SHALE GAS EXPLORATION AND PRODUCTION

Vivek PriyadarshiM.Sc in Petroleum Geosciences

Department of GeologyBanaras Hindu University,Varanasi-221005,INDIA

What Is Unconventional Gas?Unconventional gas formations are “continuous”, deposited over large areas rather than in discrete traps.•The geologic setting of unconventional gas is several orders more complex than conventional gas.•For coalbed methane and gas shales, the gas source, trap and reservoir are the same, not three distinct elements as for conventional gas.

Shale GasShale Gas contained in absorbed form in the

micro-pores and micro fractures of shale which is a sedimentary rock. The gas mostly thermogenic origin but cases of biogenic sources are also reported.

The shale gas exploration in India is relatively new but rapidly gaining momentum, as India has huge shale deposits. The shale in Vindhyan, Gondwana, Cambay, Rajasthan, & other sedimentary basins have being are field experimented. The initial are encouraging and on par with U.S. producing shale.

The shale gas production pressure are generally low but length of production on period compensates by volume.

Shale (Gas) Properties Conventional gas reservoirs:• created when natural gas migrates toward

the earth’s surface from an organic-rich source formation into highly permeable reservoir rock, where it is trapped by an overlying layer of impermeable rock.

Shale gas resources:• form within the organic-rich shale source

rock.• The very low permeability of the shale

greatly inhibits the gas from migrating to more permeable reservoir rocks towards the surface.

• The gas is held in natural fractures or pore spaces, or is adsorbed onto organic material (kerogen) in the shale which is the source material for all hydrocarbon resources.

Generally, the higher the TOC (Total amount of Organic material) the better the potential for hydrocarbon generation.

The amount and distribution of gas within the shale is determined by the initial reservoir pressure, the petrophysical properties of the rock, and its adsorption characteristics.

Shale gas is natural gas that is produced from a type of sedimentary rock derived from clastic sources often including mudstones or siltstones, which is known as ‘shale’.

Shales can be the source of the hydrocarbons that have migrated upwards into the reservoir rock. Shales contain organic matter (‘kerogen’) which is the source material for all hydrocarbon resources.

As the rock matures, hydrocarbons are produced from the kerogen. Hydrocarbons (a liquid or a gas) may then migrate through existing fissures and fractures in the rock until they reach the earth’s surface or until they become trapped by strata of impermeable rock.

The very low permeability of the rock causes the rock to trap the gas and prevent it from migrating towards the surface. The shale gas can be held in natural fractures or pore spaces, or can be adsorbed onto organic material.

Aside from permeability, the key properties of shales when considering gas potential are:• Total amount of Organic Content (‘TOC’,

kerogen in the rock)• Thermal maturity

Generally, the higher the TOC, the better the potential for hydrocarbon generation.

The thermal maturity of the rock is a measure of the degree to which organic matter contained in the rock has been heated over time, and potentially converted into liquid and/or gaseous hydrocarbons.

Shale Gas Challenges and Solutions

Key Techniques for Shale Gas Production Due to very low permeability, special well design

and well stimulation techniques are required to deliver production rates of sufficient levels to make a development economic.

Horizontal drilling and fracture stimulation are crucial in the development of the shale gas.

Horizontal Drilling Horizontal drilling allows the wellbore to come

into contact with significantly larger areas of hydrocarbon bearing rock than in a vertical well.

Hydraulic Fracture Stimulation Hydraulic fracture stimulation (‘fracking’) is

a process to create a large number of fractures in the rock, thus allowing the natural gas trapped in formations to move through those fractures to the wellbore.

Fracturing can both increase production rates and increase the total amount of gas. Pump pressure causes the rock to fracture, and water carries sand (‘proppant’) into the hydraulic fracture to prop it open allowing the flow of gas.

Whilst water and sand are the main components of hydraulic fracture fluid, small amount of chemical additives are often added to improve fracturing performance.

Horizontal Drilling & Fracturing

Hydraulic Fracturing Fluid Fracturing Fluid

Fracturing fluid is a mixture of water, proppants, and chemical modifiers.

