Ongc Project 2

On

“DRILLING AND PRODUCTION OPERATIONS”

Drilling Services, ONGC, Ankleshwar Asset

Indian School of Mines University, Dhanbad

Report Submitted By:

Md Hamid Siddique, Saumya,

Saurabh Mishra, Mohit Garg,

Praveen Kumar, Prakash Mishra

(M.Tech in Petroleum Engineering)

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CERTIFICATE

This is to certify that following Students of M.tech, 1st Year, Petroleum Engineering, Indian School of Mines, Dhanbad has successfully completed summer training and submitted project-report titled “ DRILLING AND PRODUCTION OPERATIONS ” at Drilling Services, Ankleshwar Asset, ONGC.

Md Hamid Siddique, Saumya,

Saurabh Mishra, Mohit Garg,

Praveen Kumar, Prakash Mishra

(M.Tech in Petroleum Engineering)

Indian School of Mines, Dhanbad

Mr. S.K.Mandloi

Chief Engineer (D),

Drilling Services, ONGC Ankleshwar Asset.

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ACKNOWLEDGEMENT

The trainee wishes to thank OIL AND NATURAL GAS CORPORATION Ltd. Ankleshwar Asset for allowing to conduct training program at their premises and for providing all the needful facilities required for completion of the entire program.

We would like to express our sincere gratitude towards our mentor Mr. S.K. Mandloi (SE) – Drilling Services for his continuous guidance and for enlightening us with vital knowledge throughout the program. Working under his guidance has been a privilege and a fruitful learning experience. We would also like to thank Mr. Aloke Deb (CE) – Cementing Services for his constant support and for arranging several field visits during the course of my training.

We are also thankful to Mr. M.C. Sharma, SE (D)-(DTYS); Mr. Sunder Lal, SC (Mud Services); Mr. P.K. Gupta, CE (Cementing); Mr. S.K. Sindha, EE (Drilling); Mr. P.K. Jog, EE (Drilling); Mr. Sanjeev Kumar, EE (drilling) in providing us with valuable knowledge about drilling operations.

We express our deep gratitude to those who have helped and encouraged us in various ways in carrying out this project work. We would like to extend our thanks and would like to acknowledge the ONGC personnel for sharing their valuable knowledge with us without which the completion of this project would have been rather impossible.

_____________________

Mr. S.K. Mandloi (SE)

INDEX

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1. INTRODUCTION2. ABOUT ANKLESHWAR ASSET

2.1 INTRODUCTION

2.2 GEOLOGY OF ANKLESHWAR

2.3 RESERVOIR PROPERTIES

2.4 BASIN INTRODUCTION

2.5 PETROLEUM SYSTEM

3. INTRODUCTION TO DRILLING

4. PRODUCTION OPERATION

5. WELL LOGGING SERVICES

6. SITE VISIT

7. CASE STUDY

REFERENCES

1 INTRODUCTION

The story of oil exploration in India began in dense jungles of Assam in the extreme northeast corner of India. Oil was struck at Makum near Margherita in Assam in 1867 just nine years after the historical Drake well in Pennsylvania in 1859. First commercial

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oil was discovered in Digboi in 1889. However, exploration and production started in a systematic way in 1899 after the Assam Oil Company (AOC) was formed.

After India attained independence in 1947, Geological Survey of India carried out extensive reconnaissance surveys and mapping to locate structures suitable for exploration of oil and gas. The real thrust to petroleum exploration in country was achieved only after the setting up of Oil and Natural Gas Commission (ONGC) in 1955. The first gas and oil pool were discovered in Jwalamukhi (Punjab) and Cambay (Gujarat) in 1958 respectively and in the same year Oil India Limited (OIL) was setup. The two public sectors companies, ONGC and OIL have discovered over 260 oil and gas fields located in Assam, Bombay Offshore Cambay, Cauvery, Krishna-Godavari, Tripura-Cachar and West Rajasthan basins.

Government of India (GOI) offered acreages for exploration in 1980, 1982 and 1986 but the response was not encouraging. The government of India further liberalized the petroleum exploitation and exploration policy in 1991 inviting private companies, both overseas and indigenous, to participate in exploration in oil and gas field development activities to meet the ever-increasing national demand for oil and gas. A more attractive policy was formulated by the Government in 1999 and designated as the New Exploration Licensing Policy (NELP). Since 1980, eight exploration rounds, one round for joint venture and six rounds under NELP have been offered for global bidding. In order to introduce new technology and oil production, the GOI offered 69 small and medium sized oil and gas fields in onshore and offshore to private sector in 1992 and 1993. The Government of India signed Production Sharing Contracts (PSCs) for 28 exploration blocks under Pre-NELP rounds since 1993. Out of these 12 blocks have been relinquished / surrendered. At present, 12 exploration blocks are under operation and 4 blocks are awaited for approval of additional exploration.

1. Under the first round of New Exploration Licensing Policy, Government of India invited bids on 8th January 1999 for 48 blocks for exploration of oil and natural gas.

2. Under the second round of New Exploration Licensing Policy, Government of India invited bids on 15th December 2000 for 25 blocks for exploration of oil and natural gas.

3. Under the third round of New Exploration Licensing Policy, Government of India invited bids on 27th March 2002 for 27 blocks for exploration of oil and natural gas.

4. Under the Fourth round of New Exploration Licensing Policy, Government of India invited bids on 8th May 2003 for 24 blocks for exploration of oil and natural gas.

5. Under the fifth round of New Exploration Licensing Policy twenty exploration blocks have been awarded to different consortiums/ individual company. A total of two discoveries have been made a KG deepwater block.

6. Fifty five exploration blocks were offered under the sixth round on 23rd February, 2006, the highest offering so far under NELP, covering an area of 3.52 lakhs Sq.Km. in order to enhance country’s energy security.

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7. Fifty-seven exploration blocks were offered under the seventh round, proposed bid closing date is 30th June.

THE ORGANIZATION

ONSHORE

ONGC has got seven producing asserts in Onshore - Ahmedabad, Mehasana,

Ankleshwar, Assam, Tripura, Rajahmundry and Cauvery Assets.

Two producing basins- Cambay and Assam Arakan Fold Belt (AAFB).

Cumulative Crude oil production- 282.114 MMT.

Cumulative Gas production- 110.27 BCM.

IOR schemes implemented in 13 major onshore fields.

OFFSHORE

Three producing Assets- Mumbai High, Neelam & Heera and Bassein & Satellite.

Joint ventures and production sharing contract for Ravva, Panna-Mukta and Tapti

fields.

Development of several Marginal Fields like- Vasai West (SB-11), Vasai East, C-

series, G-1 and GS-15 Offshore fields in East Coast, KG Basin, B-22 cluster, etc.

Oil and Gas produced from offshore processed at Uran and Hazira plant.

Cumulative Crude oil production-453.83 MMT.

Cumulative Gas production- 336.34 BCM

ONGC VIDESH LIMITED (OVL):

ONGC’s overseas arm ONGC Videsh Limited (OVL) is engaged in Exploration and

Production of Oil and Gas across the globe. It is the 2nd largest E&P Company in India,

both In terms of oil production and oil gas reserve holdings. It has marked presence in 39

E & P projects in 17 countries; Vietnam, Sudan, Russia, Iraq, Iran, Myanmar, Libya,

Cuba, Columbia, Nigeria, Nigeria Sao Tome JDZ, Egypt, Brazil, Congo BR,

Turkmenistan, Syria, Venezuela. OVL has produced 8.80 MMT of O+OEG in 2007-08

and an investment of over 4.5 billion USD.

2 ABOUT ANKLESHWAR ASSET

2.1 Introduction:-

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Field discovered in 1960. Put on production since 1960. Location at a distance of 15 km from Ankleshwar town. Part of Narmada Block of Cambay basin. Spread over an area of approx. 32.27 sq.km. Hydrocarbon entrapment in multi-layered sandstone reservoir.

2.2 GEOLOGY OF ANKLESHWAR Ankleshwar is the oldest on-shore oil field owned by ONGC. This field is located at a distance of 6 km from the Ankleshwar town of Gujarat state of India. The field is situated at Narmada – Tapti tectonic block of Cambay basin with the aerial extent of 32 sq.km. Geological Survey of India started exploration of oil and gas in the field as early as 1930s. Subsequently the geologists of Oil and Natural Directorate of India mapped the area and carried out the Gravity Magnetic survey during the year 1957-58. Seismic survey was carried out in the year 1958-59. An exploratory test well was released for confirming the hydrocarbon potential and the well was drilled in the year 1960 to a depth of 1969 meters. Large amount of oil and gas reserves have been established during subsequent

exploration and development activities in association with Russian Geoscientists. The major

oil and gas reserves are present within Hazad and Adol member of Ankleshwar formation.

Ankleshwar field comprise of mainly three producing horizons, i.e. Lower productive group developed in Cambay shale, middle and upper producing group developed in Ankleshwar formation.

The upper producing horizon, called Adol member of Ankleshwar formation is located within the Telwa and Kanwa and Cambay shale. Six important sand bodies are identified as S-6, S-7, S-8, S-9, S-10 and S-11 in Adol member. The Hazad member is sub divided in to five sands i.e. S-1, S-2, S-3, S-4 and S-5. There is only one sand body in lower producing horizons, called LS-1 developed at the bottom of the Cambay shale In addition to that, there are two gas bearing sands, i.e. Dadar sands within Tarkeshwar and Ankleshwar formation and Miocene sands in Babaguru formation. In addition to that, there are two gas bearing sands, i.e. Dadar sands within Tarkeshwar and Ankleshwar formation and Miocene sands in Babaguru formation.

2.3 RESERVOIR PROPERTIES

Major formations are in the Ankleshwar formation and Cambay shale

Initial super hydrostatic pressure has presently reduced to the sub hydrostatic.

The sands S-5 and LS-1hve got good porosity and moderate permeability values.

All other sand layers are having good values of porosity and permeability.

MAIN OPERATION ACTIVITES

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Exploration and exploitation of hydrocarbon to meet committed target to production and supply.

Reservoir health management to optimize recovery. Well servicing and minimizing non flowing wells and improving productivity. Quality, Health, Safety and Environment (QHSE) Management.

2.4 BASIN INTRODUCTION

Geographic Location of the basinThe Cambay rift Basin, a rich Petroleum Province of India, is a narrow, elongated rift graben, extending from Surat in the south to Sanchor in the north. In the north, the basin narrows, but tectonically continues beyond Sanchor to pass into the Barmer Basin of Rajasthan. On the southern side, the basin merges with the Bombay Offshore Basin in the Arabian Sea. The basin is roughly limited by latitudes 21˚ 00' and 25˚ 00' N and longitudes 71˚ 30' and 73˚ 30' E. (FIG: 1, Index Map)

Category of the basinProved

Area The total area of the basin is about 53,500 sq. km.

Age of the Basin & Sediment-thicknessThe evolution of the Cambay basin began following the extensive outpour of Deccan Basalts (Deccan Trap) during late cretaceous covering large tracts of western and central India. It’s a narrow half graben trending roughly NNW-SSE filled with Tertiary sedimentswithrifting due to extensional tectonics. Seismic and drilled well data indicate a thickness of about 8 km of Tertiary sediments resting over the Deccan volcanics.

Major Discoveries, Total Seismic coverage, 2D/3D and exploratory wells drilled A total of 12,937 gravity and magnetic stations were measured by the ONGC in the entire Cambay Basin. The Bouguer anomaly map has helped in identification of the major structural highs and lows in the basin. The magnetic anomaly map also depicts the broad structural configuration of the basin. A total of more than 30,688 LKM of conventional data has been acquired.

