Sodapdf-merged-merging Result-2-1.pptx

GAS PRODUCTION ENGINEERING FUNDAMENTALS Introduction The role of a production engineer is to maximize oil and gas production in a cost-effective manner. Fig. 4.1,shows a complete oil or gas production system consists of a reservoir, well, flowline, separators, pumps, and transportation pipelines. The reservoir supplies well-bore with crude oil or gas.

Reservoir Hydrocarbon accumulations in geological traps can be classified as reservoir, field, and pool. A ‘‘reservoir’’ is a porous and permeable underground formation containing an individual bank of hydrocarbons confined by impermeable rock or water barriers and is characterized by a single natural pressure system. A ‘‘field’’ is an area that consists of one or more reservoirs all related to the same structural feature. A ‘‘pool’’ contains one or more reservoirs in isolated structures. Hydrocarbon accumulations are classified as oil, gas condensate, and gas reservoirs. Reservoir Condition is shown in Fig. 4.2

An oil that is at pressure above its bubble point pressure is called an “unsaturated oil” because it can dissolve more gas at the given temperature. An oil that is at its buuple point pressure is called a “saturated oil” because it can dissolve no more gas at the given temperature. Single phase flow prevails in an undersaturated oil reservoir, where as two-phase (liquid oil and free gas) flow exists in a saturated oil reservoir. The reservoirs at and above dew point are classified as gas reservoirs.

Gas Reservoirs In general, if the reservoir temperature is above the critical temperature of the hydrocarbon system, the reservoir is classified as a natural gas reservoir. On the basis of their phase diagrams and the prevailing reservoir conditions, natural gases can be classified into four categories: • Retrograde gas-condensate • Near-critical gas-condensate • Wet gas • Dry gas

Retrograde gas-condensate reservoir: Ifthe reservoir temperature T lies between the critical temperature Tc and cricondentherm Tct of the reservoir fluid, the reservoir is classified as a retrograde gas-condensate reservoir. This category of gas reservoir is a unique type of hydrocarbon accumulation in that the special thermodynamic behavior of the reservoir fluid is the controlling factor in the development and the depletion process of the reservoir. When the pressure is decreased on these mixtures, instead of expanding (if a gas) or vaporizing (if a liquid) as might be expected, they vaporize instead of condensing. Consider that the initial condition of a retrograde gas reservoir is represented by point 1 on the pressure-temperature phase diagram of Figure 4.2b.

Because the reservoir pressure is above the upper dew-point pressure, the hydrocarbon system exists as a single phase (i.e., vapor phase) in the reservoir. As the reservoir pressure declines isothermally during production from the initial pressure (point 1) to the upper dew-point pressure (point 2), the attraction between the molecules of the light and heavy components causes them to move further apart further apart. As this occurs, attraction between the heavy component molecules becomes more effective; thus, liquid begins to condense.

This retrograde condensation process continues with decreasing pressure until the liquid dropout reaches its maximum at point 3. Further reduction in pressure permits the heavy molecules to commence the normal vaporization process. This is the process whereby fewer gas molecules strike the liquid surface and causes more molecules to leave than enter the liquid phase. The vaporization process continues until the reservoir pressure reaches the lower dew-point pressure. This means that all the liquid that formed must vaporize because the system is essentially all vapors at the lower dew point. In most gascondensate reservoirs, the condensed liquid volume seldom exceeds more than 15%–19% of the pore volume.

This liquid saturation is not large enough to allow any liquid flow. It should be recognized, however, that around the wellbore where the pressure drop is high, enough liquid dropout might accumulate to give two-phase flow of gas and retrograde liquid. The associated physical characteristics of this category are: Gas-oil ratios between 8,000 to 70,000 scf/STB. Generally, the gas- oil ratio for a condensate system increases with time due to the liquid dropout and the loss of heavy components in the liquid. • Condensate gravity above 50° API • Stock-tank liquid is usually water-white or slightly colored. •

There is a fairly sharp dividing line between oils and condensates from a compositional standpoint. Reservoir fluids that contain heptanes and are heavier in concentrations of more than 12.5 mol% are almost always in the liquid phase in the reservoir. Oils have been observed with hep-tanes and heavier concentrations as low as 10% and condensates as high as 15.5%. These cases are rare, however, and usually have very high tank liquid gravities.

Near-critical gas-condensate reservoir. If the reservoir temperature is near the critical temperature, as shown in Figure 4.2c, the hydrocarbon mixture is classified as a near-critical gas-condensate. The volumetric behavior of this category of natural gas is described through the isothermal pressure declines as shown by the vertical line 1-3 in Figure 4.2c. Because all the quality lines converge at the critical point, a rapid liquid buildup will immediately occur below the dew point as the pressure is reduced to point 2 This behavior can be justified by the fact that several quality lines are crossed very rapidly by the isothermal reduction in pressure. At the point where the liquid ceases to build up and begins to shrink again, the reservoir goes from the retrograde region to a normal vaporization region.

Wet-gas reservoir. A typical phase diagram of a wet gas is shown in Figure 4.2d, where reservoir temperature is above the cricondentherm of the hydrocarbon mixture. Because the reservoir temperature exceeds the cricondentherm of the hydrocarbon system, the reservoir fluid will always remain in the vapor phase region as the reservoir is depleted isothermally, along the vertical line A-B. As the produced gas flows to the surface, however, the pressure and temperature of the gas will decline. If the gas enters the two-phase region, a liquid phase will condense out of the gas and be produced from the surface separators.

This is caused by a sufficient decrease in the kinetic energy of heavy molecules with temperature drop and their subsequent change liquid through the attractive forces between to Wet-gas reservoirs are characterized by the molecules.properties: following • Gas oil ratios between 60,000 to 100,000 scf/STB • Stock-tank oil gravity above 60° API • Liquid is water-white in color • Separator conditions, i.e., separator pressure and temperature, lie within the two-phase region.

Dry-gas reservoir: The hydrocarbon mixture exists as a gas both in the reservoir and in the surface facilities. The only liquid associated with the gas from a dry-gas reservoir is water. A phase diagram of a dry-gas reservoir is given in Figure 4.2e. Usually a system having a gas-oil ratio greater than 100,000 scf/STB is considered to be a dry gas. Kinetic energy of the mixture is so high and attraction between molecules so small that none of them coalesce to a liquid at stock-tank conditions of temperature and pressure. It should be pointed out that the classification of hydrocarbon fluids might be also characterized by the initial composition of the system.

From the foregoing discussion, it can be observed that hydrocarbon mixtures may exist in either the gaseous or liquid state, depending on the reservoir and operating conditions to which they are subjected. The qualitative concepts presented may be of aid in developing quantitative analyses. Empirical equations of state are commonly used as a quantitative tool in describing and classifying the hydrocarbon system

Wells in the same reservoir can fall into categories of oil, condensate, and gas wells depending on the producing gas–oil ratio (GOR).Gas wells are wells with producing GOR being greater than 100,000 scf/stb; condensate wells are those with producing GOR being less than 100,000 scf/stb but greater than 5,000 scf/stb; and wells with producing GOR being less than 5,000 scf/stb are classified as oil wells. wells Oil and gas wells are drilled like an upside-down telescope. The large-diameter borehole section is at the top of the well. Each section is cased to the surface, or a liner is placed in the well that laps over the last casing in the well. Each casing or liner is cemented into the well

The ‘‘wellhead’’ is defined as the surface equipment set below the master valve. As we can see in Fig. 4.3, it includes casing heads and a tubing head. The casing head (lowermost) is threaded onto the surface casing. This can also be a flanged or studded connection. A ‘‘casing head’’ is a mechanical assembly used for hanging a casing string (Fig. 4.4). Depending on casing programs in well drilling, several casing heads can be installed during well construction.

Most flowing wells are produced through a string of tubing run inside the production casing string. At the surface, the tubing is supported by the tubing head (i.e., the tubing head is used for hanging tubing string on the production casing head [Fig. 4.5]). The equipment at the top of the producing wellhead is called a ‘‘Christmas tree’’ (Fig. 4.6) and it is used to control flow. The ‘‘Christmas tree’’ is installed above the tubing head. An ‘‘adaptor’’ is a piece of equipment used to join the two. The ‘‘Christmas tree’’ may have one flow outlet (a tee) or two flow outlets (a cross).

A Christmas tree consists of a main valve, wing valves, and a needle valve. These valves are used for closing the well when needed. At the top of the tee structure (on the top of the ‘‘Christmas tree’’), there is a pressure gauge that indicates the pressure in the tubing. The wing valves and their gauges allow access (for pressure measurements and gas or liquid flow) to the annulus spaces (Fig. 4.7).

‘‘Surface choke’’ (i.e., a restriction in the flowline) is a piece of equipment used to control the flow rate (Fig. 4.8). In most flowing wells, the oil production rate is altered by adjusting the choke size. The choke causes back-pressure in the line. The back-pressure (caused by the chokes or other restrictions in the flowline) increases the bottomhole flowing pressure. Increasing the bottom-hole flowing pressure decreases the pressure drop from the reservoir to the wellbore (pressure drawdown). Thus, increasing the back-pressure in the wellbore decreases the flow rate from the reservoir

Surface vessels should be open and clear before the well is allowed to flow. All valves that are in the master valve and other downstream valves are closed. Then follow the following procedure to open a well: 1. The operator barely opens the master valve (just a crack), and escaping fluid makes a hissing sound. When the fluid no longer hisses through the valve, the pressure has been equalized, and then the master valve is opened wide. 2. If there are no gas/oil leaks, the operator cracks the next downstream valve that is closed. Usually, this will be either the second (backup) master valve or a wing valve. Again, when the hissing sound stops, the valve is opened wide.

3. The operator opens the other downstream valves the same way. 4. To read the tubing pressure gauge, the operator must open the needle valve at the top of the Christmas tree. After reading and recording the pressure, the operator may close the valve again to protect the gauge. The procedure for ‘‘shutting-in’’ a well is the opposite of the procedure for opening a well.

Flow Regimes When a vertical well is open to produce gas/oil at production rate q, it creates a pressure funnel of radius r around the wellbore, as illustrated by the dotted line in Fig. 4.9a. In this reservoir model, the h is the reservoir thickness, k is the effective horizontal reservoir permeability to gas, μg is viscosity of oil, Bg is gas formation volume factor, rw is wellbore radius, pwf is the flowing bottom hole pressure, and p is the pressure in the reservoir at the distance r from the wellbore center line. The flow stream lines in the cylindrical region form a horizontal radial flow pattern as depicted in Fig. 4.9b.

Transient Flow ‘‘Transient flow’’ is defined as a flow regime where/when the radius of pressure wave propagation from wellbore has not reached any boundaries of the reservoir. During transient flow, the developing pressure funnel is small relative to the reservoir size. Therefore, the reservoir acts like an infinitively large reservoir from transient pressure analysis point of view.

Steady-State Flow ‘‘Steady-state flow’’ is defined as a flow regime where the pressure at any point in the reservoir remains constant over time. This flow condition prevails when the pressure funnel shown in Fig. 4.9 has propagated to a constantpressure boundary. The constant-pressure boundary can be an aquifer or a water injection well. A sketch of the reservoir model is shown in Fig. 4.10, where pe represents the pressure at the constant-pressure boundary.

Pseudo–Steady-State Flow ‘‘Pseudo–steady-state’’ flow is defined as a flow regime where the pressure at any point in the reservoir declines at the same constant rate over time. This flow condition prevails after the pressure funnel shown in Fig. 4.9 has propagated to all no-flow boundaries. A no-flow boundary can be a sealing fault, pinch-out of pay zone, or boundaries of drainage areas of production wells. A sketch of the reservoir model is shown in Fig. 4.11, where pe represents the pressure at the no-flow boundary at time t4.

Introduction Mooring System: The mooring system consists of freely hanging lines connecting the surface platform to anchors, or piles, on the seabed, positioned at some distance from the platform. “Often laid out symmetrically in plan view around the object in question” Types of Mooring Lines: 1.

Steel-Linked chain

2.

Wire rope

3.

Synthetic fiber rope

Dept. of Chemical Engineering,VIT University.

30 December 2020

1. Steel-Linked chain 2. Wire rope The above two types of catenary lines are conventionally used for mooring floating platforms. Each of the lines forms a catenary shape, depending on an increase or decrease in line tension as it lifts off or settles on the seabed, to produce a restoring force as the surface platform is displaced by the environment. Thus a spread of lines generates a nonlinear restoring force to provide the station-keeping function. Dept. of Chemical Engineering,VIT University.

30 December 2020

This force increases with vessel horizontal offset and balances quasi-steady environmental loads on the surface platform. The equivalent restoring stiffness provided by the mooring is generally too small to influence wave frequency motions of the vessel significantly, although excitation by low-frequency drift forces can induce dynamic magnification in the platform horizontal motions and lead to high peak line tensions. The longitudinal and transverse motions of the mooring lines themselves can also influence the vessel response through line dynamics. Dept. of Chemical Engineering,VIT University.

30 December 2020

3. Synthetic rope To operate in more water depths, the suspended weight of mooring lines becomes a prohibitive factor. In particular, steel chains become less attractive at great water depths. Recently, advances in taut synthetic fibre rope technology have been achieved offering alternatives for deep-water mooring. Mooring systems using taut fibre ropes have been designed and installed to reduce mooring line length, mean- and low-frequency platform offsets, fairlead tension and thus the total mooring cost. (Still a lot of R&D in progress) Dept. of Chemical Engineering,VIT University.

30 December 2020

Mooring system design philosophy: Mooring system design is a trade-off between making the system compliant enough to avoid excessive forces on the platform, and making it stiff enough to avoid difficulties, such as damage to drilling or production risers, caused by excessive offsets. Easier to achieve for moderate water depths, but becomes more difficult as the water depth increases.

Dept. of Chemical Engineering,VIT University.

30 December 2020

Single Point Mooring (SPM): Excessive offsets are often observed due to the environmental factors on the mooring system. SPM have been developed to overcome this disadvantage. In this the lines are attached to the vessel at a single point. This connection point is located on the longitudinal centre line of the vessel. The vessel is then free to weathervane and hence reduce environmental loading caused by wind, current and waves. Dept. of Chemical Engineering,VIT University.

30 December 2020

Single Buoy Mooring (SBM): A typical early facility consisted of a buoy that serves as a mooring terminal. It is attached to the sea floor either by catenary lines, taut mooring lines or a rigid column. The vessel is moored to the buoy either by synthetic hawsers or by a rigid A-frame yoke. Turntable and fluid swivels on the buoy allow the vessel to weathervane, reducing the mooring loads.

Dept. of Chemical Engineering,VIT University.

30 December 2020

In order to further reduce the environmental loading on the mooring system from the surface vessel in extreme conditions, disconnectable turret mooring systems have also been developed. Here the connected system is designed to withstand a less harsh ocean environment, and to be disconnected whenever the sea state becomes too severe such as in typhoon areas.

Dept. of Chemical Engineering,VIT University.

30 December 2020

Functional requirements for the mooring system: 1. 2. 3. 4.

Offset limitations Lifetime before replacement Install-ability Positioning ability These requirements are determined by the function of the floater.

Dept. of Chemical Engineering,VIT University.

30 December 2020

Comparison of typical MODU and FPS mooring requirements: MODU

Floating Production

Design for 50-yr return period event. Anchors may fail in larger events.

Designed for 100 yr return period events.

