Introduction to Shale Gas

Introduction to Shale Gas
Jinjung Kim

Shale Gas vs. Conventional Gas

Shale Gas vs. Conventional Gas
Natural Gas Resources-Two Categories Conventional Gas is typically found in reservoirs with permeabilities greater than 1 millidarcy(mD) and can be extracted via traditional techniques. is relatively easy and inexpensive to extract. A large proportion of the gas produced is conventional. Unconventional Gas is found in reservoirs with relatively low permeabilities (< 1mD) and hence cannot be extracted via conventional methods.

Shale Gas vs. Conventional Gas (cont’d)
Natural Gas Resources-Two Categories Unconventional Gas the three most common types of unconventional gas resources: tight gas, coal bed methane, shale gas Given the low permeability of these reservoirs, the gas must be developed via special techniques including fracture stimulation (or ‘fraccing’) to be produced commercially.

Gas Reservoir Types Matrix Permeability Increases Conventional Unconventional Conventional Gas MilliDarcy Range (>1mD) Fluid type varies Rock type varies Complex Gas Retrograde Gas with High Dew Point MilliDarcy Range (Relatively low permeability ~ 1mD or less) Sandstone Tight Gas Micro Darcy Range Dry Gas - Wet Gas Primarily Sandstone Shale Gas NanoDarcy Range Mostly free gas - some adsorbed gas CBM (Coal Bed Methane) Flow mostly trough fractures (cleats) Adsorbed Dry Gas Coal Source: Halliburton

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.

Source: US Energy Information Administration

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.

Shale Gas Challenges and Solutions
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. Fracking 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.

Overview of Hydraulic Fracturing for Shale Gas
Source: Encyclopedia Britannica, Inc.

Hydraulic Fracturing for Shale Gas Production
Overview of Hydraulic Fracturing for Shale Gas Production

Hydraulic Fracturing for Shale Gas Production

Hydraulic 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

Purposes of the Typical Constituents of Hydraulic Fracturing Fluid Product Purpose Downhole Result Water and Sand: >98% Water Expand fracture and deliver 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 water. 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. Source: Chesapeake—Water Use Fact Sheet

Purposes of the Typical Constituents of Hydraulic Fracturing Fluid, cont’d 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 surface 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” allows it to be broken down and consumed by naturally occurring microorganisms. 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 effectiveness 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. Source: Chesapeake—Water Use Fact Sheet

Monitoring Fracture Treatments
Micro-seismic Hydraulic Fracture Monitoring Source: Geospace Technologies

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 Block Diagram for Surface Facilities
Abbreviation CPF: Central Production Facilities CGF: Central Gathering Facilities CDP: Central Delivery Point LACT: Lease Automatic Custody Transfer stands for LACT (Flow Meter) F CDP CGF CPF Production Wells Oil & Gas Oil Gas Truck Loading Sales Oil Pipeline F Oil Handling Facilities Sales Gas Pipeline Mixing Condensate if required * Based on Anadarko Gas Processing Plant CGF and CDP consists of the followings: Slug Catcher Condensate Stabilizer Amine Process (Sweetening), 1st Dehydration (TEG), 2nd Dehydration (Mol-Sieve), Cryogenic Plant Process, Produced (Waste) Water Treatment, Tanks, etc. 10~15 wells connected to one CPF CPF consists of the followings: Separators, Compressor, Tanks, Produced (Waste) Water Treatment, LACT, etc.

Example: Block Flow Diagram of CGF and CDP
To Export Pipeline Slug Catcher Inlet Separator Condensate Stabilizer RVP < 9psia Condensate Storage Tank Condensate Liquid-Gas Two Phase Stream Sour Gas Glycol Dehydration Dry Gas Lean Glycol Rich Glycol Water Vapor Acid Gas to Thermal Oxidizer To Gas Treating Scrubber Slop Oil Tank Mol. Sieve Dehydration Water NGL Products Cryogenic Process De-Methanizer Residue Gas Gas/Gas HX Compressor Amine Process (Sweetening) Lean Amine Rich Amine Sweetened Gas Regenerator Flare Stack Thermal Oxidizer Incoming Gas - Gathering Lines

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 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.

Description of Block Flow Diagram
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)

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 Wet Gas Dry Gas Rich TEG INLET SCRUBBER TEG CONTACTOR COLDFINGER REFLUX CONDENSER TEG PREHEATER HX RICH TEG FLASH DRUM Flashed Gas CHARCOAL FILTER Liquid Hydrocarbons CARTRIDGE FILTER RICH/LEAN TEG HX STILL COLUMN REBOILER Vapors to Vapor Recovery Unit SURGE DRUM Condensate TEG CIRCULATION PUMP STAND PIPE LEAN TEG / DRY GAS HX TC Lean TEG LC HEATING BUNDLE Heating Medium Free Liquid * This system was applied in Donghae-1 Gas Plant.

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 Sweet Dry Gas to Cryogenic Process Heating Medium Supply Sweet Wet Gas from TEG Unit A B C Filter Regen Gas Filter 1st Heater Three Tower Desiccant Dehydrator Mol. Sieve Outlet Filter Regen Gas Cooler - adsorption: downflow, - regeneration: upflow for heating, - cooling: downflow Heating Medium Return 2nd Heater

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 (NGL, Natural Gas Liquid Recovery) Example

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
Water Usage for both Drilling and Hydraulic Fracturing Hydraulic fracturing involves the introduction of aqueous fracturing fluid to raise the downhole pressure above the fracture pressure of the formation rock and to create fissures and interconnected cracks. After hydraulic fracturing, the pumping pressure is relieved and the fracture fluid returns to the surface through the well casing. This water is referred to as ‘flowback’. Hydraulic fracturing is commonly a one-time event, performed in stages. However, additional hydraulic fracturing may be performed over the lifetime of the well, if necessary. About 4.5 million gallons (≈ 17,000m3 = 100,000bbls) of water for the fracturing of a typical horizontal well is required. See the figure iThe water is trucked to the drilling location or transported via temporary pipelines.

