpressured;

4 Zone 4 incipient metamorphism with

recrystallization of clays to micas

Formation water

classification

Oder Category Total dissolved Solids

Oder Category Total dissolved

Solids(mg/l)

ê Regional isosalinity maps are very useful

exploration tools

stagnant regional are uneffected by

GW Composition

water both salinity and proportions of

dissolved irons

Connate water divided

to:

+ High CL - and Ca 2+

water high concentration of soluble

chlorine and sodium (Tab 03)

(Br is more abundant than seawater)

+ SO 2- 4 reduction by bacterial action,

producing H 2S gas

Table 03

ê Depletion of Mg 2+ in connate water

illite + Ca2+ + Na2+ + H2O)

+ Low rate of calcium precipitation

• Depletion of potassium probably results from the uptake of that element by clay minerals.

• Connate waters also contain traces of

dissolved hydrocarbons which are not

common in normal sea water (Buckley et al., 1958)

– This is significant for two reasons: First, it raises

the possibility of regionally mapping dissolved

hydrocarbons as a key to locating new oil and gas

fields Second, it has some bearing on the

migration of both oil and gas

GW research application in O&G Exploitation &

Exploration

(By Tran van Xuan)

GW research application in O&G Exploitation &

Exploration (Cont.)

• + Sulin classification : Water is divided based

on Ion ratio, which specifying different

generation conditions, and especially in oil

and gas formation water This classification

is widely applied in petroleum hydrogeology

• Based on relationships (rNa + , rCl - Ὴ are

FW divided to 4 types (by Sulin):

1 Sodium sulfate (cratonic solution origin):

2 Sodium bicarbonate (cratonic origin):

ῆ 3 Chloride magnesium (Marine origin):

ῆ 4 Chloride calcium (formation water):

<1 and

2 4

2 4

GW Classification by Sulin (Russia)

Fig 03

• The pore spaces in rocks usually contain water, whose thermal conductivity is lower than that of many minerals As these rocks are buried, porosity is reduced, water is

expelled, and their thermal

conductivities increase

Thermal Conductivities and Rock Type

The thermal conductivities of some common

sedimentary rock types

Fig 04

• Although oil-producing basins have not been found along oceanic ridges, they have been found in rift-type basins

associated with intracontinental crustal extension, such as the Suez Graben in the Middle East and the Viking Graben

in the North Sea

• In some of these, the heat flow is elevated above normal because the outer mantle of the earth beneath them is

hotter than normal, as is the case along a mid-oceanic

ridge

Fig 06

• Where plates are converging at subduction zones, as along the Indonesian arc,

abnormally low heat flow is seen in the trench region ( Figure 7)

arc-Fig 07

• Block fault basins, called "back-arc

basins", often form on the cratonic side of volcanic arcs These back-arc sedimentary basins also may display abnormally high

heat flow which provides for the efficient

generation of petroleum Examples are the back-arc basins of the Indonesian arc

(Figure 9)

Fig 09

• The important thing to remember is that

basins with high heat flow and high

thermal gradients can produce oil at

shallower depths than basins with low heat flow and low thermal gradients

• The potential for petroleum migration and the quality of reservoirs are both greater at shallower depths where primary porosity

may still be preserved

• Figure 10 shows the depths to certain

isotherms as a function of thermal

gradient We can plot on this graph the 60°

C, 175ºC and 220°C isotherms

• The minimum temperature for the

generation of oil is about 60 °C and for

thermal gas, about 175 °C

Fig 10

• Regardless of what the regional heat flow

is, it is important to recognize that an

interval of unusually low thermal

conductivity at some depth in a region also affects the position of the oil and gas

"thermal window"

• Figure 11 shows a thermal gradient of 20°C/km

• The low conductivity zone acts as an insulating blanket and raises the temperature at every

depth below it Of importance here is the fact

that the prospect of finding shallow petroleum is greatly improved by the elevation of the "thermal window" for oil and gas generation

Fig 11

• Lithostatic pressure is due to the weight of the

rock overburden It is transmitted through the

subsurface by grain-to-grain contacts in the

rocks

• The magnitude of this lithostatic pressure at a

particular depth depends on the depth, the

density of the overlying rocks, and the

acceleration due to gravity

• The lithostatic pressure gradient increases

with depth and is approximately 0.6 psi/ft ( 0.136 kg/cm2 * m ) or ( 13.6 kPa/m )

• The fluid pressure, often called "pore

pressure" or "formation pressure", is applied

by the fluids within the pore spaces These fluids exert pressure against the grains

• When the pressure in the pores is caused only

by the weight of the column of fluid in the rocks

above, it is called hydrostatic pressure

• For a column of fresh water with a density of 1

gm/cm3, the hydrostatic gradient is 433 psi/ft

(0.0979 kg/cm2 * m) or ( 9.79 kPa/m) The

gradient increases with increasing salinity of the

water to about 465 psi/ft (0.1052 kg/cm2 * m) or

(10.52 kPa/m) for typical connate water

In the oil industry, fluid pressure is usually calculated

as:

p = 0.052 x wt x d

where:

– p = hydrostatic pressure ( psi )

– wt = mud height ( lb/gallon )

– d = depth ( ft )