Risers disconnected in storms

Risers remain connected in storm

Slack moorings in storm events to reduce line tensions

Moorings are usually not slacked because of risk to the risers, and lack of marine operators on board

Components designed for < 10 yr life

Components designed for > 10 yr life

Fatigue analysis not required

Fatigue analysis required

Life dynamics analysis not required

Life dynamics analysis required

Missing line load case not required

Missing line load case required 30

Dept. of Chemical Engineering,VIT University.

December 2020

Steel Chain or Wire Catenary lines: In the figure: Catenary mooring is deployed from point A on the submerged hull of a floating vessel to an anchor at B on the seabed. Some part between AB is resting on the seabed, & horizontal distance “a” is 520 times larger than the vertical dimension “b”. Dept. of Chemical Engineering,VIT University.

30 December 2020

As we shift the mounting point from A1to A4 the catenary line laying/resting varies from a significant length at A1 to none at A4. From a static point of view, the cable tension in the vicinity of point A is due to the total weight in sea water of the suspended line length. The progressive effect of line lift-off from the seabed due to the horizontal vessel movement from Al to A4 increases line tension in the vicinity of point A. This feature, coupled with the simultaneous decrease in line angle to the horizontal, causes the horizontal restoring force on the vessel to increase with vessel offset in a non-linear manner. Dept. of Chemical Engineering,VIT University.

30 December 2020

Synthetic Lines: For deep-water applications, synthetic fibre lines can have significant advantages over a catenary chain or wire because they are considerably lighter, very flexible and can absorb imposed dynamic motions through extension without causing an excessive dynamic tension.

Dept. of Chemical Engineering,VIT University.

30 December 2020

Additional advantages include the fact that there is reduced line length and seabed footprint, as depicted in the adjacent figure

This, causes reduced mean- and low-frequency platform offsets, lower line tensions at the fairlead and smaller vertical load on the vessel. This reduction in vertical load can be important as it effectively increases the vessel useful payload. Dept. of Chemical Engineering,VIT University.

30 December 2020

14

The disadvantages in using synthetics are that their material and mechanical properties are more complex and not as well understood as the traditional rope. This leads to over conservative designs that strip them of some of their advantages. Furthermore, there is little inservice experience of these lines. In marine applications this has led to synthetic ropes subject to dynamic loads being designed with very large factors of safety. Dept. of Chemical Engineering,VIT University.

30 December 2020

Important properties of synthetic lines to considered in design:    

Stiffness Hysteresis and heat build up Fatigue Other issues

Dept. of Chemical Engineering,VIT University.

30 December 2020

Stiffness: In a taut mooring system the restoring forces in surge, sway and heave are derived primarily from the line stretch. This mechanism of developing restoring forces mostly differs from the conventional steel catenary systems that develop restoring forces primarily through changes in the line catenary shape. This is made possible by the much lower modulus of elasticity of polyester compared to steel. The stretch characteristics of fibre ropes can extend from 1.2 to 20 times as much as steel, reducing induced wave and drift frequency forces. (Stiffness of line is a function of load & age) Dept. of Chemical Engineering,VIT University.

30 December 2020

Hysteresis and heat build up: The energy induced by cyclic loading is dissipated (hysteresis) in the form of heat. In addition, the chaffing of rope components against each other also produces heat. Cases are known in which the rope has become so hot that the polyester fibers have melted. This effect is of greater concern with larger diameters or with certain lay types because dissipation of the heat to the environment becomes more difficult.

Dept. of Chemical Engineering,VIT University.

30 December 2020

Fatigue: The fatigue behavior of a rope at its termination is not good. In a termination, the rope is twisted (spliced) or compressed in the radial direction (barrel and spike or resin socket). The main reason for this decreased fatigue life is local axial compression. Although the rope as a whole is under tension, some components may go into compression, resulting in buckling and damage of the fibres. In a slack line this mechanism is more likely to be a problem than in a rope under tension. The phenomenon can appear at any position along the rope. Dept. of Chemical Engineering,VIT University.

30 December 2020

Other relevant issues: Issues to consider are that the strength of a polyester rope is about half that of a steel wire rope of equal diameter. Additionally the creep behavior is good but not negligible (about 1.5% elongation over 20 years). Furthermore, synthetic fibre ropes are sensitive to cutting by sharp objects and there have been reports of damage by fish bite. A number of rope types such as high modulus polyethylene (HMPE) are buoyant in sea water; other types weigh up to 10% of a steel wire rope of equal strength. Synthetic fibre lines used within taut moorings require the use of anchors that are designed to allow uplift at the seabed. Dept. of Chemical Engineering,VIT University.

30 December 2020

Loading Mechanism on Mooring System: There are various loading mechanisms acting on a moored floating vessel as depicted in the previous figure are: For a specific weather condition, the excitation forces caused by current are usually assumed temporally constant, with spatial variation depending on the current profile and direction with depth. Wind loading is often taken as constant, at least, in initial design calculations, though gusting can produce slowly varying responses. Wave forces result in time-varying vessel motions in the 6 rigid body degrees of freedom of surge, sway, heave, roll, pitch and yaw. Wind gust forces can contribute to some of these motions as well. Mooring System Design  Static design  Quasi Static Design Dept. of Chemical Engineering,VIT University.  Dynamic Design

30 December 2020

Mooring Hardware Components The principle components of a mooring system may consists of:      

Chain, wire or rope or their combination Anchors or piles Fairleads, bending shoes or pad-eyes Winches, chain jacks or windlasses Power supplies Rigging (e.g. stoppers, blocks, shackles)

Dept. of Chemical Engineering,VIT University.

30 December 2020

Chain, wire or rope or their combination: Properties are given by “Det Norske Veritas OS-E301” codes. Chain and wire make up the strength members for the mooring system. There are primary 2 chain constructions: a) Stud-Link Chain (studs provide stability to the link and facilitate laying down of chain while handling.) b) Stud-less Chain (removing stud reduces the weight per unit of strength and increases the chain fatigue life, at the expense of making the chain less convenient to handle.) Dept. of Chemical Engineering,VIT University.

30 December 2020

Wire rope: Wire rope consists of individual wires wound in a helical pattern to form a “strand”. The pitch of the helix determines the flexibility and axial stiffness of the strand. Wire rope used for mooring can be multi-strand or single-strand construction. Stud-link chain and six-strand wire rope are the most common mooring components for MODUS and other “temporary” moorings. Dept. of Chemical Engineering,VIT University.

30 December 2020

Wire rope: Multi-strand ropes are favored for temporary applications because of their ease of handling. Six-strand rope is the most common type of multi-strand rope used offshore. Mooring line ropes typically consist of 12, 24, 37 or more wires per strand. The wires have staggered sizes to achieve higher strength Dept. of Chemical Engineering,VIT University.

30 December 2020

Common “classes” of multi-strand rope include (Myers, 1969): 6x7 class: 7 wires per strand, usually used for standing rigging. Poor flexibility and fatigue life, excellent abrasion resistance. Minimum drum diameter/rope diameter (D/d) = 42. 6x9 Class: 16 to 27 wires per strand. Good flexibility and fatigue life and abrasion resistance. Common in lifting and dredging. Minimum D/d = 26-33. 6x37 Class: 27 to 49 wires per strand. Excellent fatigue life and flexibility, but poor abrasion resistance. Minimum D/d = 1626. Dept. of Chemical Engineering,VIT University.

30 December 2020

Multi-strand wire ropes may contain either a fibre or a metallic core. The core is important for support of the outer wires, especially on a drum, and in some applications to absorb shock loading. Fibre core (FC) ropes are not generally used for heavy duty marine applications. Metallic core ropes may be one of the two types: a) Independent Wire Rope Core (IWRC) b) Wire-Strand Core (WSC). IWRC is the most common core filling for heavy marine applications. Dept. of Chemical Engineering,VIT University.

30 December 2020

Anchors or piles: Anchors are basically of two types, relying either on self-weight or suction forces. The traditional embedment anchors, as shown in figure, are not normally designed for vertical force components. Holding power is related to anchor weight and type of seabed.

Dept. of Chemical Engineering,VIT University.

30 December 2020

Turrets: The design of mono-hull turret structures used for single-point moorings in floating production systems must allow for large static and dynamic loading caused by the vessel motions in waves together with forces transmitted by the mooring system. The hull design in the turret region must reflect the fact that the amount of primary steel is reduced here with an appropriate increase in the stress concentration. Careful selection of turret position is important because of its influence on:  Mooring line tension and riser loading.  Vessel yaw  Rigid body oscillation in the horizontal plane Dept. of Chemical Engineering,VIT University.

30 December 2020

Mooring System Analysis: The mooring system is assessed in terms of three limit states based on the following criteria: Ensuring that individual mooring lines have suitable strength when subjected to forces caused by extreme environmental loads ultimate limit state (ULS). Ensuring that the mooring system has suitable reserve capacity when one mooring line or one thruster has failed - accidental limit state (ALS).  Ensuring that each mooring line has suitable reserve capacity when subject to cyclic loading - fatigue limit state (FLS). Dept. of Chemical Engineering,VIT University.

30 December 2020

Potential failure modes as given in standards: Hysteresis heating: lubricants and fillers can be included to reduce hotspots, creep rupture in particular this is relevant to HMPE yarns, and the risks need careful evaluation. -

 Tension: Tension fatigue-only limited data exist, indications being that fatigue resistance is higher than for steel wire ropes. Axial compression fatigue - on leeward lines during storms for example, prevented by maintaining a minimum tension on the rope. Particle ingress - causes strength loss by abrasion from waterborne material such as sand, prevented by using a suitable sheath and not allowing contact between the rope and seabed. Dept. of Chemical Engineering,VIT University.

30 December 2020

NATURAL GAS: OFFSHORE PRODUCTION & HANDLING

Lecture by M . A s l am A b d u ll a h

25 July 2020

School of Chemical Engineering, VIT University.

1

Process of Offshore Oil and Gas Developments The process of developing offshore oil and gas reserves can be divided into the following major steps: 1. Exploration 2. Exploratory drilling 3. Development drilling 4. Production 5. Storage and offloading 6. Transportation

25 July 2020

Dept.of Chemical Engineering, VIT University.

2

FACTORS DRIVING DEEPWATER RUSH 1.

Growing global demand for energy.

2.

Traditional fields fast exhausting.

3.

Declining production & reserves.

4.

Pressure to diversify supply.

5.

Oil supply jitters.

6.

Energy economics.

7.

Technological advent.

25 July 2020

Dept.of Chemical Engineering, VIT University.

3

DEEP WATER TECHNOLOGIES In order to meet the current demand for hydrocarbon based fuel, the scout for it is widespread with demanding impetus on technological innovations.

Problems associated with Offshore (deep water) areas are: 1. Reservoir characterization.

7. Tidal waves

2. Reservoir management.

8. Corrosion

3. Source- rock prediction.

9. Wind

4. Formation water properties.

10. Fatigue

5. Granite reservoir characterization.

11. Salinity

6. Pore pressure & temperature prediction.

25 July 2020

12. Thermal shock (steep gradient, seasonal change, fluid injection)

Dept.of Chemical Engineering, VIT University.

4

DEEP WATER TECHNOLOGIES Factors affecting field services in deep water on a macro-basis can be given as: 1. Unconventional oil (tar sands) vs. deepwater. 2. Novel Deepwater technology trends. 3. Drilling technologies. 4. Subsea technologies. 5. Forecast for deepwater oilfield services. 6. Hydrate formation. 7. High temperature High Pressure.

25 July 2020

Dept.of Chemical Engineering, VIT University.

5

DEEP WATER TECHNOLOGIES Classification of problems encountered in general: 1. Deepwater projects take up to 10 years from discovery to first production. 2. Geology not cooperating (Like finding 100MMbl pockets when we used to find 500MMbl to 1bln barrel fields). 3. Cluster developments are expensive (five (100MMbl) fields do not equal one (500MMbl) field). 4. Escalating rig rates were a leading indicator for the cost increases across the sector for deepwater developments.

25 July 2020

Dept.of Chemical Engineering, VIT University.

6

DEEP WATER TECHNOLOGIES To solve the deepwater issues it requires blend of many technologies like: 1. Reservoir geophysics seismic

6. Time-lapse

2. Seismic imaging stratiography

7. Seismic litho

3. Seismic signal processing drilling

8. Imaging while

4. 3D seismic characterization of reservoirs arrays

9. Ocean sensor

5. Multi-component seismology

25 July 2020

Dept.of Chemical Engineering, VIT University.

7

Location Surveys for Offshore Drilling The offshore environment has a much more significant influence on drilling operations than the onshore environment. It is necessary to carry out a suite of location surveys before starting drilling operations in order to obtain data such as weather forecast during drilling operations, bathymetric map around the location, current profiles, properties of the sea bottom soil, topography of the sea bottom, and shallow geological hazards. The minimum requirement of the survey includes following instruments: 1. 2. 3. 4. 5.

sparkers (Acoustic signal) sub-bottom profilers (Physical Properties) side-scan sonar (high frequency sound pulses) fathometers gravity corers (Sediment Extractor)

Wind and current measurements for several months would be carried out at a proposed location about one year ago before operations. 25 July 2020

Dept.of Chemical Engineering, VIT University.

8

History of Offshore 1. 1st offshore well was drilled in 1947 in 15 feet of water in (Louisiana, USA). 2. 30 years ago, a deepwater operation implies exploring water depths up to 500 feet. 3. Today, deepwater refers to a well in up to 5,000 feet (1524m) of water . 4.

Ultra-deepwater exploratory drilling now occurring in water depths over 5000 ft to 10,000 feet. i.e.,( 1524m to 3048m)

5. The challenges in ultra deep reserves are more complicated than exploring space.

25 July 2020

Dept.of Chemical Engineering, VIT University.

9

Classification of water depths  Shallow water generally refers to a depth less than 1000ft (304.8m).  Deep water refers to a depth greater than 1000ft (304.8m) and less than 5000ft (1524m).  Ultra-deepwater refers to a depth greater than 5000ft (1524m).

25 July 2020

Dept.of Chemical Engineering, VIT University.

10

Record depths achieved in Onshore/Offshore Onshore 1. The scientific research well “SG-3” in Russia reached the depth of 12,263 m in 1988, has had the depth record ever since. 2. The deepest exploration drilling for hydrocarbons was carried out to the depth of 9583 m in the United States of America in 1974.

Offshore 1. A hydrocarbon exploration well was drilled offshore Brazil in 2965 m of water in 2001. 2. A production well was completed with a subsea completion system offshore Brazil in 1852 m of water in 1998. The offshore technology is steadily in progress towards deeper and deeper seas to search and Dept.of Chemical Engineering, VIT 25 July 2020 produce subsea resources for the future welfare of the world. University.

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As per SPE publication: “Since 1947, the offshore industry has moved from the first platform out of sight of land to safely producing in 7,000 feet (2,100 meters) of water and safely drilling in 10,000 feet (3,050 meters) of water.”

The industry is still learning, and there is more to come…

25 July 2020

Dept.of Chemical Engineering, VIT University.

12

Offshore Drilling Structures Technical Features of Offshore Drilling 1. Because of the location remote from infrastructure, offshore rigs also carry on board a number of service systems such as cementing, geophysical logging, and so on. 2.

In addition, there are lots of specific services on board such as divers, meteorological measurements, helicopter, etc.

3. Accommodations and catering for crews working for 24 hours are required on the rig. All these factors make offshore rigs complex and sophisticated, and therefore Dept.of Chemical Engineering, VIT 25 July 2020 offshore drilling costs are higher thanUniversity. land drilling costs for similar

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There are two basic types of offshore drilling rigs:

Moveable rigs are often used for exploratory purposes because they are much cheaper to use than permanent platforms. Once large deposits of hydrocarbons have been found, a permanent platform is built to allow their extraction.