The total volume of seismic reflection data acquired from the Cambay Basin is of the order of 104113 LKM (2D) and 7895 sq. km (3D). (Fig: 2, Showing Density of Seismic coverage)

In 1958, ONGC drilled its first exploratory well on Lunej structure near Cambay. This turned out to be a discovery well, which produced oil and gas. The discovery of oil in Ankleshwar structure in 1960 gave boost to the exploration in the Cambay Basin. More than 2318 exploratory wells have been drilled in Cambay Basin. Out of 244 prospects drilled, 97 are oil and gas

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Exploration Status(Fig: 2 & 3 showing exploration status of N.Cambay & S.Cambay)

PEL AREAS ‘P’

ML AREA ‘M’

TOTAL AREAS ‘T’

UNEXPLORED AREAS ‘U’ = T – ( P+M )

15,838.04 Sq. KM

5,083.62 Sq. KM

53,500 Sq. KM 32578.34 Sq. KM

bearing.

Fields of Cambay BasinField Date of Signing contract Area(Sq Km) Field Size

Lohar-ONGC 8.29

Cambay-ONGC 161

Umra Ext. – II 34.43

Kosamba Ext. – I 39

Kim Ext. – I 56.11

Pakhajan Ext. – II 38.50

Olpad - Dandi Ext. – I 94.40

Gandhar Ext. – IX 40.91

Kural (Ml) 83.49

Gandhar Ext. – VIII 7.23

Gandhar Ext. - VII (G#155) 25.82

Dabka Ext. - V (D#38) 2

Nada Ext. – I 6.12

Gandhar Ext. - VI (G#388) 644.47

Kim (Ml) 18.33

Dabka Ext. - IV (D#6) 1

Olpad (A) 2.75

Kosamba 19.07

Kharach 0.70

Elav 10.37

Kudara 2.60

Sanaokhurd 23.29

Motwana 42.21

Ankleshwar (Main) 38.98

Ankleshwar Ext. – I 17.43

Kasiyabet 5.06

Pakhajan Ext. – I 18

Pakhajan (Ml) 6.25

Dahej 18.52

Dahej Ext. – I 90.90

Gandhar Ext. – V 29.43

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Gandhar Ext. – III 235.38

Gandhar Ext. - II (Denwa) 54.30

Gandhar 11.78

Gandhar Ext. – I 32.75

Gandhar Ext. – IV 36.75

Nada 9.85

Malpur (Ml) 1

Umera Ext. – I 9.93

Umera 8.44

Dabka Ext. – III 1.15

Dabka 21.67

Dabka Ext. – II 0.56

Dabka Ext. – I 12.85

Kathana Ext. – I 16.99

Anklav Ext. – I 61

Akholjuni 81.25

Padra Ext. – IX 21

Padra Ext. – VIII 15.68

Padra Ext. – VII 7.11

Padra Ext. – VI 83.95

Padra Ext. – V 3.58

Padra Ext. – IV 6.37

Padra Ext. – III 0.38

Padra 1.25

Padra Ext. – I 8.42

Padra Ext. – II 14.50

Kathana 16.95

Siswa 37.78

Nawagam South Ext. - III 53.71

Kadi Ext. – IV 5.28

Rupal 14.06

Nawagam South Ext. - II 43.94

Nawagam South Ext. - I 30.88

Kalol West Ml 14.53

Kalol West Ext. – I 54.25

Nawagam Ext. – III 56

South Wamaj ML 18.29

Gamij Ext. – II 116.22

Nadej Ext. – I 56.18

Gamij Ext. - III Ml 15.41

Ahemdabad Ext. – V 17.75

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Nawagam Ext. – II 14.66

Kadi Ext. – III 16.07

Asmali Ml 43.26

Raipur Ext. – I 8.70

Ahemdabad Ext. – IV 10.21

Wadu Ext. – I 55.17

Mawagam Ext. I 2077.77

Nawagam Main 72.23

Nadej 90.18

Nadej East 20.92

Ahmedabad Ext. –III 34.75

Ahmedabad Ext. –II 5.98

Ahmedabad Ext. –I 17.29

Ahmedabad – Bakrol 30.16

Hirapur 87.92

Gamij Ext. –I 81.22

Gamij 39.16

Sanand Ext. –III 19.30

Sanand Ext. –II 10.37

Sanand Ext. –I 18.51

Sanand 81.36

Viraj 17.49

Wamaj 19.44

Motera Ext. –I 23.64

Motera 15.86

Motera Ext. –II 26.02

Kalol Ext. –II 15.50

Kalol Ext. –I 159.82

Kalol Main 35.84

Halisa 143.44

Limbodra Ext. –I 14.96

Limbodra 15.75

Paliyad-Kalol-Limbodra 161.48

Kalol North East 9.44

Wadu 15.41

Rajpur 6.76

Jotana – Warosan 38.05

Kadi Asjol 0.72

Chandrora 1.39

Langhnaj ML 17.90

Sanganpur ML 6.97

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Langnaj – Wadasma 13.84

West Mewad (ML) 13.02

North Sobhasan Ext. -II 23

East Sobhasan 22.42

N. Sobhasan Pt. A+B 12.05

South Patan 6.99

Joksana (ML) 9.80

Jotana Ext. –II 0.87

Lanwa Ext. –I 2.15

Dedana (ML) 5.44

Chansama 2.81

Nandasan – Langnaj 61.90

Mansa 58.72

Nandasan Ext. –I 26.39

Linch 43.73

Linch Ext. –I 34.25

North Kadi 64.49

N. Kadi Ext. –I 20.42

Kadi Ext. –II 41.01

Bechraji Ext. –I 3.06

Bechraji 37.11

Santhal 19.46

Jotana 39.50

North Sobhasan Ext. –I 56.85

Linch Ext.- II 13.35

Geratpur 18.31

Sobhasan 35.89

Mehsana City Ext. –II 7.58

Mehsana City 8.85

West Sobhasan 9.60

Jotana Extn. – I 57.70

Balol 24

Lanwa 30

CB-OS/2 201.76 4

Cb-On/3 7.81 4

Cb-Onn-2000/2_Nsa/Bheema 24.25 4

CB-ONN-2000/1 01/01/1900 14.10 4

Palej-Pramoda(CB-ON/7) 01/01/1900 3.54 4

Bheema(CB-ONN-2002/2) 01/01/1900 4.03 3

NS-A(CB-ONN-2002/2) 01/01/1900 20.22 4

CB-X 01/01/1900 33.30 3

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Gauri(CB-OS/2) 01/01/1900 80.70 3

lakshmi(CB-OS/2) 01/01/1900 121.06 3

Modhera 23/02/2001 12.70 1

Ognaj 16/02/2004 13.65 1

Karjisan 16/02/2004 5 1

N.Balol 23/02/2001 27.30 1

Baola 05/04/1995 4 1

Lohar 13/03/1995 5 1

Bakrol 13/03/1995 36 1

Indrora 13/03/1995 130 1

Wavel 20/02/1995 9 1

Dholka 20/02/1995 48 1

Sabarmati 23/09/1994 6 1

Matar 01/01/1900 0 1

Cambay 23/09/1994 161 1

Bhandut 23/09/1994 6 1

Hazira 23/09/1994 50 1

Asjol 03/02/1995 15 1

Sanganpur 23/02/2001 4 1

Unawa 23/02/2001 6 1

Kanawara 23/02/2001 6.30 1

Allora 23/02/2001 6.85 1

North Kathana 23/02/2001 12.20 1

Dholasan 23/02/2001 8.80 1 Tectonic History

Type of Basin Intracratonic rift graben.

Different Tectonic Zones with in the Basin The Cambay rift valley is bounded by well demarcated basin margin step faults. Based on the cross trends the basin has been divided into five tectonic blocks. From north to south, the blocks are:

Sanchor – Tharad Mehsana – Ahmedabad Cambay – Tarapur Jambusar – Broach and Narmada Block.(FIG 4: Tectonic Map of the Basin)

2.5 Petroleum System

Source RockThick Cambay Shale has been the main hydrocarbon source rock in the Cambay Basin. In the

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northern part of the Ahmedabad-Mehsana Block, coal, which is well developed within the deltaic sequence in Kalol, Sobhasan and Mehsana fields, is also inferred to be an important hydrocarbon source rock. The total organic carbon and maturation studies suggest that shales of the Ankleshwar/Kalol formations also are organically rich, thermally mature and have generated oil and gas in commercial quantities. The same is true for the Tarapur Shale. Shales within the Miocene section in the Broach depression might have also acted as source rocks.

Reservoir RockThere are a number of the reservoirs within the trapwacke sequence of the Olpad Formation. These consist of sand size basalt fragments. Besides this, localized sandstone reservoirs within the Cambay Shale as in the Unawa, Linch, Mandhali, Mehsana, Sobhasan, fields, etc are also present.

Trap RockThe most significant factor that controlled the accumulation of hydrocarbons in the Olpad Formation is the favorable lithological change with structural support and short distance migration. The lithological heterogeneity gave rise to permeability barriers, which facilitated entrapment of hydrocarbons. The associated unconformity also helped in the development of secondary porosity.

Transgressive shales within deltaic sequences provided a good cap rock. (Fig 6: Generalized Tectono Stratigraphy Map Showing Source rock, Reservoir Rock, and Oil and Gas Occurrences.)

Timing of migration & Trap formation: The peak of oil generation and migration is understood to have taken place during Early to Middle Miocene.

Petroleum Plays

Structural Highs and fault closures & Stratigraphic traps (pinchouts / wedgeouts, lenticular sands, oolitic sands, weathered trap) in Paleocene to Miocene sequences have been proved as important plays of Cambay Basin.

Paleocene – Early Eocene Play :

Formations : Olpad Formation/ Lower Cambay Shale. Reservoir Rocks : Sand size basalt fragments & localized sandstone. Unconformities

within the Cambay Shale and between the Olpad Formation and the Cambay Shale have played a positive role in the generation of secondary porosities. The Olpad Formation is characterised by the development of piedmont deposits against fault scarps and fan delta complexes.

Middle Eocene Play:

Formations: Upper Tharad Formation Reservoir Rocks: In Southern part, Hazad delta sands of Mid to Late Eocene & in the

Northern part the deltaic sequence is made up of alternations of sandstone and shale associated with coal. Plays are also developed in many paleo-delta sequences of Middle Eocene both in northern and southern Cambay In the Northern Cambay Basin, two delta systems have been recognised.

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Late Eocene – Oligocene Play:

Formations : Trapur Shale, Dadhar Formation. Reservoir Rocks : This sequence is observed to possess good reservoir facies in the

entire Gulf of Cambay. North of the Mahi river, a thick deltaic sequence, developed during Oligo–Miocene, has prograded upto south Tapti area.

Miocene Play:

Formations: Deodar: Formation (LR. Miocene), Dhima Formation (Mid Miocene), Antrol Formation (UP. Miocene) The Mahi River delta sequence extends further westward to Cambay area where Miocene rocks are hydrocarbon bearing.