Proppants are small particles of sand or engineered materials, such as resins or ceramics.

Proppants flow with the fracturing fluid and hold the fractures open, maintaining porosity as the pressure decreases in the formation with the return of fracturing fluid and gas to the surface.

The mixture of chemical modifiers is determined by site characteristics.

Source: Chesapeake—Hydraulic Fracturing Fact Sheet

Hydraulic Fracturing Fluid

Purposes of the Typical Constituents of Hydraulic Fracturing FluidProduct Purpose Downhole Result

Water and Sand: >98%

Water Expand fracture and de-liver sand

Some stays in formation while remainder returns with natural formation water as “produced water” (actual amounts returned vary from well to well).

Sand Proppants Allows the fractures to remain open so the gas can escape

Stays in formation, embedded in fractures (used to “prop” fractures open).

Other additives: <2%

Acid Helps dissolve minerals and initiate cracks in the rock

Reacts with minerals present in the formation to create salts, water, and carbon dioxide (neutralized).

Corrosion Inhibitor Prevents the corrosion of the pipe

Bonds to metal surfaces (pipe) downhole. Any remaining product not bonded is broken down by microorganisms and consumed or returned in produced wa-ter.

Iron Control Prevents precipitation of metal (in pipe)

Reacts with minerals in the formation to create simple salts, carbon dioxide and water all of which are returned in produced water.

Product Purpose Downhole Result

Other additives: <2%

Anti-Bacterial Agent Eliminates bacteria in the water that produces corrosive byproducts

Reacts with micro‐organisms that may be present in the treatment fluid and formation. These microorganisms break down the product with a small amount of the product returning in produced water.

Scale Inhibitor Prevents scale deposits downhole and in sur-face equipment

Product attaches to the formation downhole. The majority of product returns with produced water while remaining reacts with micro‐organisms that break down and consume the product.

Friction Reducer “Slicks” the water to minimize friction

Remains in the formation where temperature and exposure to the “breaker” al-lows it to be broken down and consumed by naturally occurring microorgan-isms. A small amount returns with produced water.

Surfactant Used to increase the viscosity of the fracture fluid

Generally returned with produced water, but in some formations may enter the gas stream and return in the produced natural gas.

pH Adjusting Agent Maintains the effec-tiveness of chemical additives

Reacts with acidic agents in the treatment fluid to maintain a neutral (non‐acidic, non‐alkaline) pH. Reaction results in mineral salts, water and carbon dioxide which is returned in produced water.

Monitoring Fracture Treatments Micro-seismic Hydraulic Fracture Monitoring During the fracturing process, the pressure

created by the pumping of fracture fluids creates stress on individual contact points within the reservoir rocks.

As these points fracture, the movement at the point creates a micro seismic event which can be recorded by offsetting monitoring wells or seismic arrays using extremely sensitive detectors.

This process for monitoring fracture treatments is commonly referred to as micro-seismic monitoring.

Surface Production Facilities

Overall Description of Block Flow Diagram

Incoming gas goes through a slug catcher and an inlet separator to remove any free liquids.

Liquids separated from the slug catcher go to a condensate stabilizer to meet the specification of the condensate of normally 9 ~ 12psia of RVP.

* RVP (Reid Vapor Pressure, @100°F) Gas from the separator goes through an amine unit to

remove acid gases such as CO2 and H2S. Sweetened gas from the amine unit is sent through

glycol dehydration units followed by molecular sieve dehydration to remove the water to the ppm level in order to prevent hydrate formation in the systems and/or pipelines.

NGL can be recovered by cryogenic process.

Slug Catcher The produced fluids (gas) flow to the Slugcatcher via gathering

lines from CPFs. The Slugcatcher provides for bulk separation of liquid and gas and acts as a storage buffer for slugging and sphering operations.

It is intended to regularly sphere the pipeline to control slug volumes entering the Slugcatcher which has been designed for a slug handling capacity (‘transient analysis’).

Liquid from the Slugcatcher is sent into the condensate stabiliser.