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Different types of moveable offshore platforms: Rigs that can be moved from place to place, allowing for drilling in multiple locations (Mobile bottom- supported and floating rigs). 1.

Drilling Barges.

2.

Jack-Up Rigs.

3.

Submersible Rigs (swamp barges).

4.

Semisubmersible Rigs (Anchor-stationed or dynamically positioned).

5.

Drillships (Anchor-stationed or dynamically positioned ).

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Drilling structures used for developing offshore fields from stationary platforms are of two types: Rigs that are permanently placed. 1.

Self-contained platforms: (The large production platform equips a complete set of drilling equipment, and is called as self-contained platform)

2.

Tender or jack-up assisted platforms or well-protector jackets :The small platform has a space only to accommodate derrick and draw works, so a kind of tender assists the work)

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Guidelines To choose roughly the type of offshore drilling rigs according to water depth and conditions of sea state and winds:

Water depth less than 25 m: Submersible rigs (swamp barges). Water depth less than 50 m and calm sea: Tender or Jack-up assisted platforms. Water depth less than 400 m and mild sea: Self-contained platforms. Water depth from 15 m to 150 m: Jack-up rigs. Water depth from 20 m to 2000 m: Anchored Drillships or Semisubmersible rigs. Water depth from 500 m to 3000 m: Drillships or Semisubmersible rigs with dynamic positioning system. Isolated area with icebergs: Drillships with dynamic positioning system. Severe sea conditions: Semisubmersible rigs or new generation Drillships .

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Mobile Bottom-supported Structures 1. Jack-up Drilling Rigs (Jack-up Rigs, Self-elevating Drilling Rigs) 2. Submersible Drilling Rigs (Submersible Rigs, Swamp Barges) 3. Tender-Assisted Platforms and Tenders

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Floating Offshore Structures (Floaters) Neutrally buoyant structures which are dynamically unrestrained and are allowed to have 6 degrees of freedom (heave, surge, sway, pitch, roll and yaw) are: 1. Drillships. 2. Semisubmersible Drilling Rig 3. Spars Positively buoyant structures which are tethered to the seabed and are heave-restrained are: 4. Tension Leg Platforms (TLPs) 5. Tethered Buoyant Towers (TBTs) 6. Buoyant Leg Structures (BLS)

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Offshore structures for drilling

Offshore structures for production

1

Platform Rigs

1

Fixed Platforms a) Steel Jackets b) Concrete gravity-based structures

2

Mobile Offshore Drilling Units a) Drilling Tenders b) Jackups c) Submersibles d) Semisubmersibles e) Drillships

2

Floating Production Systems a) Semisubmersibles b) Tension-leg Platforms c) Spar Platforms d) Ship-Shaped FPSO’s

For drilling as well as production these units are modified for dual function. (Excluding TLP

and SPAR, because of limited motions these are suitable for surface-completed wells only)  Example for Drilling, production & Storage in 1 unit is FPDSO (Floating Production

Drilling Chemical Engineering, VIT for its development) Storage &2020 Offloading) (vessel motionsDept.of is the only hesitation 25 July University.

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Largest Offshore Structures

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Various types of Offshore Structures

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General Classification of Structures: (I) Bottom-Supported Structures (II) Compliant Structures (III) Floating Structures

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(I) Bottom-Supported Structures 1. Minimal Platforms:

Field development in shallow water uses fixed production platforms with a small deck. Example minimal platform concepts (LINX, MANTIS II and TRIPOD) for marginal field

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(I) Bottom-Supported Structures 2. Jacket Structures: Fixed jacket structures (or template structures) consist of tubular members interconnected to form a three-dimensional space frame

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(I) Bottom-Supported Structures 3. Gravity Base Structures: Offshore structures that are placed on the seafloor and held in place by their weight are called gravity structures.

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Gravity Base Structure

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(I) Bottom-Supported Structures 4. Jack-ups: The jack-up barges are typically three-legged structures having a deck supported on their legs. The legs are made of tubular truss members. The deck is typically buoyant.

5. Subsea Templates: Subsea technology covers a wide range of offshore activities. Examples are subsea Xmas trees, manifolds, templates, flowlines and risers, control systems, well fluid boosters, multiphase pumping and metering, water separation, water injection, remote and diverless connections, guideline-free installations, seabed electrical power distribution systems, interventions, etc.

6. Subsea Pipelines: Subsea pipelines are used to transfer oil from the production platforms to storage facilities or to the shore. 25 July 2020

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Jack-Up Drilling Rig with Triangular Shape and 3 Legs (JDC Hakuryu 8) (Reproduced Courtesy of Japan Drilling Co.) 25 July 2020

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There are two basic leg configurations of jack-up rigs: 1.Independent-leg type for relatively firm seabed: Each independent leg has a spud can on the end. The leg penetrates soil below the mud line, i.e. the sea bottom. The penetration depends on the composition of the soil and the shape of spud can. 2.Mat-supported type for soft seabed: Legs is connected with a mat. The mat rests on the seabed to stably support the rig. The type is used on flat seabottom in water depth of up to 50 m. The penetration is slight.

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(I) Bottom-Supported Structures 7. Submersible Drilling Rigs (Submersible Rigs, Swamp Barges) Submersible drilling rigs consist of upper and lower hulls connected by a network of posts or beams. The drilling equipment and living quarters are installed on the upper hull deck. The lower hull has the buoyancy capacity to float and support the upper hull and equipment. When water is pumped into the lower hull, the rig submerges and rests on the seabed to provide a working place for the drilling. Movement and drilling operations proceed as that of the jack-up rig. Most submerged rigs are used only shallow waters of 8 to 10 meters. Ship-shaped submersible rigs are also used, which are called swamp barges.

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Submersible Drilling Rig (Noble FriRodli) (Reproduced Courtesy of Noble Drilling Corporation) 25 July 2020

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(I) Bottom-Supported Structures 8. Tender-Assisted Platforms and Tenders In regions where the weather conditions are not harsh, it is possible to use lower cost fixed platforms that are designed to support only the derrick and the drawworks. The tender anchored alongside the platform contains drilling equipment such as pumps and tubular goods, and accommodation for personnel. A catwalk connects the platform and the tender. If weather conditions (wind, swell, and current) become too harsh, the drilling operations must be shut down due to excessive motion of the tender. The tender platforms are used in Gulf of Guinea and the Persian Gulf waters where good weather conditions prevail, resulting in low downtime less than 2% of total operation time.

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Platform (left) and Semisubmersible Tender (right) (Atwood Oceanics SEAHAWK) (Reproduced Courtesy of Atwood Oceanics, Inc.) 25 July 2020

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(II) Compliant Structures Compliant structure by definition includes those structures that extend to the ocean bottom and directly anchored to the seafloor by piles and/or guidelines. Typically designed to have their lowest modal frequency to be below the wave energy, as opposed to the fixed structures, which have a first modal frequency greater than the frequency of wave energy.

1. Articulated Platforms: One of the earliest compliant structures that started in relatively shallow waters and slowly moved into deep water.

“Articulated tower is an upright tower, which is hinged at its base with a cardan joint and is free to oscillate about this joint due to the environment.” The base below the universal joint on the seabed may be a gravity base or may be piled. The tower is ballasted near the universal joint and has a large enough buoyancy tank at the Dept.of Chemical Engineering, VIT 25 Julysurface 2020 43 free to provide large restoring force (moment). University.

(II) Compliant Structures 2. Compliant Tower: A compliant tower is similar to a traditional platform and extends from surface to the sea bottom, and it is fairly transparent to waves. Compliant tower is designed to flex with the forces of waves, wind and current. It uses less steel than a conventional platform for the same water depth.

3. Guyed Tower: A guyed tower is a slender structure made up of truss members, which rests on the ocean floor and is held in place by a symmetric array of catenary guylines.

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(III) Floating Structures Floating Platform Types: The floating structures may be grouped as Neutrally Buoyant and Positively Buoyant. structures include Spars, Semi-submersible MODUS and FPSs, Ship-shaped FPSOs and Drillships. structures are TLPs, TLWPs and Buoyant Towers. 25 July 2020

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Technologies Required by Floaters: Outline of Drilling System of Semisubmersible Rig (Modified from Sekiyukaihatsu Gijutsu no Shiori (1st edition). Reproduced Courtesy of Japan Petroleum Development Association)

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Technologies Required by Floaters:

The motion compensator is a device to maintain constant weight on the bit during drilling operation in spite of oscillation of the floater due to wave motion.

Crown Mounted Type of Heave Compensator (Reproduced Courtesy of National Oilwell Kristiansand) 25 July 2020

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(III) Floating Structures Production Units (FPSO and FPS) Most floating production units are neutrally buoyant structures (which allows six-degrees of freedom) which are intended to cost-effectively produce and export oil and gas.

1. FPSO: The FPSO generally refers to ship-shaped structures with several different mooring systems.

2. FPS FPS refers to Floating Production systems which are finding application in marginal and deepwater field development. 25 July 2020

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A computer graphic of a ship-shaped offshore installation (FPSO) with a shuttle tanker offloading system. 25 July 2020

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Drillships

The Larger is a Drillship with Dual-Activity Drilling System (TSF Discoverer Enterprise), and the Smaller is a Previous Generation Drillship (TSF Discoverer 534) Alongside with a Supply Boat 25 July 2020

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(III) Floating Structures 3. Semi-Submersible Platform: Semi-submersibles are multi-legged floating structures with a large deck. These legs are interconnected at the bottom underwater with horizontal buoyant members called pontoons.

Semisubmersible Platform 25 July 2020

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A computer graphic of a semisubmersible installation.

A computer graphic of a semisubmersible installation. 25 July 2020

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The advantages of semisubmersibles include the following: 1. Semisubmersibles can achieve good (small) motion response and, therefore, can be more easily positioned over a well template for drilling. 2. Semisubmersibles allow for a large number of flexible risers because there is no weathervaning system. Disadvantages of semisubmersibles: 3. Pipeline infrastructure or other means is required to export produced oil. 4. Only a limited number of (rigid) risers can be supported because of the bulk of the tensioning systems required. 5. Considering that most semisubmersible production systems are converted from drilling rigs, the topsides weight capacity of a converted semisubmersible is usually limited. 4. Building schedules for semisubmersibles are usually longer than those for shipshaped offshore structures. 25 July 2020

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Semisubmersible (As Drilling Rig) Semi-submersibles are multi-legged floating structures with a large deck. These legs are interconnected at the bottom underwater with horizontal buoyant members called pontoons. Semisubmersibles have submerged pontoons (lower hulls) that are interconnected to the drilling deck by vertical columns The lower hulls provide improved stability for the vessel. Also, the open area between the vertical columns of semisubmersibles provides a reduced area on which the environment can act. In drilling operations, the lower hulls are submerged in the water about half-length of the column, but do not rest on the seabed. When a semisubmersible moves to a new location, the lower hulls float on the sea surface. Semisubmersible rigs are towed by boats, and some rigs have selfpropelled capacity. On drilling site to keep the position, the anchors usually moor semisubmersibles, but the dynamic positioning systems are used by new generation semisubmersibles. 25 July 2020

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Semisubmersible Drilling Rig

Semisubmersible Drilling Rig (JDC Hakuryu 3) (Reproduced Courtesy of Japan Drilling Co.) 25 July 2020

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Because of the reduced heave motion, the use of rigid risers (instead of flexible risers), which are self-buoyant, is easier.

(III) Floating Structures 4. Spar: The Spar concept is a large deep draft, cylindrical floating Caisson designed to support drilling and production operations. Its buoyancy is used to support facilities above the water surface. It is, generally, anchored to the seafloor with multiple taut mooring lines. Because of the reduced heave motion, the use of rigid risers (instead of flexible risers), which are self-buoyant, is easier. Types of Spars: 1. Classic spar 2. Truss spar 3. Cell spar

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SPAR platforms

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(III) Floating Structures 5. Tension Leg Platform: A Tension Leg Platform (TLP) is a vertically moored compliant platform. The floating platform with its excess buoyancy is vertically moored by taut mooring lines called tendons (or tethers). The structure is vertically restrained precluding motions vertically (heave) and rotationally (pitch and roll). It is compliant in the horizontal direction permitting lateral motions (surge and sway).

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A computer graphic of a tension leg platform (TLP) installation. 25 July 2020

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(III) Floating Structures 5.1. MiniTLPs: SeaStar and Moses SeaStar is a deepwater production and utility mini-platform. SeaStar is a small TLP with a single surface-piercing column. It borrows from the concept of the tension leg platform and provides a cost-effective marginal field application. Moses MiniTLP appears to be a miniaturized TLP as the deck structure is supported by four columns and the columns are connected by pontoons. Motion characteristics of Moses is similar to that of SeaStar and, unlike the standard TLPs, miniTLPs need to dedicate a large percentage of their displacement (35 - 45%) for pretension.

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SeaStar Mini TLP 25 July 2020

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Function

Bottom-founded vs. floating structures Bottom-Supported Floating

Payload support

Foundationbearing capacity

Buoyancy

Well access

“rigid” conduits (conductors) surface wellheads and controls

"dynamic" risers subsea wellheads subsea or surface controls

Environmental loads

Resisted by strength of structure and foundation, compliant structure inertia

Resisted by vessel inertia and stability, mooring strength.

Construction

Tubular space frame: fabrication yards

Plate and frame displacement hull: ship yards

Installation

Barge (dry) transport and launch, upend, piled Foundations

Wet or dry transport, towing to site and attachment to pre-installed moorings

Regulatory and design practices

Oil Industry practices and government petroleum regulations

Oil industry practices, government petroleum regulations and Coast Guard & International Maritime regulations

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Worldwide offshore rigs and offshore production growth. Worldwide offshore rigs and offshore production growth. For more than 20 years, there has been a direct relationship between offshore production and the number of development drilling rigs operating, a trend that is expected to continue well into the 21st century.

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UNIVERSIT Y OF PETROLEUM & ENERGY

ACID GASES REMOVAL PROCESS Acid gases present in Natural gas • CO2 • H2S • Gas with out CO2 and H2O is called “ Sweet ” Otherwise “ Sour ” • Both gases are undesirable because they cause  Corrosion  Reduce Heating Value

Percent by Volume

Parts per Million by Volume

Grains per 100 Standard Cubic Feet*

Milligrams per Cubic Meter*

Physiological Effects

0.00013

0.13

0.008

0.18

Obvious and unpleasant odor generally perceptible at 0.13 ppm and quite noticeable at 4.6 ppm. As the concentration increases, the sense of smell fatigues and the gas can no longer be detected by odor.

0.001

10.

0.63

14.41

Acceptable ceiling concentration permitted by Federal OSHA standards.

0.005

50.

3.15

72.07

Acceptable maximum peak above the OSHA acceptable ceiling concentrations permitted once for 10 minutes per eight-hour shift, if no other measurable exposure occurs.

0.01

100.

6.30

144.14

Coughing, eye irritation, loss of sense of smell after 3 to 15 minutes. Altered respiration, pain in eyes, and drowsiness after 15 to 30 minutes, followed by throat irritation after one hour. Prolonged exposure results in a gradual increase in the severity of these symptoms.

0.02

200.

12.59

288.06

Kills sense of smell rapidly, burns eyes and throat.

0.05

500.

