tight reservoir
TRANSCRIPT
Introduction
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.
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.
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.
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).
• 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.
• 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.
Logging in tight reservoir
• 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
• 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
Spontaneous potential logThe 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
interval.
Across the tight reservoir,
the current flowing in the
mud is constant, so the
potential gradient is
uniform.
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
Resistivity log:
• Due to low porosity the resistivity log shows high resistivity of the order of 70 Ωm.
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.
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.
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.
Factors to consider for tight reservoir
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
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
Reservoir continuityOne 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 normallyrequired before the pressure transients are affected by reservoir boundaries or well-to-wellinterference. As such, the engineer often has to estimate the drainage area size and shape for atypical well in order to estimate reserves. Knowledge of the depositional system and the effectsof diagenesis on the rock are needed to estimate the drainage area size and shape for aspecific 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. Fluvialsystems tend to be more lenticular. Barrier-strandplain systems tend to be more blanket andcontinuous.
Most of the more successful tight plays are those in which the formation is a thick,continuous, marine deposit.
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
Reservoir considerationsThe 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
Drilling and completion considerations
• The most important part of drilling a well in a tight reservoir is to drill a gaugehole. A gauge hole is required to obtain an adequate suite of openhole logs andto obtain an adequate primary cement job. In low porosity, shaly reservoirs, theanalyses of gamma ray (GR), spontaneous potential (SP), porosity, andresistivity logs to determine accurate estimates of shale content, porosity, andwater 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 differentiatethe pay from the non-pay portions of the formation.
• Formation damage and drilling speed should be a secondary concern. Somewells are drilled underbalanced to increase the bit penetration rate or tominimize mud filtrate invasion.
• The completion strategy and stimulation strategy required for a tight reservoirvery much depends on the number of layers of net pay and the overall economicassessment of the reservoir. In almost every case, a well in a tight reservoir isnot economic to produce unless the optimum fracture treatment is both designedand pumped into the formation.
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
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.
Techniques to produce from tight reservoir
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.
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
• Effect of Hydraulic Fracture on Flow Regime.
• If properly created, hydraulic fractures can change flow regime from
radial to linear
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.
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.
• 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.
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.
Figure depiciting the various parts of deviated well from kick off point to
lateral section.
Figures showing the deviation of a vertical well.
In fig. 2 section A has more lateral contact, thus have more drainage radius of reservoir
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
Indian scenario
• Tight reservoir occur in almost all the producing basins of India.
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.
Mumbai Offshore Basin
• Mukta Formation have proved to be hydrocarbon bearing in the Mumbai offshorebasin as well as in their wedge out area lying on the southern plunge of Bombayhigh. Mukta and Bassein formation in the wedge out are appeared to be a tightreservoir in this area lead to better exploration control.
Cambay basin
• Cambay Basin contains thick, over pressured low permeability tight reservoir inthe Eocene section.
• Tight gas reservoirs holds approximately 413 BCF of economically recoverabletight gas
• Cambay Shale and Olpad formations are tight reservoirs
• Vindhyan Basin, a Proterozoic basins of India is underexploration for the last few years. Discovery have beenmade in Son valley, few wells flowed gas duringproduction testing from Rohtas limestone at a depthof around 1500m-1600m. The discoveries have opened a new window forexploration in proterozoic sediments.The reservoir rock is limestone and is very tight dueto its argillaceous nature as well as silica fillings andquartz overgrowth. Development of primary porosity andprimary fractures are almost absent and porosity is around 2 - 4%.
• In Mizoram ONGC has discovered non-commercial gas in a tough andgeologically challenging field, well drilledabout 130 km north of its capital Aizawal. First timehydrocarbon was struck in lower Bhuban formation of foldbelt area in the state. According to the primary estimate the potential of the areais approximately 3 BCM (In-place). Hydro-fracture is planned to access actualpotential of the well. The reservoir is sandstone and is tight in nature.
• Barmer Hill of Barmer Basin in Rajasthan which feeds the most prolific reservoiroil blocks like Mangala and Bhagyam is the main source rock. Cairn India alsoplans to drill a well at the source rock and recover oil through fracking.
Questions?