SST of Ankleshwar Asset has been divided into 6 groups:

Area

Drilling & Monitoring Group

Work Over Monitoring

Specialist Pool

Reservoir Data Acquisition Group (RDAG)

Figure 2.1: Hydrocarbon bearing fields of Ankleshwar Asset, South Cambay Basin

TOTAL WELLS DRILLED : 604

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OIL WELLS : 218

GAS WELLS : 58

INJ WELLS : 118

EFF. DISP. WELLS : 4

ABND : 86

To Be ABND : 3

OFF INJ : 4

OBS/FU : 113

3. INTRODUCTION TO DRILLNG

The Rotary Drilling method is comparatively new, having first been practiced by Leschot, a French civil engineer, in 1863. United States patents on rotary equipment were issued as early as 1866 but, as was the case with cable tools, the early application was for Water Well Drilling. It was not until approximately 1900 that two water well drilling contractors, M.C. and C.E. Baker, moved their rotary equipment from South Dakota to Corsicana, Texas where it found use in the soft rock drilling of that area. In Texas in 1901, Captain Lucas drilled the Spindle top discovery well with rotary tools. This spectacular discovery is credited with initiating both the Southwest’s oil industry and the widespread use of the rotary method. The inherent advantages of this method in the soft rock areas of Texas and California insured its acceptance, and it was in general use by the early 1920’s.

In this Method, the hole is drilled by a rotating bit to which a downward force is applied. The bit is fastened to, and rotated by, a drill string, composed of high quality drill pipe and drill collars, with new sections or joints being added as drilling progresses. The cuttings are lifted from the hole by the drilling fluid which is continuously circulated down the inside of the drill string through water courses or nozzles in the bit. And upward in the annular space between the drill pipe and bore hole. At the Surface, the returning fluid (Mud) is diverted through a series of tanks or pits which afford a sufficient quiescent period to allow cutting separation and any interesting treating. In the last of these pits the mud is picked up by the pump suction and repeats the cycle.

DRILLING RIG SPECIFICATION

ONSHORE

BY POWER USED:

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Mechanical — the rig uses torque converters, clutches, and transmissions powered by its own engines, often diesel

Electric — the major items of machinery are driven by electric motors, usually with power generated on-site using internal combustion engines

Hydraulic — the rig primarily uses hydraulic power Pneumatic — the rig is primarily powered by pressurized air Steam — the rig uses steam-powered engines and pumps (obsolete after middle of

20th Century)

BY PIPE USED:

Cable — a cable is used to raise and drop the drill bit Conventional — uses metal or plastic drill pipe of varying types Coil tubing — uses a giant coil of tube and a downhole drilling motor

BY POSITION OF DERRICK:

Conventional — derrick is vertical Slant — derrick is slanted at a 45 degree angle to facilitate horizontal drilling

Figure 3.1 Offshore

1, 2) conventional fixed platforms; 3) compliant tower; 4, 5) vertically moored tension leg and mini-tension leg platform; 6) Spar ; 7,8) Semi-submersibles ; 9) Floating production, storage, and offloading facility; 10) sub-sea completion and tie-back to host facility

BASIC DRILLING RIG AND COMPONENTS

Rotary drilling equipment is complex and any detailed discussion would of necessity involve

intricate mechanical design problems. The basic rig components in following order:

1-Derricks, masts, and substructures

2-Drawworks

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3-Mud pumps

4-Prime movers

5-Drill string

6-Bits

7-Drilling line

8-Miscellanious and auxiliary equipments

Figure 3.2: A complete Drilling site

1. Crown Block 2. Catline Boom and Hoist Line

3. Drilling Line 4. Monkeyboard

5. Traveling Block 6. Top Drive

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7. Mast 8. Drill Pipe

9. Doghouse 10. BOPs

11. Water Tank 12. Electric Cable Tray

13. Engine Generator Sets 14. Fuel Tank

15. Electrical Control House 16. Mud Pumps

17. Bulk Mud Component Tanks 18. Mud Tanks (Pits)

19. Waste Pit 20. Mud-Gas Separator

21. Shale Shakers 22. Choke Manifold

23. Pipe Ramp 24. Pipe Racks

HOISTING COMPONENTS:-the function of hoistig system is to provide a means of

lowering and raising drill stirings, casing strings and other surface equipment in to or out of

the hole. The principle components of the hoisting system are

1-the derrick and substructure 2- block and tackle ,3-drawworks.two routine drilling

operations performed with the hoisting system are called (1)- making a connection and (2)-

making a trip.

Derrick and portable mast:-the function of deriick is to provide vertical hight required to raise

sections of pipe from or lower them in to hole. Greater the hight , the longer the section of

pipe that can be handeled and thus, the faster a long string of pipe can be inserted and

removed from the hole.

Figure 3.3: Block and tackle system

BLOCK AND TACKLE:-

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The block and tackle comprised of (1) the crown block (2) Trevelling block and (3) Drilling

line .The principal function of block and tackle is to provide a Mechanical advantage.

DRAWWORKS:-

The drawworks provide the hoisting and braking power required to raise or lower the heavy

string of pipe.the principal parts of drawworks are (1) the drum (2) the brakes (3) the

transmission and (4) the catheads.

Figure 3.4: Drawworks

TREVELLING BLOCK:-

A trevlling block is the freely moving section of a block and tackle that contains a set of

pulleys or sheaves through which the drill line (wire rope) is threaded or reeved and is

opposite (and under) the crown block (the stationary section). The set of sheaves that move

up and down in the derrick.

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Figure 3.5 Travelling Block

CROWN BLOCK:- a crown block is the stationary section of block and tackle. The fixed set

of pulleys (called sheaves) located at the top of the derrick or mast, over which the drilling

line is threaded.

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Figure 3.6: Crown Block

HOOK: - The high-capacity J-shaped equipment used to hang various other equipment,

particularly the swivel and kelly, the elevator bails or topdrive units. The hook is attached to

the bottom of the traveling block and provides a way to pick up heavy loads with the

traveling block. The hook is either locked (the normal condition) or free to rotate, so that it

may be mated or decoupled with items positioned around the rig floor, not limited to a single

direction.

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Figure 3.6 Hook and Swivel

DRILLING LINE:-

In a drilling rig, the drill line is a multi-thread, twisted wire rope that is threaded

or reeved through the traveling block and crown blockto facilitate the lowering and lifting of

the drill string into and out of the wellbore.

Figure 3.7 Drilling Line

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ROTATING EQUIPMENT

ROTARY TABLE: - The revolving or spinning section of the drillfloor that provides power to turn the drillstring in a clockwise direction. The rotary motion and power are transmitted through the kelly bushing and the kelly to the drillstring. Almost all rigs today have a rotary table, either as primary or backup system for rotating the drillstring.

Topdrive technology, which allows continuous rotation of the drillstring, has replaced the rotary table in certain operations. A few rigs are being built today with topdrive systems only, and lack the traditional kelly system.

Figure 3.8 Rotary table

KELLY: - The Kelly is the first section of pipe below the swivel.the out side cross section of

the Kelly is square or hexagonal to permit to be gripped easily for turning. Torque is

transmitted to the Kelly through Kelly bushings, which fit inside the master bushing of rotary

table .the Kelly must be kept straight as possible. Rotation of a crooked Kelly causes a

whipping motion that results in unnecessary wear on crown block, drilling line, swivel and

threaded connections through out a large part of drill string.

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Figure 3.9: Kelly bushing

KELLY BUSHINGS: - An adapter that serves to connect the rotary table to the kelly. The kelly bushing has an inside diameter profile that matches that of the kelly, usually square or hexagonal. It is connected to the rotary table by four large steel pins that fit into mating holes in the rotary table. The rotary motion from the rotary table is transmitted to the bushing through the pins, and then to the kelly itself through the square or hexagonal flat surfaces between the kelly and the kelly bushing. The kelly then turns the entire drillstring because it is screwed into the top of the drillstring itself. Depth measurements are commonly referenced to the KB, such as 8327 ft KB, meaning 8327 feet below the kelly bushing.

Figure 3.10 Components

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TOP DRIVE: - A device that turns the drillstring. This is radically different from the more conventional rotary table and kelly method of turning the drillstring because it enables drilling to be done with three joint stands instead of single joints of pipe. It also enables the driller to quickly engage the pumps or the rotary while tripping pipe, which cannot be done easily with the kelly system. While not a panacea, modern topdrives are a major improvement to drilling rig technology and are a large contributor to the ability to drill more difficult extended-reach wellbores. In addition, the topdrive enables drillers to minimize both frequency and cost per incident of stuck pipe.

SWIVEL: - Swivel supports the weight of the drill string and permits rotation. the bail of the swivel is attached to the hook of the travelling block, and the gooseneck of the swivel provides a downword-pointing connection for the rotary hose. Swivels are rated according to their load capacities.

Figure 3.11 Swivel

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KELLY HOSE:- A Kelly hose (also known as a mud hose or rotary hose) is a flexible, steel reinforced, high pressure hose that connects the standpipe to the kelly (or more specifically to the goose-neck on the swivel above the kelly) and allows free vertical movement of the kelly while facilitating the flow of drilling fluid through the system and down the drill string.

Figure 3.12 Kelly hose

MUD CIRCULATING SYSTEM:-

A major function of the fluid circulating system is to remove the rock cuttings from the hole as drilling progresses. the principal components of the rig circulating system include (1) mud pumps (2) mud pits (3) mud-mixing equipments (4) contaminant-removal equipments.

MUD PUMPS: - A mud pump is a reciprocating piston/plunger device designed to circulate drilling fluid under high pressure (up to 7,500 psi (52,000 kPa)) down the drillstring and back up the annulus. Mud pumps come in a variety of sizes and configurations but for the typical petroleum drilling rig, the triplex (three piston/plunger) mud pump is the pump of choice. Duplex mud pumps (two piston/plungers) have generally been replaced by the triplex pump, but are still common in developing countries. Two later developments are the hex pump with six vertical pistons/plungers, and various quintuplex's with five horizontal piston/plungers. The advantages that these new pumps have over convention triplex pumps is a lower mud noise which assists with better MWD and LWD retrieval.

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Figure 2.13 Mud Pump

SHALE SHAKER:- Shale shakers typically consist of large, flat sheets of wire mesh screens or sieves of various mesh sizes that shake or vibrate the drill cuttings, commonly shale across and off of the screens as the drilling fluid (mud) flows through them and back into the drilling fluid system. This separates the solid drill cuttings from the fluid so that it can be recirculated back down the wellbore.

Figure 3.14 Shale shaker

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DESANDER: - A hydrocyclone device that removes large drill solids from the whole mud system. The desander should be located downstream of the shale shakers and degassers, but before the desilters or mud cleaners.Various size desander and desilter cones are functionally identical, with the size of the cone determining the size of particles the device removes from the mud system.

DESILTRER:

A hydrocyclone much like a desander except that its design incorporates a greater number of smaller cones. As with the desander, its purpose is to remove unwanted solids from the mud system. The smaller cones allow the desilter to efficiently remove smaller diameter drill solids than a desander does. For that reason, the desilter is located downstream from the desander in the surface mud system.

MUD PIT: - A large tank that holds drilling fluid on the rig or at a mud-mixing plant. For land rigs, most mud pits are rectangular steel construction, with partitions that hold about 200 barrels each. They are set in series for the active mud system. On most offshore rigs, pits are constructed into the drilling vessel and are larger, holding up to 1000 barrels. Circular pits are used at mixing plants and on some drilling rigs to improve mixing efficiency and reduce dead spots that allow settling. Earthen mud pits were the earliest type of mud pit, but environmental protection concernhas led to less frequent use of open pits in the ground. Today, earthen pits are used only to store used or waste mud and cuttings prior to disposal and remediation of the site of the pit.