31.49

720.49

Dizziness, loss of sense of reasoning and balance. Breathing problems in a few minutes. Victims need prompt artificial resuscitation.

0.07

700.

44.08

1008.55

Unconscious quickly. Breathing will stop and deaths will result if not rescued promptly. Artificial resuscitation is needed.

0.10+

1000+

62.98

1440.98+

Unconsciousness at once. Permanent brain damage or death may result unless rescued promptly and given artificial resuscitation.

*Based on 1 percent hydrogen sulfide = 629.77 gr/100 SCF at 14.696 psia and 59°F, or 101.325 kPa and 15°C.

Table 1

. Figure 1 and Figure 2

Figure 1 Continued

Figure 2

SEVERAL PROCESS Numerous processes have been developed for acid gas removal and gas sweetening based on a variety of chemical and physical principles. These processes (Table 2) can be categorized by the principles used in the process to separate the acid gas from the other natural gas components. The list, although not complete, represents many of the common available commercial processes. Table 3 shows the gases that are removed by the different processes. Table 4 illustrates the process capabilities of some of the processors for gas treating.

Table 2: Acid Gas Removal Processes Continued

Table 3: Gases Removed by Various Processes Continued

Table 4: Process Capabilities for Gas Treating

SOLID BED PROCESSES Iron Sponge Process • The iron sponge process utilizes the chemical reaction of ferric oxide with H2S to sweeten gas streams. This process is economically applied to gases containing small amounts of H2S. This process does not remove carbon dioxide. • The reaction of hydrated colloidal iron oxide and H2S produces iron sulfide and water as follows:

• The reaction requires the presence of and a temperature below 49°C (120°F). water When temperatures exceed 49°C (120°F), careful control of pH must be maintained. If the gas does not contain sufficient water vapor, water may need to be injected into the inlet gas stream. A pH level of 8 to 10 can be maintained through the injection of caustic soda, soda ash, lime, or ammonia with the water. pH control should be avoided whenever possible. Although the presence of free alkalies enhances H2S removal, it creates potential safety hazards, promotes formation of undesirable salts and adds to capital costs.

• The ferric oxide is impregnated on wood chips, which produce a solid bed with a large ferric oxide surface area. Several grades of treated wood chips are available, based on iron oxide content. They are commonly available as 6.5, 9.0, 15.0, and 20 lb iron oxide/bushel. The chips are contained in a vessel, and sour gas flows downward through the bed and reacts with the ferric oxide. Figure 2 (Iron oxide acid gas treating unit) shows a vessel for the iron sponge process.

Figure 1

• The ferric sulfide can be oxidized with air to produce sulfur and regenerate the hydrated ferric oxide. The regeneration step must be performed with great care since the reaction with oxygen is exothermic (i.e., gives off heat). Air must be introduced slowly so the heat of reaction can be dissipated. If air is introduced quickly, the heat of reaction may ignite the bed. For this reason spent wood chips should be kept moist when removed from the vessel. Otherwise, the reaction with oxygen in the air may ignite the chips and cause them to smolder.

• The reactions for oxygen regeneration are as follows:

• Some of the elemental sulfur produced in the regeneration step remains in the bed. After several cycles this sulfur will cake over the ferric oxide, decreasing the reactivity of the bed and causing excessive gas pressure drop. Typically, after ten cycles the bed must be removed from the vessel and replaced with a new bed

• It is possible to operate an iron sponge with continuous regeneration by the introduction of small amounts of air in the sour gas feed. The oxygen in the air regenerates the iron sulfide and produces elemental sulfur. Although continuous regeneration decreases the amount of operating labor, it is not as effective as batch regeneration and it may create an explosive mixture of air and natural gas. Because of the added costs associated with an air compressor, continuous regeneration generally does not prove to be the economic choice for the typically small quantities of gas involved.

• Cooler operating temperatures of the natural gas during the winter creates the potential for hydrate formation in the iron sponge bed. This can cause high pressure drop, bed compaction and flow channeling. Where the potential for hydrates exists, methanol can be injected to inhibit their formation; however, if insufficient water is present to absorb the methanol it may coat the bed, forming undesirable salts.

• Hydrocarbon liquids in the gas tend to accumulate on the iron sponge media, thus inhibiting the reactions. The use of a gas scrubber upstream of the iron sponge and a gas temperature slightly less than that of the sponge media may prevent significant quantities of liquids from condensing and fouling the bed. • There has been a recent revival in the use of iron sponges to sweeten light hydrocarbon liquids. The sour liquids flow through the bed and are contacted with the iron sponge media and the reaction proceeds as above.

SULFA-TREAT PROCESS • This

process is similar to the iron sponge ferric withtheHchemical process oxide utilizing reaction of 2S to sweeten gas streams. This processis applied to gases containing small amounts economically of H2S. Carbon dioxide is not removed in the process. • Sulfa-Treat utilizes a proprietary iron oxide co-product mixed with inert powder to form a porous bed. Sour gas flows through the bed and forms a bed primarily of pyrite. The powder has a bulk density of 70 lbs/ft3and ranges from 4 mesh to 30 mesh.

• The reaction works better with saturated gas and at elevated temperature up to 54.4°C (130°F). No minimum moisture or pH level is required. The amount of bed volume required increases as the velocity increases and as the bed height decreases. Operation of the system below 4.4°C (40°F) is not recommended. • The beds are not regenerated and must be replaced when the bed is spent.

MOLECULAR SIEVE PROCESS • Molecular sieve processes use synthetically manufactured crystalline solids in a dry bed to remove gas impurities. The crystalline structure of the solids provides a very porous material having uniform pore size. Within the pores the crystalline structure creates a large number of localized polar charges called active sites. Polar gas molecules such as H2S and water vapor, which enter the pores, form weak ionic bonds at the active sites. Non-polar molecules such as paraffin hydrocarbons will not bond to the active sites.

• Molecular sieves are available with a variety of pore sizes. A molecular sieve should be selected with a pore size that will admit H2S and water while preventing heavy hydrocarbons and aromatic compounds from entering the pores. Carbon dioxide molecules are about the same size as H2S molecules, but are non-polar. Thus, CO2 will enter the pores but will not bond to the active sites. Small quantities of CO2 will be removed by becoming trapped in the pores by bonded H2S or H2O molecules blocking the pores. More importantly, CO2 will obstruct the access of H2S and H2O to the active sites, decreasing the overall effectiveness of the molecular sieve. Beds must be sized to remove all H2O and provide for interference from other molecules in order to remove all H2S.

• The adsorption process usually occurs at moderate pressure. Ionic bonds tend to achieve an optimum performance near 3100 kPa (450 psig), but the system can be used for a wide range of pressures. • The molecular sieve bed is regenerated by flowing hot sweet gas through the bed. The hot stripping gas breaks the ionic bonds and removes the H2S and H2O from the sieve. Typical regeneration temperatures are in the range of 150°C to 200°C (300°F to 400°F).

• Molecular sieve beds can suffer chemical and mechanical degradation. Care should be taken to minimize mechanical damage to the solid crystals as this may decrease the bed's effectiveness. The main causes of mechanical damage are the sudden pressure and/or temperature changes that may occur when switching from adsorption to regeneration cycles. Proper instrumentation can significantly extend bed life. • Molecular sieves are generally limited to small gas streams operating at moderate pressures. Due to these operating limitations, molecular sieve units have seen limited use for gas sweetening operations. They are generally used for polishing applications following one of the other processes.

ZINC OXIDE PROCESS • This process is similar to the iron sponge process in the type of equipment used. The zinc oxide process uses a solid bed of granular zinc oxide to react with the H2S to form zinc sulfide and water as shown below.

• The rate of reaction is controlled by the diffusion process, as the sulfide ion must first diffuse to the surface of the zinc oxide to react. Temperatures above 120°C (250°F) increase the diffusion rate and are normally used to promote the reaction rate. The strong dependence on diffusion means that other variables such as pressure and gas velocity have little effect on the reaction

• Zinc oxide is usually contained in long thin beds to lessen the chances of channeling. Pressure drop through the beds is low. Bed life is a function of gas sulfide content and can vary from six months to over ten years. The beds are often used in series to increase the level of saturation prior to change out of the catalyst. The spent bed is discharged by gravity flow through the bottom of the vessel. The process has seen decreasing use due to increasing disposal problems with the spent bed, which is classified as a heavy metal salt.

CHEMICAL SOLVENT PROCESSES • Chemical solvent processes use an aqueous solution of a weak base to chemically react with and absorb the acid gases in the natural gas stream. The absorption driving force is a result of the partial pressure differential between the gas and the liquid phases. The reactions involved are reversible by changing the system temperature or pressure, or both. Therefore, the aqueous base solution can be regenerated and circulated in a continuous cycle. The of majority solvent processes utilize either an amine chemical or carbonate solution.

AMINE PROCESSES • Several processes have been developed using the basic action of various amines. These amines can be categorized by the number of organic groups bonded to the central nitrogen atom, as primary, secondary or tertiary. For example:

• Primary amines form stronger bases than secondary amines, which form stronger bases than tertiary amines. Amines with stronger base properties will be more reactive toward CO2 and H2S gases and will form stronger chemical bonds. This implies that the acid gas vapor pressure will be lower for a given loading as amine reactivity increases and a higher equilibrium loading may be achieved.

A typical amine system is shown in Figure 3 (Gas sweetening process flow schematic of amine sweetening).

Figure 2

• The sour gas enters the system through an inlet scrubber to remove any entrained water or hydrocarbon liquids. Then the gas enters the bottom of the amine absorber and flows countercurrent to the amine solution. The absorber can be either a trayed or packed tower with conventional packing usually used for 500 mm (20 in) or smaller diameter towers, and trays or structured packing for larger towers. The sweetened gas then leaves the top of the tower. An optional outlet scrubber may be included to recover entrained amine from the sweet gas. Since the natural gas leaving the top of the tower is saturated with water, the gas will require dehydration before entering a pipeline.

• The amine solution leaves the bottom of the absorber. This solution containing the CO2 and H2S is referred to as the rich amine. From the absorber, the rich amine flows to the flash tank to remove most of the dissolved hydrocarbon gases or entrained hydrocarbon condensates. A small amount of the acid gases will also flash to the vapor phase in this vessel. From the flash tank the rich amine proceeds to the rich amine/lean amine heat exchanger. This heat exchanger recovers some of the sensible heat from the lean amine stream to decrease the heat duty on the amine reboiler and the solvent cooler. The preheated rich amine then enters the amine stripping tower where heat from the reboiler breaks the bonds between the amine and acid gases. The acid gases are removed overhead and lean amine is removed from the bottom of the stripper.

• The hot lean amine flows to the rich amine/lean amine heat exchanger and then to additional coolers, typically aerial coolers, to lower its temperature to approximately 5.5°C (10°F) above the inlet gas temperature. This reduces the amount hydrocarbons condensed of in the amine solution when the amine contacts the sour gas. Typically, a side stream of approximately 3 percent of the amine flow rate is taken off after the rich/lean amine heat exchanger and is flowed through a charcoal filter to clean the solution of contaminants. The cooled lean amine is then pumped up to the absorber pressure and enters the top of the absorber. As the amine solution flows down the absorber it absorbs the acid gases. The rich amine is then removed at the bottom of the tower and the cycle is repeated.

• The common amine processes most monoethanolamine are (MEA) and diethanolamine (DEA). Both processes will remove CO2 and H2S to pipeline specifications. Among the newer processes, which have been developed is methyldietha-nolamine (MDEA). It can be used for selective removal of H2S in the presence of CO2 and significantly reduces treating costs when CO2 reduction is not necessary.

MONOETHANOLAMINE SYSTEMS (MEA) • Monoethanolamine (MEA) is a primary amine, which has had widespread use as a gas sweetening agent. This process is well proven, can meet pipeline specifications, and has more design/operating data available than any other system. MEA is a stable compound and in the absence of other chemicals suffers no degradation or decomposition at temperatures up to its normal boiling point.

• MEA reacts with CO2 and H2S as follows:

• These reactions are reversible by changing the system temperature. The reactions with CO2 and H2S shown above are reversed in the stripping column by heating the rich MEA to approximately 118°C at 69 kPa (245°F at 10 psig). The acid gases evolve into the vapor and are removed from the still overhead. Thus the MEA is regenerated.

• A disadvantage of MEA is that it also reacts with carbonyl sulfide (COS) and carbon disulfide (CS2) to form heat stable salts, which cannot be regenerated at normal stripping column temperatures. At temperatures above 118°C (245°F) a side reaction with CO2 exists which produces oxazolidone-2, a heat stable salt, which consumes MEA from the process.

• The normal regeneration temperature in the still will not regenerate heat stable salts or oxazolidone-2. Therefore, a reclaimer is often included to remove these contaminants. A sidestream of from 1 percent to 3 percent of the MEA circulation is drawn from the bottom of the stripping column. This stream is then heated to boil the water and MEA overhead while the heat stable salts and oxazolidone-2 are retained in the reclaimer. The reclaimer is periodically shut in and the collected contaminants are cleaned out. When the contaminants are removed from the system, any MEA bonded to them is also lost.

• MEA is usually circulated in a solution of 15 percent to 20 percent MEA by weight in water. From operating experience it has been found that the solution loading should not be greater than 0.3 to 0.4 moles of acid gas per mole of MEA. Both the solution strength and the solution loading are limited to avoid excessive corrosion. The solution concentration and loading is largely determined by the H2S/CO2 ratio. The greater the ratio (i.e., the higher the concentration of H2S relative to CO2), the higher the allowable loading and amine concentration. This is due to the reaction of H2S and iron (Fe) to form iron sulfide (Fe2S3 and FeS), which forms a protective barrier on the steel surface. This barrier can be stripped away by high fluid velocities and may lead to increased corrosion on the exposed steel.

• The gases in the rich corrosive, amine are but the above acid limits may concentration hold corrosion to acceptable levels. The corrosion commonly shows up on areas of carbon steel that have been stressed, such as heat affected zones near welds, in areas of high acid gas concentration, or at a hot gas and liquid interface. Therefore, stress relieving all equipment after manufacturing is necessary to reduce corrosion, and special metallurgy is usually used in specific areas such as the still overhead or the reboiler tubes.

• MEA systems foam rather easily resulting in excessive amine carryover from the absorber. Foaming can be caused by a number of foreign materials such as condensed hydrocarbons, degradation products, solids such as carbon or iron sulfide, excess corrosion inhibitor, valve grease, etc. One of the more effective methods of foam control is to use a coalescing filter separator at the gas inlet to the MEA contactor. This removes many of the contaminants before they enter the system. Hydrocarbon liquids are usually removed in the flash tank. Degradation products are removed in a reclaimer as described above.

• MEA storage tanks and surge vessels must have an inert blanket gas system to prevent the oxidation of MEA. Sweet natural gas or nitrogen can be used as the blanket gas. • MEA has the lowest boiling point and the highest vapor pressure of the amines. This results in MEA losses of 16 to 48 kg/MMm3 (1 to 3 lbs/MMSCF) of inlet gas. • In summation, MEA systems can effectively treat sour gas to pipeline specifications. However, care in the design and material selection of MEA systems is required to minimize equipment corrosion.

Diethanolamine Systems (DEA) • Diethanolamine (DEA) is a secondary amine also used to treat natural gas to pipeline specifications. As a secondary amine, DEA is less alkaline than MEA. DEA systems do suffer the same corrosion problems, but not as severely as those using MEA. Solution strengths are typically from 25 to 35 percent DEA by weight in water.