Schematic Geology of Horizontal Drilling and Fracking

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.

Management of Flowback Water 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.

Management of Flowback Water 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.

Management of Flowback Water Growing public concern about the flowback water due to the potential for human health and environmental impacts is associated with an accidental release of the flowback water into the environment: the large water volume, the high concentration of dissolved solids, and the complex physicochemical composition

Three options for the produced water management Underground Injection-most common? Surface Discharge Reuse Goals of the produced water treatment Reduce TDS (Total Dissolved Solids, desalination) for discharge Reduce volume for disposal Reduce TDS, scaling, and/or bio-fouling for reuse or UIC(Underground Injection Control)

Water Management Challenges
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 Challenges Shale gas produced water quality varies between formations, within formations, and over time High TDS concentrations limit treatment options. All treatment processes result in a waste stream, liquid, solid, or both. CAPEX/OPEX-related issues.

Logistics/Practical Considerations Sources of the produced water change over time as new wells are drilled and development expands. Treatment facility location: Mobile? Permanent? Semi-permanent? Treatment facility ownership: Commercial? Owned and run by operator? Contracted by operator? Treatment for Surface Discharge Available Technologies Reverse Osmosis Thermal Distillation and Crystallization * It is the same with the water treatment method, Mechanical Vapor Compression which is widely used at oil sand development in Canada.

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.

Water Treatment System-Mechanical Vapor Compression Vertical Tube Falling Film Vapor Compression Evaporator Schematic Source: GE Ionics

Water Treatment-MVC and Crystalllizer MVC and Crystalllizer System (Zero Liquid Discharge) Source: GE Ionics

Shale Gas Development Workflow
Evaluate Potential (Shale Screening) Shale Formation Characterization Data Validation and Evaluation Potential Exploitation Program Organic Shale Interval - Potential hydrocarbon presence. Review of data - Seismic - Geological geochemical - Geomechanical data Petrophysical - Mineralogy, Φ, TOC, - RO, Brittle, k - Fluid typing. Define data requirements - Core, well log etc. Workover candidate to identify production potential Reservoir Extension Estimated Principal Stresses Directions Identification of Natural Fractures Estimation of Mechanical Properties Geochemical Properties Petrophysical Properties Estimated Mineralogy - Spectral Gamma Ray - Chemostratigraphy - Cores DFIT (Diagnostic Fracture Injection Test) Analysis Determine Shale Analog Drilling - Casing Program - Bit Selection - Mud Program - Trajectory - Sidetracking - Data Acquisition Hydraulic Fracturing - Completion Perforation Strategy Material Selection: Fluids, Additives, Proppants -Stimulation Design: Job Size, Hydraulic Horsepower, Logistics & Environmental Impact Evaluation -Production Potential -Fracture Monitoring Lessons Learned/Best Practices Well Placement -Reservoir drainage Well architecture to maximize production -Vertical/high angle -Horizontal -Multilateral Water Management Logistics Source: Halliburton

생산시설 설계 시 고려할 사항??? Shale Gas 생산 surface facilities 구성은 초기 hydraulic fracturing과 생산수 처리 (재생)과정을 제외하고는 전반적으로 일반 가스전 처리 공정과 비슷함. Well streams에 포함된 sour gas 함량에 따라 sweetening process가 요구되기도 하는데 이것이 일반적임. 동해-1 및 베트남 11-2 의 경우 sweetening process가 없는 것은 타 가스 플랜트와 비교 시 가스가 너무 깨끗하기 때문임. 생산량에 따라 다르겠으나 amine unit은 plot space를 많이 차지하며 운전하기가 불편하고 OPEX가 많이 소요됨. Shale gas well stream은 대부분 wet sour gas이므로 재질 선정 시 고려해야 함. 수많은 well들을 연결하기 위한 gathering line (system)과 제품 판매를 위한 pipeline 설계 및 운영이 중요함. Transient Analysis 요구됨. Hydraulic fracturing에 필요한 막대한 water sources와 공급 방법(trucking 혹은 pipelines?)에 대한 조사 매우 중요. 생산수 처리 장치 (Water Treatment System) 투자비 및 운전 비용 (CAPEX, OPEX-waste disposal cost/high energy, transportation, logistics 등)이 높을 것으로 예상되며, 실제 적용 가능한 수처리 기술선택의 어려움 존재. 수시로 바뀌고 강화되는 대기, 수질, 토양 등 환경 법규(규제) 파악이 매우 중요. 전기 공급, 도로 등 infrastructure 고려. Shale gas의 국내 도입을 전제로 생산할 경우 가스를 LNG로 만들기 위한 LNG terminal 건설이 요구되는데 경제성 고려 시 매장량은 최소 10 TCF이어야 함. (2000년 초 기준) . 지역적 특성 고려 요구됨. Shale gas 공정 처리 후 최종 제품은 크게 residue gas, NGL, 그리고 condensate로 나뉘어 지는데 시장 상황을 고려, 선택적 제품 생산을 위한 설계가 필요함. Swing factor ? 적용. ??????

Introduction to Shale Gas

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