DRILL PIPE AND BHA

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ROTARY DRILL BIT:- Rotary drilling bits usually are classified according to their design as ”Fixed cutter bits(Drag bits)” and ”Tri Conical Roller”.

Fixed Cutter Bits:

PDC(Polycrystalline Diamond Compact) bit:

A drilling tool that uses polycrystalline diamond compact (PDC) cutters to shear rock with a continuous scraping motion. These cutters are synthetic diamond disks about 1/8-in. thick and about

1/2 to 1 in. in diameter. PDC bits are effective at drilling shale formations, especially when used in combination with oil-base muds.

Figure 3.15: Tri Conical Roller Bits (TCR Bits):

A tool designed to crush rock efficiently while incurring a minimal amount of wear on the cutting surfaces. As the drillstring is rotated, the bit cones roll along the bottom of the hole in a circle. As they roll, new teeth come in contact with the bottom of the hole, crushing the rock immediately below and around the bit tooth. As the cone rolls, the tooth then lifts off the bottom of the hole and a high-velocity fluid jet strikes the crushed rock chips to remove them from the bottom of the hole and up the annulus.

MILLED TOOTH BITS [For Soft Formations] CARBON INSERT BITS [For Hard Formations]

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Figure 3.16 TCR bit

DRILL PIPE:

Drill pipe is a tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.

Figure 3.17: Drill pipe

BOTTOM HOLE ASSEMBLY (BHA):

The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collars, heavy-weight drillpipe, jarring devices ("jars") and crossovers for various threadforms. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drillingtools, logging-while-drilling tools and other specialized devices.

A simple BHA consisting of a bit, various crossovers, and drill collars may be relatively inexpensive (less than $100,000 US in 1999), while a complex one may cost ten or more times that amount.

SAFETY EQUIPMENT

BLOW OUT PREVENTERS: - A blowout is an uncontrolled flow of gas, oil, or water from a well. A blowout frequently sends debris flying through the air and catches the well on fire or

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both. And this kind of situation is very dangerous to anyone working on the well. Blowouts can occur before casing is set or long after drilling, when the well is being serviced or repaired.

Blowout preventers shut off a well white it is being drilled or serviced and allow the well to be closed in with or without pipe in the hole. A well with a beam pumping unit always has a blowout preventer that closes the space around the polished rod. Whenever crew members pull tubing, they install blowout preventers on the wellhead.

Figure 3.18: PIPE RAM BOP & ANNULAR TYPE BOP

BOPs come in two basic types, RAM and ANNULAR. Both are often used together in drilling rig.

RAM TYPE BOP is similar in operation to a gate valve, but uses a pair of opposing steel plungers, rams. The rams extend toward the centre of the wellbore to restrict flow or retract open in order to permit flow. The inner and top faces of the rams are fitted with packers (elastomeric seals) that press against each other, against the wellbore, and around tubing running through the wellbore. Outlets at the sides of the BOP housing (body) are used for connection to choke and kill lines or valves.

Rams, or ram blocks, are of four common types:

Pipe Ram Blind Ram Shear ram Blind shear Ram

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Pipe Rams close around a drill pipe, restricting flow in the annulus (ring-shaped space between concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe. Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity.

Blind Rams (also known as sealing rams), which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.

Shear Rams cut through the drill string or casing with hardened steel shears.

Blind Shear Rams (also known as shear seal rams, or sealing shear rams) are intended to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well. The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the BOP.

In addition to the standard ram functions, Variable-Bore Pipe Rams are frequently used as test rams in a modified blowout preventer device known as a stack test valve. Stack test valves are positioned at the bottom of a BOP stack and resist downward pressure (unlike BOPs, which resist upward pressures). By closing the test ram and a BOP ram about the drill string and pressurizing the annulus, the BOP is pressure-tested for proper function.

Shear-Type Ram BOPs require the greatest closing force in order to cut through tubing occupying the wellbore. Boosters (auxiliary hydraulic actuators) are frequently mounted to the outer ends of a BOP’s hydraulic actuators to provide additional shearing force for shear rams.

Technological development of ram BOPs has been directed towards deeper and higher pressure wells, greater reliability, reduced maintenance, facilitated replacement of components, facilitated ROV intervention, reduced hydraulic fluid consumption, and improved connectors, packers, seals, locks and ram.

DERRICK:

The structure used to support the crown blocks and the drillstring of a drilling rig. Derricks are usually pyramidal in shape, and offer a good strength-to-weight ratio. If the derrick design does not allow it to be moved easily in one piece, special ironworkers must assemble them piece by piece, and in some cases disassemble them if they are to be moved.

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Figure 3.19: Derrick

DRILL PIPE, DRILL COLLAR AND CASING SLIPS:

A device used to grip the drillstring in a relatively nondamaging manner and suspend it in the rotary table. This device consists of three or more steel wedges that are hinged together, forming a near circle around the drillpipe. On the drillpipe side (inside surface), the slips are fitted with replaceable, hardened tool steel teeth that embed slightly into the side of the pipe. The outsides of the slips are tapered to match the taper of the rotary table.

Figure 3.20: Casing and pipe slips

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TONG:

The large wrenches used for turning when making up or breaking out drill pipe, casing,

tubing, or other pipe; variously called casing tongs, rotary tongs, and so forth according to the

specific use. Power tongs are pneumatically or hydraulically operated tools that spin the pipe

up and, in some instances, apply the final makeup torque.

Figure 3.21: Tong

CHEMISTRY

ROLL OF CHEMISTRY IN DRILLING: - (1) Drilling (2) Laboratory

DRILLING:-

(1) Drilling fluid ( mud)

(2) Classification of Drilling fluid

(3) Drilling fluid preparation

(4) Functions of drilling fluid

(5) Parameters of drilling fluid

(6) Drilling fluid used in Sub Asset Cambay

Definition of drilling fluid

API DEFINITION:

“A Circulating Fluid Used In Rotary Drilling To Perform Any Or All Of The Various Functions Required In A Drilling Operation.”

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Preparation of drilling fluid:7.5% Bentonite suspension - 7.5% Bentonite powder in basic water for 6-8 hrs while keeping the agitators off.

Functions of Drilling Fluid: Transport drilled cuttings to the surface and hole cleaning Viscosity Density Annular viscosity Cutting size and shape Drill string rotation etc Control subsurface pressure Help suspend the weight of the drill string and casing Help suspend the weight of the drill string and casing Deliver hydraulic energy upon the formation beneath bit Provide suitable medium for wire line logs Seal permeable formation Improves wellbore stability and prevents a number of drilling and production

problems. Control corrosion.

Direct Indicating Viscometer:

Apparent Viscosity:

The apparent viscosity in centipoises equals the 600 rpm reading divided by 2

[A.V. = 600/2 IN CENTIPOISE]

Plastic Viscosity:

Friction force between two particles known as plastic viscosity Reading At 600 Rpm – Reading At 300 Rpm

[P.V. = 600 – 300 IN CENTIPOISE]

Yield Point:

300 Rpm Reading – Plastic Viscosity

[Y.P. = 300 – PV in Lb/100 Sq.Ft.]

Plastic Viscosity (PV):

Drilling Muds are usually composed of a continuous fluid phase in which solids are dispersed. Plastic viscosity is that part of the resistance to flow caused by mechanical friction. The friction is caused by:

Solids concentration, Size and shape of solids, Viscosity of the fluid phase.

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Yield Point (YP):

The yield point is the initial resistance to flow caused by electrochemical forces between the particles. This electrochemical force is due to charges on the surface of the particles dispersedin the fluid phase. Yield point is a measure of these forces under flow conditions and is dependent upon:

The surface properties of the mud solids, The volume concentration of the solids and Ionic environment of the liquid surrounding the solids.

Thixotropy can be estimated by observing the change in strength taking place in a gel as a function of time.

GEL10 /GEL0 should not be more than 2.

Excessive gel strengths can cause:

Swabbing, when pipe is pulled, Surging, when pipe is lowered, Difficulty in getting logging tools to bottom, Retaining of entrapped air or gas in the mud, and Retaining of sand and cuttings while drilling.

Gel strengths and yield point are both a measure of the attractive forces in a mud system. A decrease in one usually results in a decrease in the other; therefore, similar chemical treatments are used to modify them both.

Classification of Drilling Fluid

Water Based - for higher reservoir pressures and non-hydratable shales

Oil Based - to drill hydratable shales

Gas Based - for depleting reservoir pressures and chemical precipitation.

Water Based MudCL-CLS System

Weighing agent- Barite

Viscosifier - CMC, XC polymer, Bentonite, HEC

Thinner- CLS, Water.

Shale stabilizer- Sulphonated Asphalt

Alkali- NaoH

Lost Circulation Material- Mica flakes.CaCO3

Ca and cement contamination- Soda Ash

Water Treatment

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The following chemicals are used to treat the separated water:

Alum-Flocculating agent Sodium Sulphite-Oxygen scavenger Bactericide aldehyde Bactericide amine HEDP-Descaling agent

SAFETY ASPECTS IN DRILLING RIG:-

Dos & Don’ts in Drilling Rig:

-Use proper handling tools. Tools should be in good working condition.-Wear proper Personal Protective Equipment (PPE) & safety kits while working.

- Keep the derrick area clean. Safety line of crown block should invariably be fitted & be in working condition. Always provide complete B.O.P assembly. Always check drill-o-meter before starting operation for to be in working condition. Provide guards on all moving/ rotating parts of equipments. Do ensure the use of flame proof light on the derrick of the rig. Test B.O.P before starting the operation. Casing line, brakes, hydraulic & pneumatic system should be in good working

condition. Keep the working place clean and free of oil/mud/water etc. Anchor flow lines properly. Provide railings on derrick & engine floor. Fit all guy ropes properly with U-clamps as per specification of rope size used. Provide all ladders with side railings. Always provide pressure gauge at Mud Pump discharge line, B.O.P Accumulator, compressor tank, and hydraulic system of the rig. Always keep B.O.P control unit at a safer distance readily accessible. Do organize mock drill at least once in a month & operate fire fighting equipment

during the drill. Do ensure that all the engines at well site should have spark arrester in their exhaust

pipe. Do keep first aid medicines and stretches at well site and all the crew members are

trained in first aid. Use waste bins for waste disposal

4 PRODUCTION OPERATIONS

4.1 Introduction to oil production

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Oil has been used for lighting purposes for many thousand years. In areas where Oil is found in shallow reservoirs, seeps of Crude Oil or Gas may naturally develop, and some Oil could simply be collected from seepage or tar ponds. Historically, we know of tales of eternal fires where Oil and Gas seeps would ignite and burn. One example1000 B.C. is the site where the famous oracle of Delphi would be built, and 500 B.C .Chinese were using natural gas to boil water. But it was not until 1859 that "Colonel" Edwin Drake drilled the first successful Oil well, for the sole purpose of finding Oil. The Drake Well was located in the middle of quiet farm country in north-western Pennsylvania, and began the international search for and industrial use of Petroleum.These wells were shallow by modern standards, often less than 50 meters, but could give quite large production. In the picture from the Tarr Farm, Oil Creek Valley, the Phillips well on the right was flowing initially at 4000 barrels per day in October1861, and the Woodford well came in at 1500 barrels per day in July,1862. The Oil was collected in the wooden tank in the foreground. Note the many different sized barrels in the background. At this time, barrel size was not yet standardized, which made terms like "Oil is selling at $5 per barrel" very confusing (today a barrel is 159 liters. But even in those days, overproduction was an issue to be avoided. When the “Empire well” was completed in September 1861, it gave 3,000 barrels per day, flooding the market, and the price of oil plummeted to 10 cents a barrel. Soon, oil had replaced most other fuels for mobile use. The automobile industry developed at the end of the 19th century, and quickly adopted the fuel. Gasoline engines were essential for designing successful aircraft. Ships driven by oil could move up to twice as fast as their coal fired counterparts, a vital military advantage.Gas was burned off or left in the ground. Despite attempts at gas transportation as far back as 1821, it was not until after the World War II that welding techniques, pipe rolling, and metallurgical advances allowed for the construction of reliable long distance pipelines, resulting in a natural gas industry boom. At the same time the petrochemical industry with its new plastic materials quickly increased production. Even now gas production is gaining market share as LNG provides an economical way of transporting the gas from even to remotest sites.With Oil prices of 50 dollars per barrel or more, even more difficult to access sources become economically interesting. Such sources include tar sands in Venezuela and Canada as well as oil shale’s. Synthetic diesel (syndiesel) from natural gas and biological sources (biodiesel, ethanol) has also become commercially viable. These sources may eventually more than triple the potential reserves of hydrocarbon fuels.

