This document discusses tight reservoirs, which are reservoirs with very low permeability (less than 0.1 mD) and porosity (less than 10%). It defines tight gas reservoirs, tight oil reservoirs, and the characteristic properties of tight reservoirs, such as low porosity and permeability. It also discusses the importance of logging, factors to consider for tight reservoirs like geologic and reservoir properties, and techniques used to produce from tight reservoirs, including hydraulic fracturing and horizontal drilling. Tight reservoirs account for a large portion of remaining oil and gas reserves and require advanced drilling and completion techniques to produce economically.

1. Introduction

2. What is tight reservoir?
• Tight reservoirs are generally defined as having less than 0.1 milli Darcy
(mD) matrix permeability and less than ten percent matrix porosity.
• Production rates from tight reservoirs are marginal, but these reservoirs
account for a large percentage of the long-term supply of oil and gas.

3. Tight gas reservoir
• Tight gas is natural gas produced from reservoir rocks with such low
permeability that massive hydraulic fracturing is necessary to produce the
well at economic rates. That reservoir is called as the tight gas reservoir.
• Although shales have low permeability and low effective porosity, shale
gas is usually considered separate from tight gas, which is contained most
commonly in sandstone but sometimes in limestone.
• Tight gas is considered unconventional source of natural gas.

4. Tight oil reservoir
• Tight oil is the oil that is found within the reservoir with very low
permeability.
• The oil contained within the reservoir typically will not flow to the wellbore
at economic rate. That reservoir is called as tight oil reservoir.
• Tight oil cannot produce without assistance from technologically advanced
drilling and completion process.
• Commonly, horizontal drilling coupled with multi-stage fracturing is used to
access these difficult to produce reservoir.

5. Characteristic of tight reservoir
• Tight reservoirs characterized with low porosity and permeability, small
drainage radius, and require significant well stimulation – hydraulic fracture
treatment – or the use of horizontal or multi-lateral wells to produce at
economic rates.
• Tight reservoir is a Strong heterogeneity and low single-well control
reserves.
• The tight reservoirs are characterized by large pressure gradient across
reservoir, often layered and complex, high transient decline rate and
comingled production.
• Typical lithology of tight reservoirs are sandstone/siltstone and rarely
carbonate with permeability as low as (<0.1md).

6. • Tight gas reservoirs are generally gas-saturated with little or no free water.
Special recovery processes and technologies like hydro-fracturing, steam
injection etc are used to produce hydrocarbons from theses reservoirs.
• Tight reservoir rock cores to reveal the nonlinear flow characteristics of
single-phase water and oil in the irreducible water state. Threshold
pressure gradient increases with the decreases of permeability.
• Tight reservoirs are mostly associated with conventional reservoirs, which
could be sandstone, siltstone, limestone, dolomite, sandy carbonates
shale and chalks with significant thickness.
• Tight reservoir sands are continuous and stacked sedimentary layers
charged with hydrocarbons.

7. • The most common tight sands generally consist of highly altered primary
porosity, with authigenic quartz growth, coupled with secondary pore
developments.
• Many tight formations are extremely complex, producing from multiple
layers with permeability that often enhanced by natural fracturing. Origin of
Fractures are due to folding and faulting, solution of evaporates, high pore
pressures, regional present day stress field and regional fractures.
• Recovery factor from tight reservoirs globally stand at around just 7-20%.
Recovery is a function of the extent to which fractures extend from each
well.

8. Logging in tight
reservoir

9. • Logging is the important process in the petroleum sector.
• Logging is important to find the hydrocarbon in to the reservoir
and find the lithology below the earth surface.
• Factors identified by Logging in tight reservoir
1. Location of the tight reservoir
2. Lithology
3. Natural fracture
4. Permeability
5. Porosity
6. Tightness

10. • Different type of logs are used in tight reservoir to find its
characteristics
• Types of Logs:
1. SP (spontaneous potential)
2. NMR (nuclear magnetic resonance)
3. Resistivity
4. Neutron porosity and density log
5. Gamma ray log
6. Image

11. Spontaneous potential log
The currents shown
flowing from shale bed
Sh 1 toward permeable
bed P2 are largely
confined to the borehole
by the high resistivity of
the formation separating
Sh1 and P2. The current
in the borehole over this
interval is constant, so
the SP curve is a straight
line inclined to the shale
baseline. The slope
changes near the more
conductive permeable