Gas is sent into the Inlet Separator where any liquid carryover droplets are removed. The pressure in the separator is maintained at a fixed set point by controlling the gas flow from the Slugcatcher. This strategy ensures that pipeline slugging and sphering do not cause pressure fluctuation (swings) in the gas process.

Sweetening Process (Amine Process) cont’d

Natural gas consists of the followings light components:

• methane(CH4), ethane(C2H6), propane(C3H8), and

butane(C4H10)

• small amounts of heavier hydrocarbons such as pentane, hexane, and heptane. A mixture of natural gas heavier than butane is called natural gasoline, ‘C5+’.

Natural gas contains impurities called ‘acid gases’ as the following:

• hydrogen sulphide(H2S), carbon dioxide(CO2), and

carbonyl sulphide(COS), etc. and these are also called ‘sour gas’.

• The impurities must be removed to meet the specifications of NGL.

The presence of sour gas would cause severe corrosion problems, especially where free water is present.

When the acid gases have been removed it is called ‘Sweet Gas’. Changing sour gas into sweet gas is called ‘sweetening’ and ‘amine process’ is widely used for a gas sweetening.

Sweetening Process (Amine Process) cont’d

The feed gases are contacted with an ‘amine solution’. An amine solution is an alkaline solution which attracts and absorbs acid gases. There is a chemical reaction between the amine solution and the acid gases called ‘absorption process’.

Absorption process takes place in an ‘amine contactor’. The sour gas comes into contact with the amine solution. When the sour gas is contacted with the amine solution the acid gases are removed but the hydrocarbons remain in the gas.

Sweetening Process (Amine Process) cont’d

The sweetened gas leaves the top of the column it contains in ppm level of H2S and CO2. The amine which comes out from the bottom of the column has absorbed a lot of acid gases which is called ‘rich amine’.

The acid gases is removed from the rich amine and the solution is used again. Removing the acid gas from the rich amine is called ‘regeneration’ and it takes place in an ‘amine regenerator’. The regenerated amine is called ‘lean amine’

Glycol Dehydration Glycol and wet gas are brought into

intimate contact in a contactor. Glycol absorbs water vapour from the

gas. The wet glycol, water rich glycol is regenerated by fractionation in a still column and reboiler where the rich glycol is heated and the absorbed water vapour boiled off.

The regenerated lean glycol is cooled and pumped back into the contactor.

The regenerator may produce the regenerated glycol containing approximately 0.9% ~ 0.05% water.

Mol-Sieve Dehydration Water in wet gas from glycol dehydration unit should

be further removed in molecular sieve to the ppm level to avoid the formation of hydrates in NGL recovery process and to protect the system.

Mol-sieve dehydration contains two or three towers filled with dry desiccant.

The gas flows through an inlet separator where free liquids and solid particles are removed. Free hydrocarbon liquid should be removed because they may damage the desiccant bed and solids may plug it.

Then the gas flows to the tower in the adsorption cycle and passes from top to bottom through the desiccant bed where natural gas and water vapours are adsorbed. Natural gas are preferentially adsorbed, but as the gas continues to pass they are gradually displaced by water. When the desiccant is saturated with water, the gas stream is switched to the second tower and the first tower is regenerated.

Cryogenic Process (Natural Gas Liquid Recovery) Generally the NGL recovery process consists of

the following three main stages.• Feed Gas Compression and 1st Chilldown• Vapour and Liquid Dehydration• 2nd Chilldown, Expander/Compressor and

Demethaniser. The gas from mol-sieve dehydrations is cooled

by mechanical refrigeration, back exchange with cold residue gas, and NGL, as well as expansion through a turbo-expander.

The turbo-expander extracts energy from the inlet gas by expanding it from about ~1000 psig to ~ 200 psig while recompressing the low pressure sales gas.

Expansion of the gas through the turbo-expander reduces the temperature of the gas to about -100°C.

Produced Water Management

Drilling and Hydraulic Fracturing During the flowback period which usually lasts up to two

weeks, approximately 10 ~ 40% of the fracturing fluid returns to the surface.

The volume of flowback depends on the formation characteristics and operating parameters. Once active gas production has begun, aqueous and nonaqueous liquid continues to be produced at the surface in much lower volumes (2~8 m3/day) over the lifetime of the well.