4.2. Process Overview

The following figure gives a simplified overview of the typical Oil and Gas

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Production process

Fig 4.1 Facilities

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Figure 4.2 Offshore Platforms

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4.3 ONSHORE

Onshore production is economically viable from a few tens of barrels a day upwards. Oil and Gas is produced from several million wells world-wide. In particular, a Gas Gathering network can become very large, with production from hundreds of wells, several hundred kilometers/miles apart, feeding through a gathering network into a Processing Plant.

The picture shows a well equipped with a sucker rod pump (donkey pump) often associated with Onshore Oil production (Ankleshwar Asset has several wells). However, as we shall see later, there are many other ways of extracting oil from an on-free flowing well For the smallest reservoirs, oil is simply collected in a holding tank and collected at regular intervals by tanker truck or railcar to be processed at a refinery. But Onshore Wells in Oil rich areas are also high capacity wells with thousands of barrels per day, connected to a 1.000.000 barrel a day

Figure 4.3 Sucker Rod Pump

gas oil separation plant(GOSP) ONGC Mumbai high is one such location. Product is sent from the plant by pipeline or tankers to BPCL, HPCL, IOC Refineries in India.

4.4 Offshore

Offshore, depending on size and water depth, a whole range of different structures are used. In the last few years, we have seen pure sea bottom installations with multiphase piping to shore and no offshore topside structure at all. Replacing outlying wellhead towers, deviation drilling is used to reach different parts of the reservoir from a few wellhead cluster locations. All such Installations are available in Offshore Mumbai High, Krishna Godavari Basins.

Gravity Base: Enormous concrete fixed structures placed on the bottom, typically with oil storage cells in the “skirt” that rests on the sea bottom. The large deck receives all parts of the

Figure 4.4 Concrete fixed structure

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process and utilities in large modules. Typical for 80s and 90s large fields in 100 to 500 water depth. The concrete was poured at an at shore location, with enough air in the storage cells to keep the structure floating until two out and lowering on to the seabed. The picture shows the world’s largest GBS platform, the Troll A during construction.

Compliant towers are much like fixed platforms. They consist of a narrow tower, attached to a foundation on the seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively rigid legs of a fixed platform. This flexibility allows it to operate in much deeper water, as it can 'absorb' much of the pressure exerted on it by the wind and sea. Compliant towers are used between 500 and 1000 meters water depth.

Floating production, where all top side systems are located on a floating structure with dry or subsea wells. Some floaters are:

FPSO: Floating Production, Storage and Offloading. Typically a tanker type hull or barge with wellheads on a turret that the ship can rotate freely around (to point into wind, waves or current). The turret has wire rope and chain connections to several anchors (position mooring - POSMOR), or it can be dynamically positioned using thrusters (dynamic positioning – DYNPOS). Water depths 200 to 2000 meters. Common with subsea wells. The main process is placed on the deck, while the hullis used for storage and offloading to a shuttle tanker. May also be used with pipeline transport.

Figure 4.5 FPSO

SPAR: The SPAR consists of a single tall floating cylinder hull, supporting a fixed deck. The cylinder however does not extend all the way to the seafloor, but instead is tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the platform in the water, and allows for movement to absorb the force of potentiall hurricanes. Spars can be quite large and are used for water depths from 300 and up to 3000 meters. SPAR is not an acronym, but refers to its likeness with a ship’s spar. Spars can support dry completion wells, but is more often used with subsea wells.

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Figure 4.6 SPAR

Subsea production systems EA, EB, EC, &ED in Mumbai High are wells located on the sea floor, as opposed to at the surface. Like in a floating production system, the petroleum is extracted at the seafloor, and then can be 'tied-back' to an already existing production platform or even an onshore facility, limited by horizontal distance or “offset”. The well is drilled by a moveable rig and the extracted oil and natural gas is transported by undersea pipeline and riser to a processing facility. This allows one strategically placed production platform to service many wells over a reasonably large area. Subsea systems are typically in use at depths of 7,000 feet or more, and do not have the ability to drill, only to extract and transport. Drilling and completion is performed from a surface rig. Horizontal offsets up to 250 kilometers, 150 miles are currently possible.

Figure 4.7 Main Process Sections

4.5 Wellheads

The wellhead sits on top of the actual Oil or Gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production. Once a natural gas or oil well is drilled, and it has been verified that commercially viable quantities of natural gas are present for extraction, the well must be 'completed' to allow for the flow of petroleum or natural gas out of the formation and up to the surface. This process

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includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of natural gas out of the well. The well flow is controlled with a choke. We differentiate between dry completion with is either onshore or on the deck of an offshore structure, and Subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well work over. Well work over refers to various technologies for maintaining the well and improving its production capacity.

Figure 4.8 Manifolds/Gathering

Onshore, the individual well streams are brought into the main production facilities over a network of gathering pipelines and manifold systems. The purpose of these is to allow set up of production “well sets” so that for a given production level, the best reservoir utilization, well flow composition (Gas, Oil, water) etc. can be selected from the available wells. For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown on the illustration. For multiphase (combination of gas, oil and water) flows, the high cost of multiphase flow meters often lead to the use of software flow rate estimators that use well test data to calculate the actual flow. Offshore, the dry completion wells on the main field centre feed directly into production manifolds, while outlying wellhead towers and subsea installations feed via multiphase pipelines back to the production risers. Risers are the system that allows a pipeline to “rise” up to the topside structure. For floating or structures, this involves a way to take up weight and movement. For heavy crude and in arctic areas, diluents and heating may be needed to reduce viscosity and allow flow.

Figure 4.9 Separation

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Some wells have pure gas production which can be taken directly to gas treatment and/or compression. More often, the well gives a combination of Gas, Oil and Water and various contaminants which must be separated and processed. The production separators come in many forms and designs, with the classical variant being the gravity separator. In gravity separation the well flow is fed into a horizontal vessel. The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instabilities and safety hazards.

Figure 4.10 Separator

4.6 Gas compression

Gas from a pure natural gas wellhead might have sufficient pressure to feed directly into a pipeline transport system. Gas from separators has generally lost so much pressure that it must be recompressed to be transported. Turbine compressors gain their energy by using up a small proportion of the natural gas that they compress. The turbine itself serves to operate a centrifugal compressor, which contains a type of fan that compresses and pumps the natural gas through the pipeline. Some compressor stations are operated by using an electric motor to turn the same type of centrifugal compressor. This type of compression does not require the use of any of the natural gas from the pipe; however it does require a reliable source of electricity nearby. The compression includes a large section of associated equipment such as scrubbers (removing liquid droplets) and heat exchangers, lube oil treatment etc. Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds. Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural gas, to produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines usually impose restrictions on the make-up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified. Associated hydrocarbons, known as 'natural gas liquids' (NGL) are used as raw materials for oil refineries or petrochemical plants, and as sources of energy.

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Figure 4.11 Metering, Storage and Export

Most plants do not allow local gas storage, but Oil is often stored before loading on a vessel, such as a shuttle tanker taking the oil to a larger tanker terminal, or direct to crude carrier. Offshore production facilities connection generally relies on crude storage in the base or hull, to allow a shuttle tanker to offload about once a week. A larger production complex generally has an associated tank farm terminal allowing the storage of different grades of crude to take up changes in demand, delays in transport etc.

Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These metering stations employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement. This metered volume represents a transfer of ownership from a producer to a customer (or another division within the company) and is therefore called Custody Transfer Metering. It forms the basis for invoicing sold product and also for production taxes and revenue sharing between partners and accuracy requirements are often set by governmental authorities.

Typically the metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals. Pipelines can measure anywhere from 6 to 48 inches in diameter. In order to ensure the efficient and safe operation of the pipelines, operators routinely inspect their pipelines for corrosion and defects. This is done through the use of sophisticated pieces of equipment known as pigs. Pigs are intelligent robotic devices that are propelled down pipelines to evaluate the interior of the pipe.

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Figure 4.12 GGS

Pigs can test pipe thickness, and roundness, check for signs of corrosion, detect minute leaks, and any other defect along the interior of the pipeline that may either impede the flow of gas, or pose a potential safety risk for the operation of the pipeline. Sending a pig down a pipeline is fittingly known as 'pigging' the pipeline. The export facility must contain equipment to safely insert and retrieve pigs form the pipeline as well as depressurization, referred to as pig launchers and pig receivers loading on tankers involve loading systems, ranging from tanker jetties to sophisticated single point mooring and loading systems that allow the tanker to dock and load product even in bad weather.

The well

Figure 4.13 Oil well

Oil Produced to Surface

Surface Casing

Cement

Produced Casing

Tubing

Packer

Oil Enters Through

PerforationPerforation

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When the well has been drilled, it must be completed. Completing a well consists of a number of steps; installing the well casing, completing the well, installing the wellhead, and installing lifting equipment or treating the formation should that be required.

3.5Wellhead

Wellheads can be Dry or Subsea completion. Dry Completion means that the well is onshore on the topside structure on an offshore installation. Subsea wellheads are located under water on a special sea bed template.

The wellhead consists of the pieces of equipment mounted at the opening of the well to regulate and monitor the extraction of hydrocarbons from the underground formation. It also prevents leaking of oil or natural gas out of the well, and prevents blowouts due to high pressure formations.

Formations that are under high pressure typically require wellheads that can withstand a great deal of upward pressure from the escaping gases and liquids. These wellheads must be able to withstand pressures of up to 140 MPa (1400 Bar). The wellhead consists of three components: the casing head, the tubing head, and the 'Christmas tree'.

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A typical Christmas tree composed of a master gate valve, a pressure gauge, a wing valve, a swab valve and a choke is shown here. The Christmas tree may also have a number of check valves. The functions of these devices are explained in the following paragraphs. Ill: Vetco international At the bottom we find the Casing Head and casing Hangers. The casing will be screwed, bolted or welded to the hanger. Several valves and plugs will normally be fitted to give access to the casing. This will permit the casing to be opened, closed, bled down, and, in some cases, allow the flowing well to be produced through the casing as well as the tubing. The valve can be used to determine leaks in casing, tubing or the packer, and will also be used for lift gas injection into the casing.

The tubing hanger: (also called donut) is used to position the tubing correctly in the well. Sealing also allows Christmas tree removal with pressure in the casing.