12. Across the tight reservoir,
the current flowing in the
mud is constant, so the
potential gradient is
uniform.

13. NMR log
• NMR porosities are not affected by shale of rock mineralogy. NMR logs
differ from conventional neutron and density porosity logs, NMR signal
amplitude provides detailed porosity free from lithology effects.
• Relaxation time gives other petrophysical parameters of tight reservoir
such as permeability, capillary pressure, distribution of pore sizes and
hydrocarbon identification

14. Resistivity log:
• Due to low porosity the resistivity log shows high resistivity of the order of 70
Ωm.

15. Neutron porosity and density log
• Since tight reservoirs are mostly shaly sands so the thermal neutron
absorbers in shaly sands affect the neutron porosities which cause neutron
porosity very high.
• As a result neutron density logs can miss hydrocarbon zones in the tight
reservoirs.

16. Gamma ray log
• Due to presence of clay minerals the total Gamma ray shows high gamma API
which misleads the reservoir as non-reservoir
• This ambiguity is resolved with the help of Spectral Gamma Ray log which infers
the presence of radioactive minerals in the reservoir.

17. Image log
• Structural features, such as fault and fractures can be interpreted for
orientation, genetic relationship and morphology on the borehole images
• Borehole images provide vital information on the stress regime which is
key to successful planning of hydro-fracturing of a well.

19. Factors to consider for tight reservoir

20. Geologic considerations
The analysis of any reservoir, including a tight reservoir, should always begin with a
thorough understanding of the geologic characteristics of the formation. The important
geologic parameters for a trend or basin are:
• The structural and tectonic regime
• The regional thermal gradients
• The regional pressure gradients
Knowing the stratigraphy in a basin is very important and can affect:
• Drilling
• Evaluation
• Completion
• Stimulation

21. Important geologic parameters that should be studied for each stratigraphic unit
are:
• The depositional system
• The genetic facies
• Textural maturity
• Mineralogy
• Diagenetic processes
• Cements
• Reservoir dimensions
• Presence of natural fractures
Geologic considerations

22. Reservoir continuity
One of the most difficult parameters to evaluate in tight reservoirs is the drainage area size
and shape of a typical well. In tight reservoirs, months or years of production are normally
required before the pressure transients are affected by reservoir boundaries or well-to-well
interference. As such, the engineer often has to estimate the drainage area size and shape for a
typical well in order to estimate reserves. Knowledge of the depositional system and the effects
of diagenesis on the rock are needed to estimate the drainage area size and shape for a
specific well.
In blanket, tight gas reservoirs, the average drainage area of a well largely depends on :-
• the number of wells drilled
• the size of the fracture treatments pumped on the wells
• the time frame being considered
A main factor controlling the continuity of the reservoir is the depositional system. Generally,
reservoir drainage per well is small in continental deposits and larger in marine deposits. Fluvial
systems tend to be more lenticular. Barrier-strandplain systems tend to be more blanket and
continuous.
Most of the more successful tight plays are those in which the formation is a thick,
continuous, marine deposit.

23. Reservoir considerations
Normally, a tight reservoir can be described as a layered system. In a clastic depositional
system, the layers are composed of:
• Sandstone
• Siltstone
• Mudstone
• Shale
In non clastic systems, layers are composed of:
• Limestone
• Dolomite
• Possibly halite or anhydrite

24. Reservoir considerations
The following data are required to use 3D reservoir and fracture propagation models to
evaluate the formation, design the fracture treatment, and forecast production rates and
ultimate recovery:
• Gross pay thickness
• Net pay thickness
• Permeability
• Porosity
• Water saturation
• Pressure
• In-situ stress
• Young’s modulus
The speed at which pressure transients move through porous media is a function of the:
• Formation permeability
• Fluid viscosity
• Fluid compressibility