• DEA reacts with CO2 and H2S as follows

• These reactions are reversible. • DEA has significant advantages over MEA when COS or CS2 are present. DEA reacts with COS and CS2 to form compounds which can be regenerated in the stripping column. Therefore, COS and CS2 are removed without a loss of DEA. • High CO2 levels have been observed to cause DEA degradation to oxazolidones. Typically, DEA systems include a carbon filter but do not include a reclaimer.

• The stoichiometry of the reactions of DEA and with CO2 and H2S are the same. The molecular weight MEA of DEA is 105 compared to 61 for MEA. The combination of molecular weights and reaction stoichiometry means that approximately 0.77 kg (1.7 lbs) of DEA must be circulated to react with the same amount of acid gas as 0.45 kg (1.0 lbs) of MEA. The solution strength of DEA ranges up to 35 percent by weight compared to 20 percent for MEA. Loadings for DEA systems range from 0.35 to 0.65 moles of acid gas per mole of DEA without excessive corrosion. The result of this is that the circulation rate of a DEA solution is slightly less than in a comparable MEA system. • The vapor pressure of DEA is approximately 1/30 of the vapor pressure of MEA. Therefore, amine losses are much lower than in an MEA system

DIGLYCOLAMINE® SYSTEMS (DGA) • The Fluor Econamine Process uses diglycolamine® (DGA) to treat natural gas. The active DGA reagent is 2-(2aminoethoxy) ethanol, which is a primary amine as follows:

• The reactions of DGA with acid gases are the same as those for MEA. Unlike MEA, degradation products from reactions with COS and CS2can be regenerated.

• DGA systems typically circulate a solution of 50 to 70 percent DGA by weight in water. At these solution strengths and a loading of up to 0.3 moles of acid gas per mole of DGA, corrosion in DGA systems is slightly less than in MEA systems. The advantages of a DGA system are that the low vapor pressure decreases amine losses, and the high solution strength permits lower circulation rates.

DIISOPROPANOLAMINE SYSTEMS (DIPA) • Diisopropanolamine (DIPA) is a secondary amine used in the Shell "ADIP®" process to sweeten natural gas. • DIPA systems are similar to DEA systems but offer the following advantages: • Carbonyl sulfide (COS) can be removed and the DIPA solution regenerated easily • The system is generally non-corrosive • Lower energy consumption

• One feature of this process is that at low pressures DIPA will preferentially remove H2S. As pressure increases, the selectivity of the process decreases, and DIPA removes increasing amounts of CO2. Therefore, this system can be used either to selectively remove H2S or to remove both CO2 and H2S.

METHYLDIETHANOLAMINE SYSTEMS (MDEA) • Methyldiethanolamine is a tertiary amine, which like the other amines, is used to treat acid gas streams.advantage, major The which MDEA offers over other amine processes, is its selectivity for H2S in the presence of CO2. If the gas is contacted at pressures ranging from 5500 to 6900 kPa (800 to 1000 psig), H2S levels can be reduced to the very low concentrations required by pipelines, while at the same time 40 to 60 percent of the CO2 present flows through the contactor, unreacted.

• In cases where a high CO2/H2S ratio is present, MDEA can be used to improve the quality of the acid gas stream to a Claus recovery plant, but the higher CO2 content of the treated residue gas must be tolerated. • Solution strengths typically range from 40 to 50 percent MDEA by weight. Acid gas loading varies from 0.2 to 0.4 or more moles of acid gas per mole of MDEA depending on supplier. MDEA has a molecular weight of 119. MDEA solution makeup is dependent upon the supplier. It can be adjusted to optimize treatment for a particular gas inlet composition.

• Higher allowable MDEA concentration and acid gas loading results in reduced circulation flow rates. Significant capital savings are realized due to reduced pump and regeneration requirements. MDEA has a lower heat requirement due to its low heat of regeneration. In some applications, energy requirements for gas treating can be reduced as much as 75 percent by changing from DEA to MDEA.

INHIBITED AMINE SYSTEMS • These processes use standard amines that have been combined with special inhibiting agents which minimize corrosion. This allows higher solution concentrations and higher acid gas loadings, thus reducing required circulation rates and energy requirements.

CARBONATE PROCESSES • Hot Potassium Carbonate Systems • Carbonate processes generally utilize hot potassium carbonate to remove CO2 and H2S. As a general rule, this process should be considered when the partial pressure of the acid gas is 138 kPa (abs) (20 psia) or greater. It is not recommended for low pressure absorption, or high pressure absorption of low concentration acid gas.

• The main reactions involved in this process are:

• These reactions are based on the pressures of the acid gases. partial Note that reversible potassium bicarbonate (KHCO3) solutions are not readily regenerable in the absence of CO2, so that these processes are only employed for H2S removal when quantities of CO2 are present. Potassium carbonate also reacts reversibly with COS and CS2.

Figure4 (Gas sweetening flow schematic of a hot carbonate process) shows a typical hot carbonate system for gas treating.

Figure 4

• The gas to be treated enters the bottom of the absorber and flows countercurrent to the potassium carbonate. The sweet gas then exits the top of the absorber. The absorber is typically operated at 110°C (230°F). Therefore, a gas/gas exchanger may be included to cool the sweet gas, recover sensible heat, and decrease the system's utility heat requirements.

• The rich potassium carbonate solution from the bottom of the absorber flows to a flash drum where much of the acid gas is removed. The solution then proceeds to the stripping column, which operates at approximately 118°C (245°F) and near atmospheric pressure. The low pressure, combined with a small amount of heat input, strips the remaining acid gases. The lean potassium carbonate from the stripper is pumped back to the absorber. The lean solution may or may not be cooled slightly before entering the absorber. The heat of reaction from the absorption of the acid gases causes a slight temperature rise in the absorber.

• The solution concentration for a potassium carbonate system is limited by both the solubility of potassium carbonate in the lean stream and the solubility of the potassium bicarbonate (KHCO3) in the rich stream. The reaction with CO2 produces two moles of KHCO3 per mole of potassium carbonate reacted. For this reason the KHCO3 in the rich stream normally limits the lean solution potassium carbonate concentration to 20 to 35 percent by weight.

• Potassium carbonate works best on gas streams with a CO2 partial pressure of 207 to 620 kPa (30 to 90 psi). When CO2 is not present, H2S removal will be limited because the regeneration of the potassium carbonate requires an excess of KHCO3. The presence of CO2 in the gas provides a surplus of KHCO3 in the rich stream. Note that pipeline quality gas often requires secondary treating using an amine or similar system to reduce H2S level to 4 ppm.

• The entire system is operated at temperatures to the solubility of high increase carbonates. Therefore, the designer must be careful to avoid dead spots in the system where the solution could cool and precipitate solids. If solids do precipitate, the system may suffer from • The potassium carbonate solutions plugging, erosion, or foaming. hot corrosive. are All carbon steel must be stress relieved to limit corrosion. A variety of corrosion inhibitors, such as fatty amines or potassium dichromate, are available to decrease corrosion rates.

PROPRIETARY CARBONATE SYSTEMS • Several proprietary processes have been developed based on the hot carbonate system with an activator or catalyst. These activators increase the performance of the hot potassium carbonate system by increasing the reaction rates both in the absorber and the stripper. In general, these processes also decrease corrosion in the system. The following are some of the proprietary processes for hot potassium carbonate:

• • • •

Benfield: Several activators Girdler : Alkanolamine activators Catacarb: Alkanolamine and/or borate activators Giammarco-Vetrocoke: Arsenic and other activators

SPECIALTY BATCH CHEMICAL SOLVENTS • Several batch chemical processes have been developed and have specific areas of application. Among these processes are Zinc Oxide slurry, caustic wash, SulfaCheck, Slurrisweet, and Chemsweet. In general, gas is flowed into a vessel and contacted with the solvent. The acid components are converted to soluble salts, which are non-regenerable, limiting the life of the solution. Once saturation levels are reached, the solution must be replaced. For some of these processes, the spent solutions are not hazardous, but for others, the spent solutions have been labeled hazardous and, if used, must be disposed of as Class IV materials.

• These units have a wide operating range, with acid gas concentrations ranging from as low as 10 ppm to as high as 20 percent. Operating pressures range from near atmospheric to greater than 7000 kPa (1000 psig). Units have been designed to handle from several hundred cubic meters per day to more than 420,000 m3 per day (from several thousand cubic feet per day to more than 15 MMSCFD).

• Typical among these processes is the Sulfa-Check process. This is a single step process that converts H2S to sulfur in a bubble tower filled with a proprietary solution of oxidizing and buffering agents. The oxidizing agent is a proprietary formulation of chelated nitrite ions. The reaction chemistry involved is as follows:

• Reaction rate is independent of the concentration of the oxidizing agent. Although there is no limit to the concentration of H2S treated, the process is most economical for acid gas streams containing from 1 ppm to 1 percent H2S. It is important to hold pH above 7.5 to control selectivity and optimize H2S removal. Four liters (one gallon) of oxidizing solution can remove up to 1 kg (2 lbs) of H2S when the system is operated at ambient temperatures less than 38°C (less than 100°F). If gas temperatures exceed 38°C (100°F), the solubility of sulfur in the oxidizing agent decreases. An operating pressure of at least 138 kPa (20 psig) is required for proper unit operation to maintain bubble flow through the column. Bubble flow is necessary to produce intimate mixing of the gas and liquid.

• The oxidizing solution will eventually become saturated and require replacement. Disposal of this slurry poses no environmental problem, as the reaction produces an aqueous slurry of sulfur and sodium salt.

PHYSICAL SOLVENT PROCESSES • Physical solvent systems are very similar to chemical solvent systems but are based on the gas solubility within a solvent instead of a chemical reaction. The partial pressure of the acid gases and the system temperature both affect the acid gas solubility. Higher acid gas partial pressures increase the acid gas solubility. Low temperatures have a similar effect, but, in general, temperature is not as critical as pressure.

• Various organic solvents are used to absorb the acid gases based on partial pressures. Regeneration of the solvent is accomplished by flashing to lower pressures and/or stripping with solvent vapor or inert gas. Some solvents can be regenerated by flashing only and require no heat. Other solvents require stripping and some heat, but typically the heat requirements are small compared to chemical solvents.

• Physical solvent processes have a high affinity for heavy hydrocarbons. If the natural gas stream is rich in C3+ hydrocarbons, then the use of a physical solvent process may result in a significant loss of the heavier mole weight hydrocarbons. These hydrocarbons are lost because they are released from the solvent with the acid gases and cannot be economically recovered.

• Under the following circumstances physical solvent processes should be considered for gas sweetening: • The partial pressure of the acid gases in the feed is 345 kPa (50 psi) or higher •

The concentration of heavy hydrocarbons in the feed is low •

•

Only bulk removal of acid gases is required Selective H2S removal is required

A physical solvent process is shown Figure 5 (Typical flow schematic of a physical solvent process).

Figure 5

in

• The gas contacts the solvent using countercurrent flow in the sour Rich absorber.from the absorber bottom is flashed in solvent stages to near atmospheric pressure. This causes the acid gas partial pressures to decrease, and the acid gases evolve to the vapor phase and are removed. The regenerated solvent is then pumped back to the absorber.

• The example in Figure 5 (Typical flow schematic of a physical solvent process) is a simple one where flashing is sufficient to regenerate the solvent. Some solvents require a stripping column just prior to the circulation pump. Some systems require temperatures below ambient, thus refrigeration using power turbines replaces the pressure reducing valves. These turbines recover some of the power from the high pressure rich solvent and thus decrease the utility power requirements for refrigeration and circulation • The majority of the physical solvent processes are proprietary and are licensed by the company that developed the process. Four typical processes are discussed below.

FLUOR SOLVENT PROCESS • The Fluor Solvent process uses propylene carbonate as a physical solvent to remove CO2 and H2S. Propylene carbonate also removes C3+ hydrocarbons,COS, SO2, CS2 and H2O from the natural gas stream. Thus, in one step the natural gas can be sweetened and dehydrated to pipeline quality. In general this process is used for bulk removal of CO2 and is not used to treat to less than 3 percent CO2 as may be required for pipeline quality gas. The system requires special design features, larger absorbers and higher circulation rates to obtain pipeline quality and usually is not economically applicable for these outlet requirements.

• Propylene carbonate has the following characteristics, 2 which mHagi khe gases oilltvyefnfor acidangdasottrhee ditesgureiteabLow olfesaheat osul aof bsisolution otrfCO CorO 2 arting Low vapor pressure at operating temperature Low solubility for light hydrocarbons (C1, C2) Chemically non-reactive toward all natural gas components  Low viscosity  Non-corrosive toward common

• These characteristics combine to yield a system that has low heat and pumping requirements, is relatively non-corrosive, and suffers only minimal solvent losses, (less than 1 lb/MMSCF). • Solvent temperatures below ambient are usually used to increase solvent gas capacity, and, therefore, decrease circulation rates. The expansion of the rich solvent and flash gases through power turbines can provide the required refrigeration. Alternately, auxiliary refrigeration may be included to further decrease circulation rates.

SULFINOL® PROCESS • The Sulfinol®process, developed and licensed by Shell, employs both a chemical and a physical solvent for the removal of H2S, CO2, mercaptans, and COS. The Sulfinol®solution is a mixture of tetrahydrothiophene dioxide (Sulfolane®), which is the physical solvent; a secondary amine, diisopropanolamine (DIPA); and water. previously discussed,is the DIPA chemical range from 25 ,to 40 Typical solution concentrations percent Sulfolane®, 40 to 55 percent DIPA, solvent. and 20 to 30 percent water, depending on the conditions and composition of the gas being treated.

• The

presence the physical solvent, of Sulfolane®,to allows gas loadings compared systemshigher based acid on amine only. Typical loadings are 1.5 moles of acid gas per mole of Sulfinol® solution. Higher acid gas loadings, together with a lower energy of regeneration, can result in lower capital and energy costs per unit of acid gas removed as compared to the ethanolamine processes.

• Other features of the Sulfinol® 

process include:

Essentially complete removal of mercaptans  High removal rate of COS  Lower foaming tendency  Lower corrosion rates  Ability to slip up to 50 percent CO2

• The process design of a Sulfinol® unit is similar to that of the ethanolamines. However, the degradation of DIPA to oxazolidones (DIPA-OX) usually necessitates the installation of a reclaimer for their removal. As with the ethanolamine processes, aromatics and heavy hydrocarbons in the feed gas should be removed prior to contact with the Sulfinol® solution to minimize foaming.

• Although the relative merits of the Sulfinol® process as compared to the ethanolamine processes appear to be many, there are other factors which must be considered before selecting the appropriate gas treating process for a particular application. The payment of a licensing fee, while not necessary for the ethanolamine processes, is required for the Sulfinol® process. In addition, solvent costs are generally higher for Sulfinol®than they are for DEA. A less tangible disadvantage of the Sulfinol® process, is that operators are more familiar with DEA and the typical problems associated with this process. Finally, in cases of low acid gas partial pressure, the advantage of a lower circulation rate for the Sulfinol® process diminishes as compared to DEA.

SELEXOL® PROCESS • Selexol® is a process using the dimethylether of polyethylene glycol as a solvent. It was developed by Allied Chemical Company and is licensed by the Norton Company. This process is selective toward removing sulfur compounds. Levels of CO2 can be reduced by approximately 85 percent. This process may be used economically when there are high acid gas partial pressures and an absence of heavy ends in the gas. The Selexol® process will not normally remove enough CO2 to meet pipeline gas requirements. DIPA can be added to the solution to remove CO2 down to pipeline specifications. This process also removes water to less than 0.11 g/stdm3 (7 lb/MMSCF). This system then functions much like the Sulfinol® process discussed earlier. The addition of DIPA increases the relatively low stripper heat duty.