Master gate valve: The master gate valve is a high quality valve. It will provide full opening, which means that it opens to the same inside diameter as the tubing so that specialized tools may be run through it. It must be capable of holding the full pressure of the well safely for all anticipated purposes. This valve is usually left fully open and is not used to control flow. The pressure gauge: The minimum instrumentation is a pressure gauge placed above the master gate valve before the wing valve. In addition other instruments such as temperature will normally be fitted.

The wing valve: The wing valve can be a gate valve, or ball valve. When shutting in the well, the wing gate or valve is normally used so that the tubing pressure can be easily read.

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The swab valve: The swab valve is used to gain access to the well for wire line operations, intervention and other work over procedures (see below), on top of it is a tree adapter and cap that will mate with various equipment.

The variable flow choke valve: The variable flow choke valve is typically a large needle valve. Its calibrated opening is adjustable in 1/64 inch increments (called beans). High-quality steel is used in order to withstand the high-speed flow of abrasive materials that pass through the choke, usually for many years, with little damage except to the dart or seat. If a variable choke is not required, a less expensive positive choke is normally installed on smaller wells. This has a built in restriction that limits flow when the wing valve is fully open.

This is a vertical tree. Christmas trees can also be horizontal, where the master, wing and choke is on a horizontal axis. This reduces the height and may allow easier intervention. Horizontal trees are especially used on subsea well.

3.5.1Subsea wells

4.Production Separator

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6 SITE VISITED

DTYS, F 6100 Rig, E 760-17 Rig, Workover Operation (ANK # 334)

E- 760- 17

Rig name: E 760-17 BHEL drilling rig at Gandhar field drilling a Directional well of TD 3200mtrs

Well name:- GNDDH Field:- Gandhar Location:- Gandhar Kick off was at 250mtrs. L – Profile drilling. Type of well : Development well Current onsite drilling depth : 2605m Type of BOP:- 13 ⅝" annular and double RAM Mud used: - CLCLS (Chrome lignite – Chrome ligno-sulphate) . Two triplex pumps were used for mud pumping

H/SIZE Interval(m) Csg. Size Csg. Plan23” 0-150 18 5/8” J-55, 87.5 ppf, BTC

17 ½” 0-1400 13 3/8” N-80, 68 ppf, BTC12 ¼” 0-3206 12 ¼” N-80. 47 ppf, BTC8 ½” 0-3236.3 7” L-80, 29 ppf, BTC

F-6100

Rig name:- F 6100 Well name:- GNWW (AIG 15) Field:- Gandhar Location: - Gandhar. Dist. Bharuch Kick off was at 250mtrs.

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S – Profile drilling. Type of well : Development well Current onsite drilling depth : 3025m Type of BOP:- 18 ⅝" annular and double RAM Mud used: - CLCLS (Chrome lignite – Chrome ligno-sulphate) . Two triplex pumps were used for mud pumping

H/SIZE Interval(m) Csg. Size Csg. Plan17 ½” 0-200 13 3/8” J-55, 68 ppf, BTC12 ¼” 0-1800 9 5/8” N-80, 43.5 ppf, BTC8 ½” 0-3178 7” L-80, 27 ppf, BTC

7 CASE STUDY

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DRILL STRING DESIGN

H/Size Interval(m) D/Collar Weight in Air(tons) D/Pipe

17 ½” 0-150 8”x 3”=28M (6 T), (6+7.5)T 5”HWDP+Rest 5” D/P ,E-GD6 ½” x 2 13/16”= 56M (7.5

T)12 ¼” 150-800 8”x 3”=28M (6 T), (6 + 15)T 5”HWDP+Rest

5” D/P ,E-GD6 ½ x 2 13/16”= 112M (15 T)

8 ½” 800-2000 6 ½” x 2 13/16”= 168M(22.5T)

22.5 T 5”HWDP+Rest 5” D/P ,E-GD

Grade Yield strength, (psi)

J 55000

N 80000

N 80000

X 95000

DRILL STRING

SECTION 1

Depth 150m

Hole size 17 1/2”

Mud Weight 1.06gm/cc = 8.85 ppg

Buoyancy Factor = 1 - (8.85/65.5) = 0.865

Safety Factor Tension 1.8

Collapse 1.125

Drill Collar 1 stand 8” × 3” 28m

2 stands 6 ½ x 2 13/16” 56m

2 stands 5”HWDP 56m

Max WOB 8 tonne

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Well to be drilled Cos α = 1(vertical)

Total length of D/C assembly

Wt of D/C in air = WOB/ ( SF x BF x Cos α )

= 8 / (0.8 x 0.865 x 1 ) = 11.56 tonnes

Nominal Weight

Wt of 8” × 3” D/C = 6 Tonnes

Wt of 6 ½ x 2 13/16” D/C = 7.5 Tonnes

Wt of 5”HWDP = 56 x 73.5 Kg

= 4116 Kg

= 4.12 Tonnes

Total Wt of D/C assembly + HWDP = 17.62 Tonnes

Length of Drill Pipe above Drill collar Assembly

Drill Pipe 5” D/P J -55 Grade

19.5 ppf

Length oF D/P = 10 m

L D/P = ( Pt X 0.9 /SF x BF x WD/P ) - (WcLC / WD/P )

= ( 141.8 x 1000 x0.9 / 1.8 x 31.2 x0.865) - ( 17.62 x 1000/ 31.2 )

= 2062.35m

True Ldp = 10 m (feasible)

Margin Of Over Pull

MOP = Pa - P

P = B(WcLD/c + WD/PLD/P/ 1000 )

= 0.865 ( 17.62 + 31.52 x 10/1000 )

= 15.514 Tonnes

Pa = Pt x 0.9 = 141.8 x 0.9 = 127.62 Tonnes

MOP = 127.62 – 15.514

= 112.11 Tonnes

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DRILL STRING

SECTION 2

Depth 800m

Hole size 12 1/4”


Buoyancy Factor = 1 - (10.02/65.5) = 0.847


Collapse 1.125

Drill Collar 1 stand 8” × 3” 28m

4 stands 6 ½ x 2 13/16” 112m


Max WOB =10 tonne


Total length of D/C assembly

SF = 0.8 (this ensures that only 80% of weight of D/C is used on WOB

BF = 0.853

Cos α = 1

WOB = 10 tonnes

Wt of D/C in Air = 10 / (0.8 x 0.865 x 1 ) = 14.768 tonnes

Nominal Weight

Wt of 8” × 3” D/C = 6 Tonnes

Wt of 6 ½ x 2 13/16” D/C = 15 Tonnes

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= 4122 Kg

= 4.12 Tonnes

Total wt of D/C assembly + HWDP = 21 + 4.12 tonnes

= 25.12 tonnes


Drill Pipe 5” D/P N -80 Grade

19.5 ppf


Adjusted wt =31.2 kg/m

Tensile strength =141.8 tonnes

S.F =1.8


= ( 141.8 x 1000 x0.9 / 1.8 x 31.2 x0.847) - ( 25.12 x 1000/ 31.2 )

= 1877.8 m


Margin Of Over Pull

MOP = Pa - P


= 0.847 ( 25.12 + 31.52 x 604/1000 )

= 37.24 Tonnes

Pa = Pt x 0.9 = 141.8 x 0.9 = 127.62 Tonnes

MOP = 127.62 – 37.24

= 90.38 Tonnes

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DRILL STRING

SECTION-III

Depth 2000m

Hole size 8 ½”


Buoyancy Factor = 1 - (10.44/65.5) = 0.841


Collapse 1.125

Drill Collar 1 stand 8” × 3” 28 m

6 stands 6 ½” x 2 13/16” 168m


Max WOB =14 tonne


Total length of Drill collar assembly

SF = 0.8 (this ensures that only 80% of weight of D/C is used on WOB

BF = 0.841

Cos α = 1

WOB = 14 tonnes

Wt of D/C in Air = 14 / (0.8 x 0.841 x 1 ) = 20.81 tonnes

Nominal Weight

Wt of 6 ½ x 2 13/16” D/C = 22.5 Tonnes


= 4122 Kg

= 4.12 Tonnes

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Total wt of D/C assembly + HWDP = 22.5 + 4.12 tonnes

= 26.62 tonnes


Drill Pipe 5” D/P N -80 Grade

19.5 ppf


Adjusted wt =31.2 kg/m

Tensile strength =141.8 tonnes

S.F =1.8


= ( 141.8 x 1000 x0.9 / 1.8 x 31.2 x0.841) - ( 26.62 x 1000/ 31.2 )

= 1848.85m


Margin Of Over Pull

MOP = Pa - P


= 0.841 ( 26.62 + 31.52 x 1748/1000 )

= 68.25 Tonnes

Pa = Pt x 0.9 = 141.8 x 0.9 = 127.62 Tonnes

MOP = 127.62 – 68.25

=59.36 Tonnes

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Hydraulics Design

Section I

A) Hole size =17 ½”

Sp. Gr =1.06

Depth interval from 0 to 150m

Drill collar,

8” x 3” =28 m

6 1/2” x 2 13/16 =56m

5” HWDP =56m

D.P 5” =10m

Pump available, Oil well Triplex A-850 PT x 2 Nos.

B) Operating pressure limit = 160 kg/cm2

C) Surface equipment =Type 3

Step I: Annulus velocities 60-100 ft/min, 18-30 m/min

Circulation rate (5” DP) = 4340 lit/min.

Step II: liner size selected = 7” = 177mm

No. Of pumps =2 Nos

Operating pressure = 160 kg/cm2

Step III: SPM = ((circulation rate lit/min)/(No. Of pumps x lit/stroke))

= 4340/(2 x 36.7) = 59.13 spm.

Step IV: From Table- D4

St pipe - 45 ft

ID - 4”

Hose - 55 ft

ID - 3”

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Swivel - 5 ft

ID - 2 1/4”

Kelly - 40 ft

OD - 3 ¼”

Step V: Assume Pressure losses through surface equipment = 10.2 kg/cm2

Step VI: Pressure loss = (pressure loss from table D-6)/1000 x length of D.P

Assuming loss through drill pipe bore = 39.3 kg/cm2/1000

Pressure loss = (39.3/ 1000) x 10

= 0.393 kg/cm2

Step VII: Assuming for 17 ½” hole size 5” drill pipe, Pressure loss through D/P

Annulus = 0.2 Kg/cm2/1000m.