25. Drilling and completion considerations
• The most important part of drilling a well in a tight reservoir is to drill a gauge
hole. A gauge hole is required to obtain an adequate suite of openhole logs and
to obtain an adequate primary cement job. In low porosity, shaly reservoirs, the
analyses of gamma ray (GR), spontaneous potential (SP), porosity, and
resistivity logs to determine accurate estimates of shale content, porosity, and
water saturation can be difficult. If the borehole is washed out ("out of gauge"),
the log readings will be affected, and it will be even more difficult to differentiate
the pay from the non-pay portions of the formation.
• Formation damage and drilling speed should be a secondary concern. Some
wells are drilled underbalanced to increase the bit penetration rate or to
minimize mud filtrate invasion.
• The completion strategy and stimulation strategy required for a tight reservoir
very much depends on the number of layers of net pay and the overall economic
assessment of the reservoir. In almost every case, a well in a tight reservoir is
not economic to produce unless the optimum fracture treatment is both designed
and pumped into the formation.

26. Formation evaluation
To properly complete, fracture treat, and produce a tight reservoir, each layer of the pay
zone and the formations above and below the pay zone must be thoroughly evaluated.
The most important properties that must be known are pay zone thickness, porosity, water
saturation, permeability, pressure, in-situ stress, and Young’s modulus. The raw data that
are used to estimate values for these important parameters come from:
• Logs
• Cores
• Well tests
• Drilling records
• Production from offset wells

27. Principle types of Tight reservoir
• Tight formation (gas)
A tight gas reservoir is one in which the expected value of permeability to
gas flow would be less than 0.1 md.
• Coal bed (methane)
Coalbed methane, as its name suggests, is trapped in coal deposits. It is
also known as coal seam gas. Most of the gas is adsorbed on the surface of
the coal, which is an excellent "storage medium": it can contain two to three
times more gas per unit of rock volume than conventional gas deposits.
• Shales (gas)
Shale gas is natural gas that is found trapped within shale formations
• Carbonate reservoir
• Shale oil
Tight oil (also known as shale oil or light tight oil, abbreviated LTO) is
petroleum that consists of light crude oil contained in petroleum-bearing
formations of low permeability, often shale or tight sandstone.

28. Techniques to produce from tight reservoir

29. Techniques to produce from tight reservoir
• In contrast with conventional reservoir, unconventional gas from tight
reservoir is situated in rocks with extremely low permeability, which makes
extracting it much more difficult.
• New technologies and enhanced applications of existing techniques are
making it possible to extract these tight gas resources safely, responsibly and
economically. The combination of horizontal wells and hydraulic fracturing,
for example, have been key to unlocking unconventional gas reserves in the US
and elsewhere.

30. Hydraulic fracturing
• Hydraulic fracturing is the most common mechanism to create channels ( highly
conductive path) by breaking the low permeabilty rock to increase well productivity.
• Carbonate formations generally have a low permeability and can be highly fissured
In certain carbonate reservoirs fracturing is performed with acid – acid fracturing.
Why Fracture?
• By-pass near wellbore damage
• Increase well production by changing flow regime from radial to linear
• Reduce sand production
• Increase access to the reservoir from the well bore.
• Develop uneconomical/ marginal reserves.
• 95% of US and Canada fractures are in tight-gas or unconventional resource wells

31. • Effect of Hydraulic Fracture on Flow Regime.
• If properly created, hydraulic fractures can change flow regime from
radial to linear

32. Process
• We are injecting a fluid at high pressure, which overcomes the tensile
strength of the rocks and breaks them.
Fig. depicting shale will sustain maximum amount of strain at some confining pressure
before fracturing.

33. Hydraulic fracturing is done in 4 stages.
• Pre pad or pre flush : pumping of thin fluid ahead of water to decrease the
friction pressure.
•It also cools down the hot formation so that the viscosity of the fluid which we
pumped in second stage do not fall down.
• We inject the drag or friction reducer in low concentration i.e. ½ or ¼ gallon per
1000 gallon of water, which reduces friction pressure by 80 to 85%.
• It initiates fractures.
Pad stage of viscous fluid : viscous fluid is pumped in order to enhance fracture
dimensions in terms of height, width and lengh.
•Polymers are also added in fluid so that it can hold the proppant in suspension.

34. • Proppant laden stage
• solids are added with viscous fluid to make a slurry and pump them to keep
the fractures open which closes due to overburden.
Flush stage
• After proppants are set in the fractures, by reducing pressure in stages by
choke production commences. We add thin fluids – Visbreakers which
reduces the viscosity of fluids which we have pumped, to flow.
• We want proppants to be in the fractures, not the viscous fluid. So that
fractures do not closes.