RECTISOL PROCESS • The German Lurgi Company and Linde A. G. developed the Rectisol process to use methanol to sweeten natural gas. Due to the high vapor pressure of methanol this process is usually operated at temperatures of -34°C to 74°C (30°F to -100°F). It has been applied for the purification of gas for LNG plants and in coal gasification plants, but is not commonly used to treat natural gas streams

DIRECT CONVERSION PROCESSES • Direct conversion processes use chemical reactions to oxidize H2S and produce elemental sulfur. These processes are generally based either on the reaction of H2S and O2 or H2S and SO2. Both reactions yield water and elemental sulfur. These processes are licensed and involve specialized catalysts and/or solvents.

STRETFORD PROCESS • An example of a process using O2 to oxidize H2S is the Stretford process, which is licensed by the British Gas Corporation. In this process the gas stream is washed with an aqueous solution of sodium carbonate, sodium vanadate and anthraquinone disulfonic acid. Figure 6 (Stretford Process) shows a simplified diagram of the process.

Figure 6

• Oxidized solution is delivered from the pumping tank to the top of the absorber tower where it contacts the gas stream in a countercurrent flow. The bottom of the absorber tower consists of a reaction tank from which the reduced solution passes to the solution flash drum, which is situated above the oxidizer. The reduced solution passes from here into the base of the oxidizer vessel. Hydrocarbon gases, which have been dissolved in the solution at the plant pressure are released from the top of the flash drum. Air is blown into the oxidizer and the main body of the solution, now reoxidized, passes into the pumping tank.

• The sulfur is carried to the top of the oxidizer by froth created by the aeration of the solution and passes into the thickener. The function of the thickener is to increase the weight percent of sulfur which is pumped to one of the alternate sulfur recovery methods of filtration, filtration and autoclaves, centrifugation or centrifugation with heating.

• The chemical reactions involved are:

• Sodium carbonate provides the alkaline solution for initial adsorption of H2S and the formation of hydrosulfide (HS¯ ). The hydrosulfide is reduced in a reaction with sodium meta vandate to precipitate sulfur.

• Anthraquinone disulfonic acid (ADA) reacts with 4valent vanadium and converts it back to 5-valent.

• Oxygen from the air converts the reduced ADA back to the oxidized state.

• The overall reaction is:

IFP PROCESS • The Institute Francais du Petrole has developed a process for reacting H2S with SO2 to produce water and sulfur. The overall reaction is:

Figure 7 process.

(IFP Process) is a simplified diagram of the

Figure 7

• This process involves mixing the H2S and SO2 gases and then contacting them with a liquid catalyst in a packed tower. Elemental sulfur is recovered in the bottom of the tower. A portion of this must be burned to produce the SO2 required to remove the H2S. The most important variable is the ratio of H2S to SO2 in the feed. This is controlled by analyzer equipment to maintain the system performance.

LO-CAT®/SULFEROX® • Developed by ARI Technologies and Shell Development, respectively, these processes employ high iron concentration reduction-oxidation technology for the selective removal of H2S to less than 4 ppm in both low and high pressure gas streams. The acid gas stream is contacted with the solution where H2S reacts with and reduces the chelated-iron and produces elemental sulfur. The iron is then regenerated by reaction with the oxygen in air. The reactions involved are exothermic:

• The features of these processes are high allowable iron concentration in solution, reduced degradation rates of the chelated-iron, and no heat requirements.

Figure 8 (LOillustrates the process design CAT) for the LO-CAT® process.

Figure 8

Figure 9 (Example SulFerox®System) illustrates the process design for the SulFerox® process.

Figure 9

• The SulFerox® process uses the patented pipeline contactor with co-current flow to minimize sulfur plugging. The system has a high turndown capability. • These units are relatively small per unit of acid gas treated. The technology of these processes has many potential applications such as:  Treatment

of sour produced or recycled CO2  Remote, single well streams  Tail Gas treatment  Offshore installations

• Although suitable for several applications, these processes have disadvantages, which must be considered prior to selecting this type of process for a specific gas treating application. Because CO2 is not removed and only partial removal of mercaptans is achieved, gas streams containing these components in excess of pipeline specifications will require additional treatment. Gas streams above 49°C (120°F) can cause excessive chelated-iron degradation, resulting in costly make-up rates. Certain components in gas streams, such as HCN, can "poison" the solution, rendering it non-regenerable, while other components, such as NH3, can raise the pH of the solution, resulting in the precipitation of iron. The licensors should be contacted to determine what incompatibilities between the solution and gas components may exist.

DISTILLATION PROCESS • The Ryan-Holmes distillation process uses cryogenic distillation to remove acid gases from a gas stream. This process is applied to remove CO2 for LPG separation or where it is desired to produce CO2 at high pressure for reservoir injection or other use. The process consists of two, three or four fractionating columns. The gas stream is dehydrated and then cooled with refrigeration and/or first pressure reduction.

• The three-column system is employed for gas streams containing less than 50 percent CO2. The first column operates at 3100 to 4500 kPa (450 to 650 psig) and separates a high quality methane product in the overhead. Temperatures in the overhead are from -18°C to -95°C(0°F to -140°F). The second column operates at a slightly lower pressure, and produces a CO2 stream overhead, which contains small amounts of H2S and methane. The bottom product contains H2S and the ethane plus components. The third column produces NGL liquids, which are recycled back to the first two columns. It is this recycle that allows the process to be successful. The NGL liquids prevent CO2 solid formation in the first column and aids in the breaking of the ethane/CO2 azeotrope in the second column to permit high ethane recoveries.

• A four-column system is used where CO2 feed concentration exceeds 50 percent. The initial column in this scheme is a de-ethanizer. The overhead product, a CO2/methane binary, is sent to a bulk CO2 removal column and demethanizer combination. CO2 is produced as a liquid and is pumped to injection or sales pressure.

• The two-column system is used when a methane product is not required and is thus produced with the CO2. Very high propane recoveries may be achieved; however, little ethane recovery is achieved. • These processes require feed gas preparation in the form of compression and dehydration, which add to their cost. They are finding applications in enhanced oil recovery projects.

Gas Permeation Process • Gas permeation is based on the mass transfer principles of gas diffusion through a permeable membrane. There are two types of membranes used. The first is a hollow tube membrane resembling a shell and tube exchanger. The second is a polymeric film envelope wound on a mandrel. • The permeation through a membrane involves both the diffusivity and solubility of a given component. The driving force for the separation is differential pressure; thus, operations can take place over a wide range of temperatures and pressures, as determined by the physical limitations of the membrane.

• In its most basic form, a membrane separation system consists of a vessel divided by a membrane into a high and a low-pressure section. Feed entering the high-pressure side selectively loses the fast permeating components to the low pressure side. Where gas permeability rates of the components are close, or if high product purity is required, the membrane modules can be arranged in series or streams may be recycled. • CO2 tends to diffuse quickly through membranes, and, thus, can be removed from the bulk gas stream. Permeation separation works well on gases with a high CO2 partial pressure. The CO2is produced at 1/5 to 1/10 the feed pressure. H2S is a problem with membranes, as it will usually be found in both the high and low-pressure streams. This may require further treatment for one or both of the streams.

• The main drawback of membrane separation for removal of CO2 is that some methane will also permeate through the membrane and be lost with the CO2. The permeate stream can contain as much as 10 percent of the methane that was in the feed stream. • The permeate typically contains enough methane that it can be burned for fuel. If there is insufficient need for fuel, this stream can be compressed and fed to another membrane to recover most of the methane.

• Membranes

are

susceptible rapid to deterioration if the liquid droplets or solids, and,feed thus,contains a good filterseparator is required upstream. In addition, the feed should be heated after separation to assure that the gas stays above its dew point.

Claus • The Claus process is used to treat gas streams containing high concentrations of H2S. The chemistry of the units involves partial oxidation of hydrogen sulfide to sulfur dioxide, and the catalytically promoted reaction of H2S and SO2 to produce elemental sulfur. The reactions are staged and are as follows:

(Typical flow diagram of a two-stage Claus process plant) shows a simplified process flow diagram of the Claus process.

• The first stage of the process converts H2S to sulfur dioxide and to sulfur by burning the acid gas stream with air in the reaction furnace. This provides SO2 for the next phase of the reaction. Multiple reactors are provided to achieve a more complete conversion of the H2S. Condensers are provided after each reactor to condense the sulfur vapor and separate it from the main stream. Conversion efficiencies of 94 to 95 percent can be attained with two catalytic stages while up to 97 percent conversion can be attained with three catalytic stages. As dictated by environmental concerns the effluent gas is either vented, incinerated or sent to a "tail gas treating unit."

Tail Gas Treating • There are many different processes used in tail gas treating today. These processes can be grouped into two categories: the first category is an extension of the Claus reaction in a dry or a liquid system. Leading among these processes are the Sulfreen and the Cold Bed Absorption (CBA) processes. These are similar processes, using two parallel Claus reactors in a cycle, where one reactor operates below the sulfur dew point to absorb the sulfur, while the second is regenerated with heat to recover the absorbed sulfur. Even though recoveries are normally 99 to 99.5 percent of the inlet sulfur stream, incineration of the outlet gas is required to meet environmental air quality.

• The second category of tail gas processes involves the conversion of the sulfur compounds to H2S and then the absorbing of the H2S from the stream. The SCOT process appears to be the leading choice among this type of process. The SCOT process uses an amine to remove the H2S, which is usually recycled back to the Claus plant. Other types of processes oxidize the sulfur compounds to SO2 and then convert the SO2 to a secondary product such as ammonium thiosulfate, a fertilizer. These plants can remove more than 99.5 percent of the sulfur and may eliminate the need for incineration. Costs of achieving tail gas cleanup are high; typically double the cost of a Claus unit.

PROCESS SELECTION Each of the acid gas treating processes advantages relative to the others for has applications; certain in therefore, process, the following appropriate selectionfacts ofshould the be

•

cTohnesitdyepreedo:f acid contaminants present in

the stream • gasThe concentrations of each contaminant and degree of removal required • The volume of gas to be treated and temperature and pressure at which the gas is available

• The feasibility of recovering sulfur • The desirability of selectively removing one or more of the contaminants without removing the others • The presence and amount of heavy hydrocarbons and aromatics in the gas • The environmental conditions required at the plant site.

Removal of H2S to Meet Pipeline Qualities (4 ppm) • For feeds with small acid gas loadings, one of the batch processes should be considered for removal of H2S. The most common are: iron sponge, Sulfa-Treat, and SulfaCheck. • As acid gas loadings increase, the disposal and replacement costs become high, and it becomes necessary to choose a process that can be regenerated. The amine systems are most often used for these installation systems. DEA is the most common amine system.

• The end product of an amine system is an acid gas stream off the stripper, which must be flared. As acid gas loadings increase, environmental constraints require that this acid gas stream be converted to sulfur. One of the processes that converts acid gas to sulfur, such as LO-CAT®, SulFerox®, Claus, or Stretford, must be added downstream of the amine system. In some cases, it may be feasible to contact the gas stream to be treated directly with LO- CAT® or SulFerox® solution and eliminate the need to separate the acid gas components from the gas stream with an amine unit.

• When a Claus unit is used, it may be necessary to add tail gas cleanup downstream of the Claus unit if acid gas loadings are very high.

Removal of CO2 • Removal of CO2 to meet pipeline quality specifications can be accomplished with an amine-based system since the acid gas from the stripper can be vented (assuming levels of H2S in the gas being treated are very low). • Removal of CO2 with gas permeation may be attractive for low volume gas streams in remote areas where the loss of methane is not critical. Permeation systems with a second stage recycle may be competitive with amine systems.

Removal of H2S and CO2 • Most commonly, both H2S and CO2 are present and must be removed to meet pipeline quality requirements. In most cases, essentially all of the H2S will have to be removed, while only a fraction of the CO2 will have to be removed. Use of a non-selective solvent such as MEA or DEA will require that the equipment be sized to essentially remove all the CO2 so that the H2S specification can be achieved. This procedure may be the most economical solution for streams with low CO2 concentrations.

• As CO2 concentrations in the feed increase, it becomes more economical to use a selective process such as MDEA, Sulfinol®, Selexol®, etc., which will remove a higher percentage of H2S than CO2 from a stream. • Another alternative is to use gas permeation or a carbonate system for bulk removal of CO2 upstream of a non-selective amine unit. • Finally, it may be economical to remove both H2S and CO2 to a level where the CO2 content is acceptable with either a selective or non-selective process, and use a sulfur removal process (iron sponge, Sulfa-Treat, Sulfa-Check, LO-CAT®, SulFerox®) for final treating of the residue gas.

Figures 1

(H2S removal -no CO2 present),

Figure 2

(CO2 removal -no H2S present) ,

Figure 3

(Removal of H2S and CO2.) ,

and Figure 4 Selective removal -H2S in presence of CO2.) can be used as screening tools to make an initial selection of potential process choices

• These graphs are not meant to supplant engineering judgment nor to cover every possible contingency. New processes are continuously being developed. Modifications to existing proprietary products will change their range of applicability and relative cost. The graphs do enable a first choice of several potential candidates, which could be investigated to determine which is the most economical for a given set of conditions. • To select a process, determine flow rate, temperature, pressure, concentrations of the acid gases in the inlet gas, and allowed concentrations of acid gases in the outlet stream. With this information, calculate the partial pressure of the acid gas components.

Equation 1

Next, determine if one of the four following situations is required, and use the appropriate guide

Removal of H2S with no presentCO2 Figure (H2S 1 removal -no CO2 present) Removal of CO2with no H2S present Figure 2 removal -no H2S present) (CO2 Removal of CO2and H2S - Figure 3 (Removal of H2S and CO2.) Selective removal of H2S with CO2 present Figure 4 (Removal of H2S in the presence CO2.)

Thank You

D I R E C T I O N A LD R I L L I N G WITH LO G G I N G TECHNIQUES PRESEN T ED B Y:

INTRODUCTION TO DRILLING • Locating an oil field is the first obstacle to be overcome. • Today, petroleum engineers use instruments such as Seismic exploration, Gravity meters and Magnetometers in the search for petroleum. • Generally, the first stage in the extraction of crude oil is to drill a well into the underground reservoir. • Oilfield drilling is of mainly three types based on their physical presentation: – Horizontal Drilling – Vertical drilling – Directional drilling

DIRECTIONAL DRILLING • This refers to the trajectory of a well when at some point it is swayed from the vertical to drill at an angle to reach a target some way laterally from the wellhead. • Increasing the exposed section length through the reservoir by drilling through the reservoir at an angle. • Drilling into the reservoir where vertical access is difficult or not possible. For instance an oilfield under a town, under a lake, or underneath a difficult-to-drill formation. • Upcoming video will have a clear visualise on it.

LOGGING TECHNIQUES Mainly logging techniques are comprised of 1. Electric Logging 2. Radioactive logging 3. Gamma ray logging 4. Nuclear magnetic resonance logging 5. Acoustic logging

1. ELECTRIC LOGGING • Resistivity logging measures the subsurface electrical resistivity, which is the ability to impede the flow of electric current. • This helps to differentiate between formations filled with salty waters (good conductors of electricity) and those filled with hydrocarbons (poor conductors of electricity). • As oil does not conduct electricity, it shows higher resistivity and it differentiate between water and oil presence.. • Resistivity and porosity measurements are used to calculate water saturation.