Pressure Loss = (0.2/1000) x 10 Kg/cm2 = 0.002 Kg/cm2

Step VIII: (i) Drill collar 8” x 3” = 28m

Assume Pressure loss through Drill collar bore3’’ = (23.5/100) x 28 Kg/cm2

= 6.58 Kg/cm2

(ii) Drill Collar 6 ½” x 2 13/16” = 56 m

Assuming pressure through D/C bore (2 13/16)” = 32.1 kg/ cm2

Pressure losing (32.1/100)x 56 = 17.64 kg/cm2

(iii)HWDP 5” = 56 m

Pressure loss = (39.3/1000) x 56 kg/cm2 = 2.2008 kg/cm2

Total pressure loss through D/C = (6.58+17.64+2.2008) = 26.4208 kg/cm2

Step IX: Circulation rate, hole size and drill collar size,

Pressure loss = (pressure loss from table D-9)/100) x length of collar

Hole Size 17 ½”, D/C size

8” x 3” = 28 m, 0.23 kg/cm2/100

6 ½” x 2 13/16= 56 m, 0.23 kg/cm2/100

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For 8” x 3” casing (0.23/100) x 28 = 0.0644 kg/cm2

For 6 ½” x 2 13/16 (0.23/100) x 56 = 0.1288 kg/cm2

Annulus loss,

HWDP-> 5”

P.D = (0.2/1000) x 56 =0.0112 kg/cm2

Total Pr. Loss around collar annulus = 0.205 kg/cm2

Step X: Adding steps 5, 6, 7, 8, 9

Sp.gr = 1.06

System Pressure Loss x (1.06/1.2) = Actual Pressure loss

Applied pr. Loss = 37.2208 x (1.06/1.2)

APL = 32.8784 kg/cm2

Step XI: Pressure available for nozzle selection = (160- 32.8784) x (1.2/1.06)

= 143.91 kg/cm2

Step XII: Nozzle size - 20-20-20

Pressure loss - 100.9 kg/cm2

Mud wt = 1.06 gm/cc

Actual Pr loss through nozzles

= 100.9 x (1.06/1.2)

= 89.13 kg/cm2

Step XIII: Stand pipe Pr = 100.9 +89.13

= 190.03kg/cm2

Step XIV: %age BHP = (100.9 x 100)/ 190.03 =53.1 %

Step XV: Jet velocity = (1.55 x circulation rate) / Area of Nozzles

= (1.55 x 4340) / (0.9204 x 60)

= 121.81 kg/cm2

Step XVI: Calculate BHHP/ sq inch hole size

BHHP/ Sq. Inch hole size = ((Actual Pr loss through bit) x (Circulation rate))/

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(5.97 x (hole Dia. inch) 2)

= (100.9 x 4340/60)/ (5.97 x (17.5)2) = 3.992

Section 2

A) Hole size =12 ¼”

Sp. Gr =1.20


Drill collar,

8” x 3” =28 m

6 1/2” x 2 13/16 =112 m

5” HWDP =56 m

D.P 5” =604 m


B) Operating pressure limit = 70 x 2 = 140 kg/cm2




Step II: liner size selected = 6 ½” = 165mm

No. Of pumps =2 Nos


Step III: SPM = ((circulation rate lit/min)/(No. Of pumps x lit/stroke))

= 4777/ (2 x 32.2) = 74.18 spm.


St pipe - 45 ft

ID - 4”

Hose - 55 ft

ID - 3”

Swivel - 5 ft

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ID - 2 1/4”

Kelly - 40 ft

ID - 3 ¼”


Step VI: Pressure loss = (pressure loss from table D-6)/1000 x length of D.P


Pressure loss = (39.3/ 1000) x 604

= 23.74 kg/cm2

Step VII: Assuming for 12 ¼” hole size 5” drill pipe, Pressure loss through D/P



Step VIII: (i) Drill collar 8” x 3” = 28m

Assume Pressure loss through Drill collar bore3’’ = (23.5/100) x 28 Kg/cm2

= 6.58 Kg/cm2

(ii) Drill Collar 6 ½” x 2 13/16” = 112 m


Pressure losing (32.1/100) x 112 = 35.952 kg/cm2

(iii)HWDP 5” = 56 m


Total pressure loss through D/C = (6.58+35.952+2.2008) = 44.7328 kg/cm2

Step IX: Pressure Loss in annulus around the collar


Hole Size 12 ¼”, D/C size are

8” x 3” = 28 m, 0.23 kg/cm2/100

6 ½” x 2 13/16= 56 m, 0.23 kg/cm2/100

For 8” x 3” casing (0.23/100) x 28 = 0.0644 kg/cm2

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For 6 ½” x 2 13/16 (0.23/100) x 112 = 0.2576 kg/cm2

Annulus loss,

HWDPof size 5”

Pr. loss= (0.2/1000) x 56 =0.0112 kg/cm2

Total Pr. Loss around the drill collar annulus = 0.3332 kg/cm2


Sp.gr = 1.20


Actual System Pr. Loss = 79.1268 x (1.2/1.2) kg/cm2

ASPL = 79.1268 kg/cm2

Step XI: Pressure available for nozzle selection = (140 - 79.1268) x (1.2/1.2)

= 68.8732 kg/cm2



Mud wt = 1.2 gm/cc


= 48.7 x (1.2/1.2)

= 48.7 kg/cm2

Step XIII: Stand pipe Pr = 48.7 + 48.7

= 97.4 kg/cm2

Step XIV: %age BHP = (48.7 x 100)/ 97.4 =50 %


= (1.55 x 4777)/ (1.3254 x 60)

= 93.1365 kg/cm2




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= (48.7 x 4777/60)/ (5.97 x (12.25)2) = 4.328

Section 3

A) Hole size =8 ½”

Sp. Gr =1.25


Drill collar,

6 1/2” x 2 13/16 =168 m

5” HWDP =56 m

D.P 5” =1776 m


B) Operating pressure limit = 2 x 100 kg/cm2




Step II: liner size selected = 6 ½” = 165mm

No. Of pumps =1 Nos


Step III: SPM = ((circulation rate lit/min) / (No. Of pumps x lit/stroke))

= 5644/ (2 x 32.2) = 87.64 spm.


St pipe - 45 ft

ID - 4”

Hose - 55 ft

ID - 3”

Swivel - 5 ft

ID - 2 1/4”

Kelly - 40 ft

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ID - 3 ¼”


Step VI: Pressure loss = (pressure loss from table D-6) / 1000 x length of D.P


Pressure loss = (39.3 / 1000) x 1776

= 69.796 kg/cm2

Step VII: Assuming for 8 ½” hole size 5” drill pipe, Pressure loss through D/P



Step VIII: (i) Drill Collar 6 ½” x 2 13/16” = 168 m


Pressure losing (32.1/100) x 168 = 53.928 kg/cm2

(ii)HWDP 5” = 56 m


Total pressure loss through D/C = (53.928+2.2008) = 56.1288 kg/cm2

Step IX: Pressure Loss in annulus around the collar


Hole Size 8 ½”, D/C size are

6 ½” x 2 13/16= 168 m, 0.23 kg/cm2/100

For 6 ½” x 2 13/16 (0.23/100) x 168 = 0.3864 kg/cm2

Annulus loss for,

HWDP of size 5”

Pr. loss= (0.2/1000) x 56 =0.0112 kg/cm2

Total Pr. Loss around the drill collar annulus = 0.3976 kg/cm2


Sp.gr = 1.20

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Actual System Pr. Loss = 136.8776 x (1.25/1.2) kg/cm2

ASPL = 142.58 kg/cm2

Step XI: Pressure available for nozzle selection = (200- 142.58) x (1.2/1.25)

= 55.1232 kg/cm2



Mud wt = 1.25 gm/cc


= 44.3 x (1.25/1.2)

= 46.15 kg/cm2

Step XIII: Stand pipe Pr = 44.3 + 46.15

=90.45 kg/cm2

Step XIV: %age BHP = (44.3 x 100)/ 90.45 =48.98 %


= (1.55 x 5644)/ (1.5555 x 60)

= 94.066 kg/cm2




= (44.3 x 5644/60)/ (5.97(8.5)2) = 9.66

CASING DESIGN

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Factors Influencing Casing Design:Casing design involves the determination of factors which influence the failure of

casing andthe selection of the most suitable casing grades and weights for a specific operation, bothsafely and economically. The casing programme should also reflect the completion andproduction requirements.

A good knowledge of stress analysis and the ability to apply it are necessary for the design ofcasing strings. The end product of such a design is a 'pressure vessel' capable of withstandingthe expected internal and external pressures and axial loading. Hole irregularities furthersubject the casing to bending forces which must be considered during the selection of casinggrades.

A safety margin is always included in casing design, to allow for future deterioration of thecasing and for other unknown forces which may be encountered, including corrosion, wearand thermal effects.

Casing design is also influenced by:a. Loading conditions during drilling and production;b. The strength properties of the casing seat (i.e. formation strength at casing shoe);c. The degree of deterioration the pipe will be subjected to during the entire life of the

well;d. The availability of casing.

A casing string incorrectly designed can result in disastrous consequences, placing humanlives at risk and causing damage and loss of expensive equipment. The entire oil reservoir may be placed at risk if the casing cannot contain a kick which may develop into a blowout resulting in a large financial loss to the operating company and a large depletion of the reservoir potential.

Design Criteria:There are three basic forces which the casing is subjected to: collapse, burst and tension.These are the actual forces that exist in the wellbore. They must first be calculated and mustbe maintained below the casing strength properties. In other words, the collapse pressuremust be less than the collapse strength of the casing and so on.

Casing should initially be designed for collapse, burst and tension. Refinements to the selected grades and weights should only be attempted after the initial selection is made.

For directional wells a correct well profile is required to determine the true vertical depth(TVD). All wellbore pressures and tensile forces should be calculated using true verticaldepth only. The casing lengths are first calculated as if the well is a vertical well and thenthese t lengths are corrected for the appropriate hole angle.

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Collapse criteria:

Collapse pressure originates from the column of mud used to drill the hole, and acts on theoutside of the casing. Since the hydrostatic pressure of a column of mud increases withdepth, collapse pressure is highest at the bottom and zero at the top.This is a simplified assumption and does not consider the effects of internal pressure.

For practical purposes, collapse pressure should be calculated as follows:

Collapse pressure = External pressure – Internal pressure

The actual calculations involved in evaluating collapse and burst pressures are usually straight forward. However, knowing which factors to use for calculating external an internal pressure is not easy and requires knowledge of current and future operations in the wellbore.

The following procedure was used for collapse design:Assumptions1. Casing is assumed empty due to lost circulation at casing

setting depth (CSD) or at TD of next hole2. Internal pressure inside casing is zero3. External pressure is caused by mud

in which casing was run in4. No cement outside casing

The equation could be written asCollapse pressure (C) = mud density x depth x acceleration due to gravity

=0.052 x x CSD….psi

=W x D

10

…………..Kg/sq.cmWhere is in ppg CSD is in ft.W is mud weight in gm. /ccD is depth in cm

LOST CIRCULATIONIf collapse calculations are based on 100% evacuation then the internal pressure

(or back up load) is to zero. The 100% evacuation condition can only occur whena. The casing is run emptyb. There is complete loss of fluid into a thief zone (say into a cavernous formation),c. There is complete loss of fluid due to a gas blowout which subsequently subsides

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None of these conditions should be allowed to occur in practice with the exception of encountering cavernous formations.

During lost circulation, the mud level in the well drops to a height such that the remaining hydrostatic pressure of mud is equal to the formation pressure of the thief zone. In this case the mud pressure exactly balances the formation pressure of the thief zone and fluid loss into the formation will cease. If the formation pressure of the thief is not known, it is usual to assume the pressure of the thief zone to be equal to 0.465 psi/ft. or 0.0075gm/cm.

Burst criterionIn oil well casings, burst occurs when the effective internal pressure inside the casing(internal pressure minus external pressure) exceeds the casing burst strength. Like collapse, the burst calculations are straightforward. The difficulty arises when oneattempts to determine realistic values for internal and external pressures.

In development wells, where pressures are well known the task is straight forward. Inexploration wells, there are many problems when one attempts to estimate the actualformation pressure including:a. The exact depth of the zone (formation pressure increases with depth)b. Type of fluid (oil or gas)c. Porosity, permeabilityd. Temperature

The above factors determine the severity of the kick in terms of pressure and ease ofDetection Clearly; one must design exploration wells for a greater degree of uncertainty thandevelopment wells. Indeed, some operator’s manuals detail separate design methods fordevelopment and exploration wells

BURST CALCULATIONSBurst Pressure, B is given by:

B = internal pressure – external pressure

DESIGN & SAFETY FACTORS

Safety factor uses a rating based on catastrophic failure of the casing.