The overburden pressure, which is also called

geostatic pressure, is equal to the sum of the

hydrostatic pressure plus the lithostatic pressure

This pressure may also be thought of as the pressure caused by the weight of water plus sediment per unit area The overburden pressure increases with depth

and averages about 1psi/ft ( 226 kg/cm2 * m ) or ( 22.6 kPa/m )

Summarizing differences between lithostatic and fluid pressure gradients we might normally expect to see

Fig 12

Downhole Pressures

• Normal hydrostatic pressure is roughly half the

overburden pressure at any depth In a normally

pressured well, measured fluid pressures would lie

on the hydrostatic curve However, abnormally

pressured intervals commonly occur in wells

• These abnormal pressures have important

implications concerning the history of the basin, the formation of traps, and the migration of fluids as well

as causing severe drilling problems Intervals that have fluid pressures higher than hydrostatic are

described as "over-pressured", those intervals with fluid pressures less than hydrostatic are called

"underpressured".

• Some oil fields ( such as those in the

Rocky Mountains of the U.S.A ) are

characteristically underpressured, while

many other fields ( for example those in

the Gulf Coast area of the U.S.A, Bach Ho oil field of Viet Nam ) are overpressured

Pressure regimes in well 110 of basement (Bach

Ho oil field):

•In L.Miocene formation, the pressure factor only reached 0.91.0.

•In U part of U Oligocene formation exist very high: overpressure (1.7251.715).

•In L part of U Oligocene formation, the pressure factor decreased , but still high (1.68

1.34).

•In L Oligocene formation and basement: the pressure factor only has value 1.231.25.

Fig 13

• Drilling in these areas requires special care

when the drill stem passes through an interval with

formation fluid pressures either higher or lower

than normal As a rule, pore fluid under normal

pressure conditions tends to flow into the well To prevent seepage into the hole, the density of the drilling mud is adjusted to maintain a sufficient

back pressure against the wall of the hole If the

bit were to suddenly penetrate a bed that is

underpressured, then the drilling mud would be

forced into the formation and mud circulation

would be lost

• If, on the other hand, a high pressure bed

is penetrated, formation water will be

injected into the hole, despite the mud

pressure and significant back pressures

on the mud column, with the consequent danger of blow

• Understanding where the abnormally

pressured zones are likely to be along the course of the hole allows adjustments to

be made to prevent significant disruption

in drilling operations

Pressure Integrity & Pressure Balance Drilling

Lateral & Vertical Distance in Basement

Different Pressure Domain

Cumulative Mud Loss Situation

Establishment of Pressure Balance System while Drilling

Pressure Gradient in the Basement Reservoir

Severe Mud Loss Partial Mud Loss

Floating Mud Cap &

Blind Drilling

Total Mud Loss

Fig 14

Low Pressure Domain

High Pressure Domain

Different Pressure Compartment

Different pressure Behavior in Isolated

Compartment

Fig 15

Potentiometric Surfaces

• The pressure of the fluids in the rocks

would cause the fluid to rise to a certain level in the well This level is called the

"potentiometric", or sometimes the

"piezometric", level and is usually

designated by its elevation with respect to sea level

• Figure 17 is a geological situation

somewhat similar to the one that have just discussed

Fig 17

• The potentiometric surface may also point

to areas in which the formation water is

most saline The salinity of formation water commonly increases in the direction that

the potentiometric surface is inclined

• Figure 18 shows contours on the elevation

of the potentiometric surface in the Illizi

basin of Algeria

Fig 18

• As a rule, subsurface fluids move readily through rocks, such as sandstone, that have high permeability Fluid movement through rocks with low permeabilities,

such as shale, is much slower

• Fluids in the pore spaces of rocks can be considered to exist in two forms (fig 19)

Fig 19

• Some of the fluid is adsorbed onto the

surfaces of the grains and held there by

electrical attractive forces This water is

often called "interstitial" water.

• Some of the fluid is not bound to the surfaces

of grains but rather is located in the center of each pore space This water is not electrically

held to the grain surfaces and is called "free

water" because it can move from pore space

to pore space

• The adsorbed water is not free to move.

• Sandstones generally allow fluids to flow

readily because the pores are relatively large and most of the pore water is "free water"

• Shales have low permeabilities because they have very small pore spaces and abundant clay mineral grains that have high surface

charge densities These factors cause most

of the pore water in shales to be bound and difficult to move

• Rocks with low permeability, such as shale, therefore, retard the flow of water and act as flow barriers.

2.1.2 Abnormal Fluid Pressures

• When fluid communication with the

surface is inhibited by rocks of low

permeability, it can caused abnormal or non-hydrostatic pore pressures

TWO ASPECTS TO CONSIDER:

• The nature of the fluid barrier and

• The reason for the pressure build-up

• There are five major causes of high fluid

pressure:

1.Artesian systems: pore pressures greater

than normal hydrostatic pressure are

produced in a confined aquifer

2.Undercompaction of shales: present of

shale-rich intervals in a stratigraphic

section

3.Deformation: by faulting

4 Diagenesis: water-liberating chemical

reactions

5 Thermal expansion of water as the

temperature increases with depth

basins and cause significally drilling and production difficulties

Compaction Overpressuring

Process

• In sedimentary basins where sediment is being rapidly deposited, as in the

Mississippi River delta, we encounter

overpressures from undercompaction of shales

Fig 20