2. RADIOACTIVE LOGGING • There are those that measure the natural radiation generated by the formation, such as the total and spectral gamma ray logs. • Those that measure the response of the formation to radiation generated by the tool, such as the neutron, density and litho-density logs. • Radioactivity is a fundamental property of the structure of all matter. • The atoms of all elements have a nucleus which contains different numbers of protons and neutrons, which is surrounded by a sheath of electrons that are arranged in different energy levels.

BEHAVIOUR OF DIFFERENT MATERIALS

3. GAMMA RAY LOGGING • Gamma ray logs reflect naturally occurring radiation in rocks penetrated by the borehole. • Although several types of rays are emitted, only gamma rays have enough penetration to be of practical use in logging the natural radioactivity of rocks. • All natural rocks contain some radioactive material. • However, compared to that of uranium or radium ore, even of low grade, the radioactivity of most rocks is very small. • The radioactivity of a rock is usually expressed in terms of equivalent amount of radium per gram of rock required to produce the same gamma ray intensity.

Effect of Casing • Most of the gamma rays emitted by the formation can penetrate casing, so that a gamma ray curve can be obtained in cased holes, although the amplitudes of the curve are somewhat reduced. For example, a 5/16 inch thickness of steel reduces the gamma ray intensity about one fourth. Effect of Mud • It absorbs a small percent of the radiation and therefore reduces the log amplitude; unless the hole diameter is very large (more than 24") this effect is very small and can be ignored. Effect of Hole Size • The larger the hole, the smaller the gamma ray intensity reaching the probe. However, this effect is small and can generally be neglected.

APPLICATION OF GAMMA RAY LOGS Gamma ray logs are used in the following instances. 1.

To log cased holes (no electric log can be obtained in cased holes).

2.

To log dry holes (no electric log can be obtained in holes that do not contain water or mud).

3.

To log holes containing salt water or salty mud (the electric logs obtained in such holes are generally poor).

4.

To supplement the information given by the electric log (identification of formations, estimating the amount of clay in sands, etc.)

5.

To locate radioactive ores, uranium in particular.

6.

To help locate lignite and coal beds.

7.

To help locate clay and fresh water sands.

4. NUCLEAR MAGNETIC RESONANCE LOGGING • In petroleum industry this technology is used in petro physical laboratory research and subsequently developed downhole logging tools for in-situ reservoir evaluation. • A subcategory of electromagnetic logging. • NMR effectively responds to the volume, composition, viscosity, and distribution of these fluids, for example: – Oil – Gas – Water

• Provide information about the quantities of fluids present, the properties of these fluids, and the sizes of the pores containing these fluids. – The volume (porosity) and distribution (permeability) of the rock pore space – Rock composition – Type and quantity of fluid hydrocarbons – Hydrocarbon producibility • Provides measurements of a variety of critical rock and fluid properties in varying reservoir conditions (e.g., salinity, lithology, and texture), some of which are unavailable using conventional logging methods and without requiring radioactive sources . • Disadvantages: – the most complex logging service introduced to date – requires extensive pre-job planning to ensure optimal acquisition of the appropriate data needed to achieve the desired objectives.

5. ACOUSTIC LOGGING • Provides a measure of a formation’s capacity to transmit seismic waves • Varies with – Lithology – Rock texture – Decreases with increase in effective porosity.

• Seismic velocity is calculated using set of two receivers, one near and one far. • Travel time

• Porosit y

• V = seismic velocity of the formation • Vf = seismic velocity of the pore fluid • Vmat = seismic velocity of the rock matrix •

= porosity

UNIVERSIT Y OF PETROLEUM & ENERGY

NATURAL GAS LIQUIDS RECOVERY INTRODUCTION •

Most natural gas is processed to remove the heavier hydrocarbon liquids from the natural gas stream.

•

These heavier hydrocarbon liquids, commonly referred to as natural gas liquids (NGLs), include ethane, propane, butanes, and natural gasoline (condensate).

•

Recovery of NGLcomponents in gas for dew point control & yields a source of revenue.

•

Lighter NGL fractions, such as ethane, propane,and butanes, can be sold as fuel or feedstock to refineries and petrochemical plants, while the heavier portion can be used as gasolineblending stock.

Gas Condensate Reservoirs •

Gas condensate reservoirs have been defined as those hydrocarbon reservoirs that yield gas condensate liquid in the surface separator(s).

•

A retrograde gas condensate reservoir is one whose temperature is below the cricondentherm (the maximum temperature at which liquid and vapor phases can coexist in equilibrium for a constant-composition multicomponent system).

•

As pressure decreases below the dew point due to production, a liquid phase develops within the reservoir, which process is called retro grade condensation.

Figure 1: shows a pressure-temperature phase d i a g r a m .

Options of Phase Change •

To recover and separate NGL from a bulk of gas stream, a change in phase has to take place. In other words, a new phase has to be developed for separation to occur. Two distinctive options are in practice depending on the use of ESA or MSA.

Energy Separating Agent (Refrigeration)

(Distillation)

Mass Separating Agent •

To separate NGL, a new phase is developed by using either a solid material in contact with the gas stream (adsorption) or a liquid in contact with the gas (absorption).

Parameters Controlling NGL Separation • • •

Operating pressure, P Operating temperature, T System composition or concentration, x and y

To obtain the right quantities of specific NGL constituents, a control of the relevant parameters has to be carried out: 1. For separation using ESA, pressure is maintained by direct control. Temperature, on the other hand, is reduced by refrigeration using one of the following techniques: (a) Compression refrigeration (b) Cryogenic separation; expansion across a turbine (c) Cryogenic separation; expansion across a valve

2. For separation using MSA, a control in the composition or the concentration of the hydrocarbons to be recovered (NGL); y and x is obtained by using adsorption or absorption methods.

In Summary •

The efficiency of condensation, hence NGL recovery, is a function of P, T, gas and oil flow rates, and contact time. Again, absorption could be coupled with refrigeration to enhance condensation.

•

A proper design of a system implies the use of the optimum levels of all operating factors plus the availability of sufficient area of contact for mass and heat transfer between phases.

Figure 2:Thermodynamic pathways of different NGL recovery technologies.

Mechanical Refrigeration Mechanical refrigeration is the simplest and most direct process for NGL recovery. of condensate are expected. This process may also lead to the recovery of liquified petroleum gas, where for LPG recovery up to 90%, a simple propane refrigeration system provides refrigeration at temperatures to −40o F.

Flow sheet of a mechanical refrigeration process

Salient Features •

propane as the refrigerant

•

gas-to-gas heat exchanger recovers additional refrigeration

•

The temperature of the cold gas stream leaving this exchanger “approaches” that of the warm inlet gas

•

The chiller in is typically a shell and tube, kettle-type unit

•

The refrigerant (often propane) boils off and leaves the chiller vapor space essentially as a saturated vapor.

•

The thermodynamic path followed by the gas in an external refrigeration process is shown as line ABC in Figure 2. From A to B indicates gas-to-gas heat exchange; from B to C, chilling.

•

Hydrate formation is prevented either by dehydration of the gas or by injection of a hydrate inhibitor.

Choice of Refrigerant • Any material could be used as a refrigerant. The ideal refrigerant is nontoxic, non-corrosive, has Pressure-Volume-Temperature (PVT) and physical properties compatible with the system needs, and has a high latent heat of vaporization. •

The practical choice reduces to one, which has desirable physical properties and will vaporize and condense at reasonable pressures at the temperature levels desired.

Cascade Refrigeration • Cascade refrigeration refers to two refrigeration circuits thermally connected by a cascade condenser, which is the condenser of the lowtemperature circuit and the evaporator of the high-temperature circuit. •

A cascade system utilizes one refrigerant to condense the other primary refrigerant, which is operating at the desired evaporator temperature. This approach is usually used for temperature levels below −90◦F, when light hydrocarbon gases or other low boiling gases and vapors are being cooled.

Mixed Refrigerants •

An alternative to cascade refrigeration is to use a mixed refrigerant. Mixed refrigerants are a mixture of two or more components. The light components lower the evaporation temperature, and the heavier components allow condensation at ambient temperature.

•

The evaporation process takes place over a temperature range rather than at a constant temperature as with pure component refrigerants. The mixed refrigerant is blended so that its evaporation curve matches the cooling curve for the process fluid.

•

Heat transfer occurs in a countercurrent exchanger, probably an aluminum plate fin, rather than a kettle-type chiller. Mixed refrigerants have the advantage of better thermal efficiency because refrigeration is always being provided at the warmest possible temperature.

Self-Refrigeration In this process, the nonideal behavior of the inlet gas causes the gas temperature to fall with the pressure reduction, as shown by line ABC’ in Figure2. The temperature change depends primarily on the pressure drop.

Flow sheet of a self-refrigeration system

•

If the objective is to recover ethane or more propane than obtainable by mechanical refrigeration, a good process can be self-refrigeration, which is particularly applicable for smaller gas volumes of 5 to 10 MMCFD.

•

The self-refrigeration process is attractive if the inlet gas pressure is very high. It is important that the reservoir pressure remain high for the intended life of the plant.

•

Low-pressure inlet gas favors a cryogenic refrigeration plant or straight refrigeration process

Cryogenic Refrigeration •

Cryogenic refrigeration processes traditionally have been used for NGL recovery.

•

These plants have a higher capital cost but a lower operational cost.

•

In the cryogenic or turboexpander plant, the chiller or Joule–Thomson (JT) valve used in two previous processes is replaced by an expansion turbine.

•

The expansion process is indicated as line ABC” in Figure 2.

•

The turbine can be connected to a compressor, which recompresses the gas with only a small loss in overall pressure.

Typical flow sheet of a cryogenic refrigeration plant

Schematic of Ortloff gas subcooled process

Schematic of Ortloff residue split-vapor process

Simplified flow diagram of an oil absorption plant

Schematic of a solid bed adsorption plant

NATURAL GAS PROCESSING

Lecture by, M.Aslam Abdullah VIT University, Vellore.

FIGURE 1 Schematic of conventional turboexpander process with no recycle to demethanizer. Note that the one heat exchanger represents a network of exchangers. (Adapted from Engineering Data Book, 2004e.)

FIGURE 2 Cold-residue recycle process for maximizing ethane recovery.

Three basic methods are used for removal of nitrogen from natural gas: 

Cryogenic distillation



Adsorption



Membrane separation

TABLE 1 : Comparison of Nitrogen Removal Processes

FIGURE 3 NRU by use of two-column cryogenic distillation. Valves are JT valves.

FIGURE 4 Simple pressure swing adsorption (PSA) system.

FIGURE 5 Separating N2 from natural gas by use of membranes.

FIGURE 6 Schematic of an enhanced oil recovery (EOR) system.

NATURAL GAS: OFFSHORE PRODUCTION & HANDLING

Lecture by M . A s l am A b d u ll a h

25 July 2020

School of Chemical Engineering, VIT University.

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Process of Offshore Oil and Gas Developments The process of developing offshore oil and gas reserves can be divided into the following major steps: 1. Exploration 2. Exploratory drilling 3. Development drilling 4. Production 5. Storage and offloading 6. Transportation

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FACTORS DRIVING DEEPWATER RUSH 1.

Growing global demand for energy.

2.

Traditional fields fast exhausting.

3.

Declining production & reserves.

4.

Pressure to diversify supply.

5.

Oil supply jitters.

6.

Energy economics.

7.

Technological advent.

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Dept.of Chemical Engineering, VIT University.

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DEEP WATER TECHNOLOGIES In order to meet the current demand for hydrocarbon based fuel, the scout for it is widespread with demanding impetus on technological innovations.

Problems associated with Offshore (deep water) areas are: 1. Reservoir characterization.

7. Tidal waves

2. Reservoir management.

8. Corrosion

3. Source- rock prediction.

9. Wind

4. Formation water properties.

10. Fatigue

5. Granite reservoir characterization.

11. Salinity

6. Pore pressure & temperature prediction.

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12. Thermal shock (steep gradient, seasonal change, fluid injection)

Dept.of Chemical Engineering, VIT University.

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DEEP WATER TECHNOLOGIES Factors affecting field services in deep water on a macro-basis can be given as: 1. Unconventional oil (tar sands) vs. deepwater. 2. Novel Deepwater technology trends. 3. Drilling technologies. 4. Subsea technologies. 5. Forecast for deepwater oilfield services. 6. Hydrate formation. 7. High temperature High Pressure.

25 July 2020

Dept.of Chemical Engineering, VIT University.

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DEEP WATER TECHNOLOGIES Classification of problems encountered in general: 1. Deepwater projects take up to 10 years from discovery to first production. 2. Geology not cooperating (Like finding 100MMbl pockets when we used to find 500MMbl to 1bln barrel fields). 3. Cluster developments are expensive (five (100MMbl) fields do not equal one (500MMbl) field). 4. Escalating rig rates were a leading indicator for the cost increases across the sector for deepwater developments.

25 July 2020

Dept.of Chemical Engineering, VIT University.

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DEEP WATER TECHNOLOGIES To solve the deepwater issues it requires blend of many technologies like: 1. Reservoir geophysics seismic

6. Time-lapse

2. Seismic imaging stratiography

7. Seismic litho

3. Seismic signal processing drilling

8. Imaging while

4. 3D seismic characterization of reservoirs arrays

9. Ocean sensor

5. Multi-component seismology

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Location Surveys for Offshore Drilling The offshore environment has a much more significant influence on drilling operations than the onshore environment. It is necessary to carry out a suite of location surveys before starting drilling operations in order to obtain data such as weather forecast during drilling operations, bathymetric map around the location, current profiles, properties of the sea bottom soil, topography of the sea bottom, and shallow geological hazards. The minimum requirement of the survey includes following instruments: 1. 2. 3. 4. 5.

sparkers (Acoustic signal) sub-bottom profilers (Physical Properties) side-scan sonar (high frequency sound pulses) fathometers gravity corers (Sediment Extractor)

Wind and current measurements for several months would be carried out at a proposed location about one year ago before operations. 25 July 2020

Dept.of Chemical Engineering, VIT University.

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History of Offshore 1. 1st offshore well was drilled in 1947 in 15 feet of water in (Louisiana, USA). 2. 30 years ago, a deepwater operation implies exploring water depths up to 500 feet. 3. Today, deepwater refers to a well in up to 5,000 feet (1524m) of water . 4.

Ultra-deepwater exploratory drilling now occurring in water depths over 5000 ft to 10,000 feet. i.e.,( 1524m to 3048m)

5. The challenges in ultra deep reserves are more complicated than exploring space.

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Dept.of Chemical Engineering, VIT University.

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Classification of water depths  Shallow water generally refers to a depth less than 1000ft (304.8m).  Deep water refers to a depth greater than 1000ft (304.8m) and less than 5000ft (1524m).  Ultra-deepwater refers to a depth greater than 5000ft (1524m).

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Record depths achieved in Onshore/Offshore Onshore 1. The scientific research well “SG-3” in Russia reached the depth of 12,263 m in 1988, has had the depth record ever since. 2. The deepest exploration drilling for hydrocarbons was carried out to the depth of 9583 m in the United States of America in 1974.

Offshore 1. A hydrocarbon exploration well was drilled offshore Brazil in 2965 m of water in 2001. 2. A production well was completed with a subsea completion system offshore Brazil in 1852 m of water in 1998. The offshore technology is steadily in progress towards deeper and deeper seas to search and Dept.of Chemical Engineering, VIT 25 July 2020 produce subsea resources for the future welfare of the world. University.