35. HORIZONTAL DRILLING
• The purpose of drilling a horizontal well is to increase the contact between the
reservoir and the wellbore
• Horizontal drilling also has a greater production rate than traditional vertical drilling
because of the greater wellbore length exposed to the pay zone.
•. Wells are drilled vertically to a predetermined depth (typically 1000m to 3000m
below the surface depending on location) above the tight oil reservoir.
• The well is then “kicked off” (turned) at an increasing angle until it runs parallel
within the reservoir. Once horizontal, the well is drilled to a selected length which can
extend upto 3-4km. This portion of the well is called the horizontal leg.
• Using horizontal drilling techniques, companies can now drill a number of wells in
different directions from one well pad, which is much more efficient than having
numerous well pads set up to extract oil. This decreases the surface disturbance and
saves money with the reduced costs of well pad setups, replacements and
maintenance costs.

36. Figure depiciting the various parts of deviated well from kick off point to
lateral section.

37. Figures showing the deviation of a vertical well.
In fig. 2 section A has more lateral contact, thus have more drainage radius of reservoir

38. Global scenario
• Few countries like USA, China, Australia, Canada are the pioneer in
the development of tight reservoir.
• At present 50% of daily US gas production recovered from tight
reservoir
• Alberta basin, Michigan basin, andarko basin, spraberry field of
western texas containing billions of barrel of oil in place.
• Tight gas fields are also being developed around the world e.g. Yucal
Pacer field in Venezuela, Aguada Pichana in Argentina, Timimoun in
Lgeria and Aloumbe in Gabon, Sui area in Balochistan of Pakistan,
Warro field in western Australia.
• Recoverable tight gas reservoirs is Canada-20.4 TCM,
CIS(commonwealth of independent states)-5.4 TCM, Middle east-3.4
TCM & Others-1.4TCM

39. Indian scenario
• Tight reservoir occur in almost all the producing basins of India.

40. KG basin
• Penugonda, south Mahadevpattanam and Malleshwaram fields have been with
very good potential for exploration of tight reservoirs.
• The estimated in place volume of tight reservoirs is approximately 50 BCM.
Cauvery basin
• The early cretaceous Andimadan sandstone, late cretaceous Bhuvanagiri
formation has low porosity and permeability.
• A production of 70-90 MMTOE of oil/gas is envisaged from these HP-HT/tight
reservoirs by 2030 from KG and Cauvery basins.

41. Mumbai Offshore Basin
• Mukta Formation have proved to be hydrocarbon bearing in the Mumbai offshore
basin as well as in their wedge out area lying on the southern plunge of Bombay
high. Mukta and Bassein formation in the wedge out are appeared to be a tight
reservoir in this area lead to better exploration control.
Cambay basin
• Cambay Basin contains thick, over pressured low permeability tight reservoir in
the Eocene section.
• Tight gas reservoirs holds approximately 413 BCF of economically recoverable
tight gas
• Cambay Shale and Olpad formations are tight reservoirs

42. • Vindhyan Basin, a Proterozoic basins of India is under
exploration for the last few years. Discovery have been
made in Son valley, few wells flowed gas during
production testing from Rohtas limestone at a depth
of around 1500m-1600m. The discoveries have opened a new window for
exploration in proterozoic sediments.
The reservoir rock is limestone and is very tight due
to its argillaceous nature as well as silica fillings and
quartz overgrowth. Development of primary porosity and
primary fractures are almost absent and porosity is around 2 - 4%.

43. • In Mizoram ONGC has discovered non-commercial gas in a tough and
geologically challenging field, well drilled
about 130 km north of its capital Aizawal. First time
hydrocarbon was struck in lower Bhuban formation of fold
belt area in the state. According to the primary estimate the potential of the area
is approximately 3 BCM (In-place). Hydro-fracture is planned to access actual
potential of the well. The reservoir is sandstone and is tight in nature.
• Barmer Hill of Barmer Basin in Rajasthan which feeds the most prolific reservoir
oil blocks like Mangala and Bhagyam is the main source rock. Cairn India also
plans to drill a well at the source rock and recover oil through fracking.

44. Questions?