1. NATURAL GAS ENGINEERING

2. INTRODUCTION What Is Natural Gas?
Natural gas is a subcategory of petroleum that is a naturally occurring, complex mixture of hydrocarbons, with a minor amount of inorganic compounds.

3. Table 1-1 shows composition of a typical natural gas.

4. Natural Gas Value Chain
The conversion of natural gas into a liquid has been an elusive objective for a long time. Some parts of the produced gas – propane, butane, and the natural condensate, can be shipped as LPG or natural gasoline. If it is available in sufficient quantity, the ethane can be split out and converted into petrochemicals (ethylene and its derivatives). The big question has always been what to do with the methane.
The chart shows the overall picture for natural gas monetization options. The methane, or C1, portion can be transported by pipeline or by liquefaction and shipping, or it can be chemically converted to a liquid as methanol or by using the Fischer-Tropsch reaction.

5. Figure 1: Chart foe Natural Gas Value line

6. Table-1.2

7. Gas Reserves in India
India has a bright long term natural gas supply outlook. Certified reserves of over 28 BCM on a deepwater block in the Krishna/Godavari basin is a conservative figure with respect to significant potential for future discoveries in the basin and the Bay of Bengal. More than 9 big discoveries have been made in less than 3 years and a further multi-million deepwater exploration program was kicked off recently.
The very first exploratory venture by RIL in this block has resulted in world’s largest gas discovery for the year In addition, there is a high probability of success based on the data available is expected for the unexplored deeper targets. These targets are expected to yield new discoveries and consequently the resources from the field are expected to grow with time. It is anticipated that through sustained exploratory drilling in the next few years, the reserves are likely to increase and may range from tcf.

8. Miscellaneous Activities for New Opportunities to Petroleum Specialists
ONGC signed an agreement with L.N. Mittal group to form two 51:49 % joint venture companies - OMEL (ONGC Mittal Energy Ltd) and OMESL (ONGC Mittal Energy Services Ltd) for exploration, production and shipping activities abroad
OMEL has entered into an MOU with Nigeria under which the later will allocate deep water exploration blocks in Nigeria that are expected to yield 32.5 million tones of oil every year for 25 years. The right of PSC has been obtained by offering Abuja a $ 6 billion “capacity build up” package. OMEL will build or get Indian companies to build power plants, railway system, refining capacity and training institutes in Nigeria, in return of equity oil

9. ONGC Videsh will hold 50 % stake, Engineers India 25 %, Indian Oil Corporation 15% and Oil India the remaining 10 % in the US $ 750 million refinery revamp and petroleum products pipeline projects in Sudan.
ONGC has offered 26 % partnership in to Coal India Ltd (CIL) in its Underground Coal Gasification projects. CIL is also likely to join ONGC in its CBM projects.
ONGC board has approved setting up of a new company Opal (ONGC Petro-additions Private Ltd) to implement the C2-C3 extraction plant at Dahej from rich LNG to be supplied by Petronet LNG Ltd.

10. ONGC Videsh has signed a MOU with Ghana National Petroleum Corporation GNPC) to study and evaluate data of Central basin so as to enter an agreement for exploration, development and production agreement.
GAIL and EIL (Engineers India Ltd) have signed a MOU for gas processing and transportation projects abroad.
IOC (Indian Oil Corp) and STATOIL, Norway have formed into a SPV (Special Purpose Vehicle) for acquisition of prospective exploration acreage and producing properties. They have also entered into a agreement for the formation of joint venture SPV towards securing service business in oil and gas industry internationally.

11. ONGC Videsh and Norsk Hydro have signed a MOU under which the companies will make opportunities available for each other’s consideration on nonexclusive basis.
ONGC has entered into an MOU with ENI for exchanging information in a wide range of exploration opportunities in India and overseas and be a strategic partner with state of art technology, specially in deep water exploration and development.
OILEX of Australia has acquired 30 % stake in onshore Cambay gas field in Gujarat from GSPC

17. 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. 17

18. Figure 4.1 A sketch of a Oil or Gas production system.
Pwf = flowing bottom hole pressure
= average reservoir pressure 18

19. 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 19

20. Figure 4.2a A typical hydrocarbon phase diagram.20

21. 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. 21

22. 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 22

23. Retrograde gas-condensate reservoir: If the 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. 23

24. 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. 24

25. Figure :4.2b A typical phase diagram of a retrograde system.25

26. 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 gas-condensate reservoirs, the condensed liquid volume seldom exceeds more than 15%–19% of the pore volume. 26

27. • Gas-oil ratios between 8,000 to 70,000 scf/STB. Generally, the gas-
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. 27

28. 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. 28

29. Near-critical gas-condensate reservoir
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. 29

30. Figure :4.2c A typical phase diagram for a near-critical gas condensate reservoir.30

31. 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. 31

32. • Gas oil ratios between 60,000 to 100,000 scf/STB
This is caused by a sufficient decrease in the kinetic energy of heavy molecules with temperature drop and their subsequent change to liquid through the attractive forces between molecules. Wet-gas reservoirs are characterized by the following properties:
• 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. 32

33. Figure :4.2d Phase diagram for a wet gas.33

34. 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. 34

35. Figure :4.2e Phase diagram for a dry gas..35

36. 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 36

37. 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. 37

38. Well
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 38

39. 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. 39

40. Figure 4.3 A sketch of a wellhead.40

41. Figure 4.4 A sketch of a casing head.41

42. Figure 4.5 A sketch of a tubing head.
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]).
Figure 4.5 A sketch of a tubing head. 42

43. 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). 43

44. Figure 4.6 A sketch of a ‘‘Christmas tree.’’44

45. 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). 45

46. Figure 4.7 A sketch of a surface valve.46

47. ‘‘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 well-bore decreases the flow rate from the reservoir 47

48. Figure 4.8 A sketch of a wellhead choke.48

49. 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:
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.
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. 49

50. The operator opens the other downstream valves the same way.
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. 50

51. 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. 51

52. Figure 4.9 A sketch of a radial flow reservoir model: (a) lateral view, (b) top view.52

53. 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. 53

54. 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. 54

55. Figure 4.10 A sketch of a reservoir with a constant-pressure boundary.55

56. 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. 56

57. Figure 4.11 A sketch of a reservoir with no-flow boundaries.57

58. Thank You 58