11

As per SPE publication: “Since 1947, the offshore industry has moved from the first platform out of sight of land to safely producing in 7,000 feet (2,100 meters) of water and safely drilling in 10,000 feet (3,050 meters) of water.”

The industry is still learning, and there is more to come…

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Offshore Drilling Structures Technical Features of Offshore Drilling 1. Because of the location remote from infrastructure, offshore rigs also carry on board a number of service systems such as cementing, geophysical logging, and so on. 2.

In addition, there are lots of specific services on board such as divers, meteorological measurements, helicopter, etc.

3. Accommodations and catering for crews working for 24 hours are required on the rig. All these factors make offshore rigs complex and sophisticated, and therefore Dept.of Chemical Engineering, VIT 25 July 2020 offshore drilling costs are higher thanUniversity. land drilling costs for similar

13

There are two basic types of offshore drilling rigs:

Moveable rigs are often used for exploratory purposes because they are much cheaper to use than permanent platforms. Once large deposits of hydrocarbons have been found, a permanent platform is built to allow their extraction.

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Different types of moveable offshore platforms: Rigs that can be moved from place to place, allowing for drilling in multiple locations (Mobile bottom- supported and floating rigs). 1.

Drilling Barges.

2.

Jack-Up Rigs.

3.

Submersible Rigs (swamp barges).

4.

Semisubmersible Rigs (Anchor-stationed or dynamically positioned).

5.

Drillships (Anchor-stationed or dynamically positioned ).

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Drilling structures used for developing offshore fields from stationary platforms are of two types: Rigs that are permanently placed. 1.

Self-contained platforms: (The large production platform equips a complete set of drilling equipment, and is called as self-contained platform)

2.

Tender or jack-up assisted platforms or well-protector jackets :The small platform has a space only to accommodate derrick and draw works, so a kind of tender assists the work)

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Guidelines To choose roughly the type of offshore drilling rigs according to water depth and conditions of sea state and winds:

Water depth less than 25 m: Submersible rigs (swamp barges). Water depth less than 50 m and calm sea: Tender or Jack-up assisted platforms. Water depth less than 400 m and mild sea: Self-contained platforms. Water depth from 15 m to 150 m: Jack-up rigs. Water depth from 20 m to 2000 m: Anchored Drillships or Semisubmersible rigs. Water depth from 500 m to 3000 m: Drillships or Semisubmersible rigs with dynamic positioning system. Isolated area with icebergs: Drillships with dynamic positioning system. Severe sea conditions: Semisubmersible rigs or new generation Drillships .

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Mobile Bottom-supported Structures 1. Jack-up Drilling Rigs (Jack-up Rigs, Self-elevating Drilling Rigs) 2. Submersible Drilling Rigs (Submersible Rigs, Swamp Barges) 3. Tender-Assisted Platforms and Tenders

25 July 2020

Dept.of Chemical Engineering, VIT University.

18

Floating Offshore Structures (Floaters) Neutrally buoyant structures which are dynamically unrestrained and are allowed to have 6 degrees of freedom (heave, surge, sway, pitch, roll and yaw) are: 1. Drillships. 2. Semisubmersible Drilling Rig 3. Spars Positively buoyant structures which are tethered to the seabed and are heave-restrained are: 4. Tension Leg Platforms (TLPs) 5. Tethered Buoyant Towers (TBTs) 6. Buoyant Leg Structures (BLS)

25 July 2020

Dept.of Chemical Engineering, VIT University.

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Offshore structures for drilling

Offshore structures for production

1

Platform Rigs

1

Fixed Platforms a) Steel Jackets b) Concrete gravity-based structures

2

Mobile Offshore Drilling Units a) Drilling Tenders b) Jackups c) Submersibles d) Semisubmersibles e) Drillships

2

Floating Production Systems a) Semisubmersibles b) Tension-leg Platforms c) Spar Platforms d) Ship-Shaped FPSO’s

For drilling as well as production these units are modified for dual function. (Excluding TLP

and SPAR, because of limited motions these are suitable for surface-completed wells only)  Example for Drilling, production & Storage in 1 unit is FPDSO (Floating Production

Drilling Chemical Engineering, VIT for its development) Storage &2020 Offloading) (vessel motionsDept.of is the only hesitation 25 July University.

20

Largest Offshore Structures

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Dept.of Chemical Engineering, VIT University.

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Various types of Offshore Structures

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General Classification of Structures: (I) Bottom-Supported Structures (II) Compliant Structures (III) Floating Structures

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Dept.of Chemical Engineering, VIT University.

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(I) Bottom-Supported Structures 1. Minimal Platforms:

Field development in shallow water uses fixed production platforms with a small deck. Example minimal platform concepts (LINX, MANTIS II and TRIPOD) for marginal field

25 July 2020

Dept.of Chemical Engineering, VIT University.

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(I) Bottom-Supported Structures 2. Jacket Structures: Fixed jacket structures (or template structures) consist of tubular members interconnected to form a three-dimensional space frame

25 July 2020

Dept.of Chemical Engineering, VIT University.

25

(I) Bottom-Supported Structures 3. Gravity Base Structures: Offshore structures that are placed on the seafloor and held in place by their weight are called gravity structures.

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Gravity Base Structure

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25 July 2020

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25 July 2020

Dept.of Chemical Engineering, VIT University.

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(I) Bottom-Supported Structures 4. Jack-ups: The jack-up barges are typically three-legged structures having a deck supported on their legs. The legs are made of tubular truss members. The deck is typically buoyant.

5. Subsea Templates: Subsea technology covers a wide range of offshore activities. Examples are subsea Xmas trees, manifolds, templates, flowlines and risers, control systems, well fluid boosters, multiphase pumping and metering, water separation, water injection, remote and diverless connections, guideline-free installations, seabed electrical power distribution systems, interventions, etc.

6. Subsea Pipelines: Subsea pipelines are used to transfer oil from the production platforms to storage facilities or to the shore. 25 July 2020

Dept.of Chemical Engineering, VIT University.

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Jack-Up Drilling Rig with Triangular Shape and 3 Legs (JDC Hakuryu 8) (Reproduced Courtesy of Japan Drilling Co.) 25 July 2020

Dept.of Chemical Engineering, VIT University.

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There are two basic leg configurations of jack-up rigs: 1.Independent-leg type for relatively firm seabed: Each independent leg has a spud can on the end. The leg penetrates soil below the mud line, i.e. the sea bottom. The penetration depends on the composition of the soil and the shape of spud can. 2.Mat-supported type for soft seabed: Legs is connected with a mat. The mat rests on the seabed to stably support the rig. The type is used on flat seabottom in water depth of up to 50 m. The penetration is slight.

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(I) Bottom-Supported Structures 7. Submersible Drilling Rigs (Submersible Rigs, Swamp Barges) Submersible drilling rigs consist of upper and lower hulls connected by a network of posts or beams. The drilling equipment and living quarters are installed on the upper hull deck. The lower hull has the buoyancy capacity to float and support the upper hull and equipment. When water is pumped into the lower hull, the rig submerges and rests on the seabed to provide a working place for the drilling. Movement and drilling operations proceed as that of the jack-up rig. Most submerged rigs are used only shallow waters of 8 to 10 meters. Ship-shaped submersible rigs are also used, which are called swamp barges.

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Submersible Drilling Rig (Noble FriRodli) (Reproduced Courtesy of Noble Drilling Corporation) 25 July 2020

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(I) Bottom-Supported Structures 8. Tender-Assisted Platforms and Tenders In regions where the weather conditions are not harsh, it is possible to use lower cost fixed platforms that are designed to support only the derrick and the drawworks. The tender anchored alongside the platform contains drilling equipment such as pumps and tubular goods, and accommodation for personnel. A catwalk connects the platform and the tender. If weather conditions (wind, swell, and current) become too harsh, the drilling operations must be shut down due to excessive motion of the tender. The tender platforms are used in Gulf of Guinea and the Persian Gulf waters where good weather conditions prevail, resulting in low downtime less than 2% of total operation time.

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Platform (left) and Semisubmersible Tender (right) (Atwood Oceanics SEAHAWK) (Reproduced Courtesy of Atwood Oceanics, Inc.) 25 July 2020

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(II) Compliant Structures Compliant structure by definition includes those structures that extend to the ocean bottom and directly anchored to the seafloor by piles and/or guidelines. Typically designed to have their lowest modal frequency to be below the wave energy, as opposed to the fixed structures, which have a first modal frequency greater than the frequency of wave energy.

1. Articulated Platforms: One of the earliest compliant structures that started in relatively shallow waters and slowly moved into deep water.

“Articulated tower is an upright tower, which is hinged at its base with a cardan joint and is free to oscillate about this joint due to the environment.” The base below the universal joint on the seabed may be a gravity base or may be piled. The tower is ballasted near the universal joint and has a large enough buoyancy tank at the Dept.of Chemical Engineering, VIT 25 Julysurface 2020 43 free to provide large restoring force (moment). University.

(II) Compliant Structures 2. Compliant Tower: A compliant tower is similar to a traditional platform and extends from surface to the sea bottom, and it is fairly transparent to waves. Compliant tower is designed to flex with the forces of waves, wind and current. It uses less steel than a conventional platform for the same water depth.

3. Guyed Tower: A guyed tower is a slender structure made up of truss members, which rests on the ocean floor and is held in place by a symmetric array of catenary guylines.

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(III) Floating Structures Floating Platform Types: The floating structures may be grouped as Neutrally Buoyant and Positively Buoyant. structures include Spars, Semi-submersible MODUS and FPSs, Ship-shaped FPSOs and Drillships. structures are TLPs, TLWPs and Buoyant Towers. 25 July 2020

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Technologies Required by Floaters: Outline of Drilling System of Semisubmersible Rig (Modified from Sekiyukaihatsu Gijutsu no Shiori (1st edition). Reproduced Courtesy of Japan Petroleum Development Association)

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Technologies Required by Floaters:

The motion compensator is a device to maintain constant weight on the bit during drilling operation in spite of oscillation of the floater due to wave motion.

Crown Mounted Type of Heave Compensator (Reproduced Courtesy of National Oilwell Kristiansand) 25 July 2020

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(III) Floating Structures Production Units (FPSO and FPS) Most floating production units are neutrally buoyant structures (which allows six-degrees of freedom) which are intended to cost-effectively produce and export oil and gas.

1. FPSO: The FPSO generally refers to ship-shaped structures with several different mooring systems.

2. FPS FPS refers to Floating Production systems which are finding application in marginal and deepwater field development. 25 July 2020

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A computer graphic of a ship-shaped offshore installation (FPSO) with a shuttle tanker offloading system. 25 July 2020

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Drillships

The Larger is a Drillship with Dual-Activity Drilling System (TSF Discoverer Enterprise), and the Smaller is a Previous Generation Drillship (TSF Discoverer 534) Alongside with a Supply Boat 25 July 2020

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(III) Floating Structures 3. Semi-Submersible Platform: Semi-submersibles are multi-legged floating structures with a large deck. These legs are interconnected at the bottom underwater with horizontal buoyant members called pontoons.

Semisubmersible Platform 25 July 2020

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A computer graphic of a semisubmersible installation.

A computer graphic of a semisubmersible installation. 25 July 2020

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The advantages of semisubmersibles include the following: 1. Semisubmersibles can achieve good (small) motion response and, therefore, can be more easily positioned over a well template for drilling. 2. Semisubmersibles allow for a large number of flexible risers because there is no weathervaning system. Disadvantages of semisubmersibles: 3. Pipeline infrastructure or other means is required to export produced oil. 4. Only a limited number of (rigid) risers can be supported because of the bulk of the tensioning systems required. 5. Considering that most semisubmersible production systems are converted from drilling rigs, the topsides weight capacity of a converted semisubmersible is usually limited. 4. Building schedules for semisubmersibles are usually longer than those for shipshaped offshore structures. 25 July 2020

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Semisubmersible (As Drilling Rig) Semi-submersibles are multi-legged floating structures with a large deck. These legs are interconnected at the bottom underwater with horizontal buoyant members called pontoons. Semisubmersibles have submerged pontoons (lower hulls) that are interconnected to the drilling deck by vertical columns The lower hulls provide improved stability for the vessel. Also, the open area between the vertical columns of semisubmersibles provides a reduced area on which the environment can act. In drilling operations, the lower hulls are submerged in the water about half-length of the column, but do not rest on the seabed. When a semisubmersible moves to a new location, the lower hulls float on the sea surface. Semisubmersible rigs are towed by boats, and some rigs have selfpropelled capacity. On drilling site to keep the position, the anchors usually moor semisubmersibles, but the dynamic positioning systems are used by new generation semisubmersibles. 25 July 2020

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Semisubmersible Drilling Rig

Semisubmersible Drilling Rig (JDC Hakuryu 3) (Reproduced Courtesy of Japan Drilling Co.) 25 July 2020

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Because of the reduced heave motion, the use of rigid risers (instead of flexible risers), which are self-buoyant, is easier.

(III) Floating Structures 4. Spar: The Spar concept is a large deep draft, cylindrical floating Caisson designed to support drilling and production operations. Its buoyancy is used to support facilities above the water surface. It is, generally, anchored to the seafloor with multiple taut mooring lines. Because of the reduced heave motion, the use of rigid risers (instead of flexible risers), which are self-buoyant, is easier. Types of Spars: 1. Classic spar 2. Truss spar 3. Cell spar

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SPAR platforms

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(III) Floating Structures 5. Tension Leg Platform: A Tension Leg Platform (TLP) is a vertically moored compliant platform. The floating platform with its excess buoyancy is vertically moored by taut mooring lines called tendons (or tethers). The structure is vertically restrained precluding motions vertically (heave) and rotationally (pitch and roll). It is compliant in the horizontal direction permitting lateral motions (surge and sway).

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A computer graphic of a tension leg platform (TLP) installation. 25 July 2020

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(III) Floating Structures 5.1. MiniTLPs: SeaStar and Moses SeaStar is a deepwater production and utility mini-platform. SeaStar is a small TLP with a single surface-piercing column. It borrows from the concept of the tension leg platform and provides a cost-effective marginal field application. Moses MiniTLP appears to be a miniaturized TLP as the deck structure is supported by four columns and the columns are connected by pontoons. Motion characteristics of Moses is similar to that of SeaStar and, unlike the standard TLPs, miniTLPs need to dedicate a large percentage of their displacement (35 - 45%) for pretension.

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SeaStar Mini TLP 25 July 2020

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Function

Bottom-founded vs. floating structures Bottom-Supported Floating

Payload support

Foundationbearing capacity

Buoyancy

Well access

“rigid” conduits (conductors) surface wellheads and controls

"dynamic" risers subsea wellheads subsea or surface controls

Environmental loads

Resisted by strength of structure and foundation, compliant structure inertia

Resisted by vessel inertia and stability, mooring strength.

Construction

Tubular space frame: fabrication yards

Plate and frame displacement hull: ship yards

Installation

Barge (dry) transport and launch, upend, piled Foundations

Wet or dry transport, towing to site and attachment to pre-installed moorings

Regulatory and design practices

Oil Industry practices and government petroleum regulations

Oil industry practices, government petroleum regulations and Coast Guard & International Maritime regulations

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Worldwide offshore rigs and offshore production growth. Worldwide offshore rigs and offshore production growth. For more than 20 years, there has been a direct relationship between offshore production and the number of development drilling rigs operating, a trend that is expected to continue well into the 21st century.

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