These wastewater, known as ‘produced water’ contains very high TDS concentrations as well as heavy and light petroleum hydrocarbons to be separated and recovered from water.

Water Resources The amount of water for the drilling per well

is approximately 400 ~ 4,000m3. This water is used to maintain downhole hydrostatic pressure, cool the drillhead, and remove drill cuttings.

The amount of water for hydraulic fracturing of each well is about 7,000 ~18,000m3.

These large volumes of water are typically obtained from surface waters or pumped from a municipal source.

However, in regions where natural water sources are scarce, the limited availability of water may be a significant impediment to gas resource development.

The highest rate of flowback occurs on the first day, and the rate diminishes over time; the typical initial rate is 1,000 m3/d(≈ 6,290bbl/d).

The composition of the flowback water changes as a function of the time.

Minerals and organic constituents in the formation dissolve into the fracturing water, creating a brine solution which includes high concentrations of salts, metals, oils, and soluble organic compounds.

The flowback water is impounded at the surface for subsequent disposal, treatment, or reuse.

Large volumes of the water containing very high levels of total dissolved solids (TDS) return to the surface as the produced water (‘flowback’).

The TDS concentration in the produced water can reach 5 times that of sea water.

Currently, deep-well injection is the primary means of management. However, deep-well injection sites are not available in many areas.

Therefore, water management strategies and treatment technologies of flowback water that will enable environmentally sustainable and economically feasible natural gas extraction will be critical for the development of the shale gas.

What is TDS (Total Dissolved Solids)? the total amount of mobile charged ions, including

minerals, salts or metals dissolved in a given volume of water

expressed in units of mg per unit volume of water (mg/L), or parts per million (ppm).

directly related to the purity of water and affects everything that consumes, lives in, or uses water, whether organic or inorganic.

Why should we measure and remove the TDS in the water?

The EPA (Environmental Protection Agency, USA) advise a maximum contamination level of 500mg/L (500ppm) for TDS.

When TDS exceed 1000mg/L, it is considered unfit for human consumption.

A high level of TDS is an indicator of potential concerns. High levels of TDS are caused by the presence of potassium (K), Chlorides (Cl), and Sodium (Na). These ions have little or no short-term effects, but toxic ions (lead arsenic, cadmium, nitrate, etc) may also be dissolved in the water.

It is not strictly permitted that discharging of the produced waters including flowback water that contain high TDS levels into the environment without proper water treatment to protect groundwater and surface water resources.

Option of the produced water management

Benefits Challenges

Injection - Can be a low-cost option- Well-established and (mostly) widely accepted

disposal method- Several States encourage as the preferred option

- Limited UIC(Underground Injection Control) well capacity/locations in some shale plays

- Lack of near-by wells creates transportation issues

Surface Discharge

- Returns water to the local ecosystem- Reduces disposal volume- Can help community relations- Can be a cost-effective management option

- Treatment required- Shale gas produced water not conducive to

most beneficial uses∙ Small volume/well with scattered sources∙ Water production is episodic and moves over time

- Disposal of treatment concentrate- Regulatory requirements- Potential environmental issues

Reuse - Reduced withdrawals and associated concerns- Reduced disposal needs- Reduced environmental concerns

- Blended water must be suitable for fracture fluid

- May require treatment for TDS, scale, microbes

- Not necessarily a ‘no-treatment’ option

Treatment for Surface Discharge Thermal Distillation & Crystallization

• These technologies use evaporating the produced water to separate the water from its dissolved constituents.

• Distillation removes up to 99.5% of dissolved solids and is estimated to reduce treatment costs by as much as 75% for produced water.

• Thermal distillation can treat flowback water containing up to, and in some cases even exceeding, 125,000 mg/L of TDS, but the technology is limited to low flow rates (300 m3/d).

• Mechanical vapor-compression systems to concentrate flowback water and to create dry mineral crystals (i.e. crystallization) improves water recovery.

• Crystallization is a feasible approach for treating flowback water with TDS concentrations as high as 300,000 mg/L, with requirement of high energy requirements and large capital costs.