Safety Factor = failure load

actual applied load

Design factor uses a rating based on the minimum yield strength of casing.

Design Factor(D . F)= Rating of pipeMax Expected Service Load

The burst design factor (DF-B) is given by:

Design Factor(DF−B)= Burst StrengthBurst pressure (B)

Similarly, the collapse design factor is given by:

Design Factor(D . F−C)= Collapse strengthCollapse pressure(C)

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RECOMMENDED DESIGN FACTORS

SI.no

Type of Design Recommended DF Industry Recommended DF

1 Collapse 1.0 1.0-1.12 Burst 1.1 1.1-1.253 Tension 1.6-1.8 1.3-1.84 Compression 1.0 1.05 Triaxile design 1.1 1.1-1.2

CASING SELECTION- BURST AND COLLAPSE

However before a load case is applied, the casing grades/weights should initially be selected on the basis of burst and collapse pressures, then load cases should be applied. If only one grade or one weight of casing is available, and then the task of selecting casing is easy. The strength properties of the casings available are compared with the collapse and burst pressures in the wellbore. If the design factors in collapse and burst are acceptable then all that remains is to check the casing for tension.

For deep wells or where more than one grade and weight are used, a graphical method of selecting casing is used as follows:1. Plot a graph of pressure against depth, as shown in Figure 5.5, starting the depth and

pressure scales at zero. Mark the CSD on this graph.2. Collapse Line: Mark point C1 at zero depth and point C2 at CSD.3. Draw a straight line through points C1 and C2.For partial loss circulation, there will

be three collapse points. Mark C1 at zero depth, C2 at depth (CSD-L) and C3 at CSD. Draw two straight lines through these points.

4. Burst Line: Plot pointB1 at zero depth and point B2 at CSD. Draw a straight line through point B1 and B2 For production casing, the highest pressure will be at casing shoe.

5. Plot the collapse and burst strength of the available casing, as shown in above Figure. In this figure, two grades, N80 and K55 are plotted to represent the available casing.

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6. Select a casing string that satisfies both collapse and burst. Figure provides the initial selection and in many cases this selection differs very little from the final selection. Hence, great care must be exercised when producing Figure.

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Tension Criteria:

Tension loadings canarise due to: bending, drag, shock loading and during pressure testing of casingin casing design, the uppermost joint of the string is considered the weakest in tension, as ithas to carry the total weight of the casing string. Selection is based on a design factor of 1.6to 1.8 for the top joint.Tensile forces are determined as follows:1. Calculate weight of casing in air (positive value) using true vertical depth;2. Calculate buoyancy force (negative value);3. Calculate bending force in deviated wells (positive value);4. Calculate drag force in deviated wells (this force is only applicable if casing ispulled

out of hole);5. Calculate shock loads due to arresting casing in slips; and6. Calculate pressure testing forces

Forces (1) to (3) always exist, whether the pipe is static or in motion. Forces (4) and (5) exist only when the pipe is in motion

TENSION CALCULATIONS:

Buoyant Weight of Casing (Positive Force):

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The buoyant weight is determined as the difference between casing air weight and buoyancy force.

Casing air weight = casing weight (lb/ft) x hole TVD (5.20)

For open-ended casing, see Figure

Buoyancy force = Pe (Ae – Ai) (5.21)

For closed casing, see Figure Buoyancy force = Pe Ae – Pi Ai (5.22)

Where Pe = external hydrostatic pressure, psiPi = internal hydrostatic pressure, psiAe and Ai are external and internal areas of the casing

Since the mud inside and outside the casing is invariably the same, the buoyancy force is almost always given by

Buoyancy force = Pe (Ae – Ai)

If a tapered casing string is used then the buoyancy force at TD is calculated as above. At across-sectional change, the buoyancy force is calculated as follows:

Buoyancy force = Pe2 (Ae2 – Ae1) – Pi2 (Ai2- Ai1)

For most applications, the author recommends calculating the buoyant weight as follows:

Buoyant weight = air weight x buoyancy factor

Bending Force:

The bending force is given by:

Bending force = 63 Wn x OD x θ (5.26)Where Wn = weight of casing lb/ft (positive force)

θ= dogleg severity, degrees/100 ft

Shock LoadShock loading in casing operations results when: Sudden decelerations are applied Casing is picked off the slips Slips are kicked in while pipe is moving

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Casing hits a bridge or jumps off an edge down hole Shock loading is a dynamic force with a very short duration: approximately one second. It can be shown that the shock is

given by 1: Fshock = 1780 V As (5.27)whereAs = cross-sectional areaV = pipe running velocity in ft/s, usually taken as theInstantaneous velocity (some operators use V = 5 ft/s as the instantaneous velocity)After some observations the above shock load equation could be w rewritten as

Shock load (max) = 1500 x Wn

Drag ForceThis force is usually of the order of 100,000 lbf (positive force). Because the calculation of drag force is complex and requires an accurate knowledge of the friction factor between the casing and hole, shock load calculations will in most cases suffice. The effect of the drag force lasts for the duration of running a joint of casing; shock loading lasts for only 1 second or so. Hence shock loading and drag forces cannot exist simultaneously. In most cases the magnitude of shock and drag forces are approximately the same

Pressure TestingThe casing should be tested to the maximum pressure which it sees during drilling and production operations (together with a suitable rounding margin).

PRESSURE TESTING ISSUESWhen deciding on a pressure test value, the resulting force must not be allowed to exceed: 80% of the rated burst strength The connection pressure rating 75% of the connection tensile rating Triaxile stress rating of the casing

Load cases:

There are three load cases for which the total tensile force should be calculated for: running conditions, pressure testing and static conditions. These load cases are sometimes described as Installation Load cases. Other load cases will be discussed later.

Load Case 1: Running ConditionsThis applies to the case when the casing is run in hole and prior to pumping cement:

Total tensile force = buoyant weight + shock load +bending force

Load Case 2: Pressure Testing Conditions

This condition applies when the casing is run to TD, the cement is displaced behind the casing and mud is used to apply pressure on the top plug. This is usually the best time to test the casing while the cement is still wet. In the past, some operators tested casing

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after the cement was set. This practice created micro channels between the casing and the cement and allowed pressure communication between various zones through these open channels.

Total tensile force = buoyant weight + pressure testing force +bending force

Load Case 3: Static ConditionsThis condition applies when the casing is in the ground, cemented and the well

head installed. The casing is now effectively a pressure vessel fixed at top and bottom. One canargue that other forces should be considered for this case such as production forces, injectionforces, temperature induced forces etc.

Total tensile force = buoyant weight + bending force + (miscellaneous forces)

It is usually sufficient to calculate the total force at the top joint, but it may be necessary tocalculate this force at other joints with marginal safety factors in tension.Once again, ensure that the design factor in tension during pressure testing is greater than1.6, i.e.

DF−T= Yield strenghthTotal tensile forces during pressure testing

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Load calculations:

Collapse Pressure:

Surface casing (13 3/8’’, J-55, 61ppf, BTC)

collapse pressure at 150 m=WxD10

kg/ sq . cm

collapse pressure at 150 m=1.06 x15010

=15.9 kg /sq .cm

Intermediate Casing (9 5/8’’, N-80, 40ppf, BTC)


kg /sq . cm

collapse pressure at 800 m=1.20 x80010

=96 kg /cm2

Production Casing (5 ½’’, N-80, 17ppf, BTC)


kg/ sq . cm

collapse pressure at 2000 m=1.25 x 200010

=250 kg /sq . cm

Burst Calculations:

Surface Casing: (13 3/8’’, J-55, 61ppf, BTC)

Case 1: By using Formation PressureExpected formation pressure = Hydrostatic Pressure + (10%Hydrostatic Pressure)

=110% Hydrostatic Pressure (of next Casing)

Hydrostatic Pressure = M x D/10 kg/sq.cm= 1.20x800/10

= 96 kg/sq.cm

Formation Pressure = 1.1x96=105.6 kg/sq.cm

surface pressure= Formation Pressureexp (0.0001138 xgas gradientxdepth)

kg /sq .cm

surface pressure= 105.6exp (0.0001138 x 0.65x 1200)

kg /sq . cm

=99.53 kg/sq.cm

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Case2: By using Fracture Pressure

Fracture Gradient of Gandhar field is = 0.8-0.9 psi/ft.= 1.8476-2.075 gm./cc.

Taking minimum Fracture Gradient=1.85 gm/cc

Fracture pressure=FractureGradient xCSD10

kg/ sq . cm

Fracture pressure=1.85 x15010

=27.75 kg/ sq . cm

surface pressure= Fracture Pressureexp (0.0001138 xgas gradientxdepth)

kg /sq .cm

surface pressure= 27.75exp (0.0001138 x 0.65x 150)

kg /sq . cm

=27.44 kg/sq.cmTake minimum Value=27.44 kg/sq.cm

Intermediate Casing: (9 5/8’’,N-80,40ppf,BTC)

Case 1: By using Formation PressureExpected formation pressure = Hydrostatic Pressure + (10%Hydrostatic Pressure)

=110% Hydrostatic Pressure (of next Casing)

Hydrostatic Pressure=MxD/10 kg/sq.cm =1.25x2000/10

=250 kg/sq.cm

Formation Pressure=1.1x250=275 kg/sq.cm

surface pressure= Formation Pressureexp (0.0001138 xgas gradientxdepth)

kg /sq .cm

surface pressure= 275exp (0.0001138 x 0.65x 2000)

kg /sq .cm

=237.18kg/sq.cm

Case2: By using Fracture Pressure

Fracture Gradient of Gandhar field is =0.8-0.9 psi/ft.=1.8476-2.075 gm./cc.


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kg/ sq . cm

Fracture pressure=1.85 x 80010

=148 kg /sq . cm


kg /sq .cm


=139.496 kg /sq . cm

Take Minimum Value =139.496 kg/sq.cm

Production Casing:

By using Fracture Pressure

Fracture Gradient of Gandhar field is =0.8-0.9 psi/ft.=1.8476-2.075 gm./cc.



kg/ sq . cm

Fracture pressure=1.85 x200010

=370 kg/ sq . cm


kg /sq .cm


kg /sq .cm

=319.12 kg/sq.cm

Tensile Load Calculations:

Surface Casing: (13 3/8’’, J-55, 61ppf, BTC)

W=1.06

Buoyancy=7.85−W7.85

Buoyancy=7.85−1.067.85

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=0.865

Tensile Load=( ppf ∨ kg

mxCSD )Buoyancy

1000Tonne s

Tensile Load=90.77 x150 x .8651000

Tonnes

=11.777Tonnes

Intermediate Casing: Combination Casing String

W=1.20


Buoyancy=7.85−1.207.85

= 0.847


mxCSD )Buoyancy

1000Tonnes

Tensile Load=¿¿

= 44.30 Tonnes

Production Casing: (Combination Casing)W=1.25


Buoyancy=7.85−1.257.85

= 0.841


mxCSD )Buoyancy

1000Tonnes

Tensile Load=((90.77 x 150 )+(650∗59.52 )+ (1200∗25.29 ))0.841

1000

=69.41Tonnes

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Casing Performance Properties:

Grade Size Weight(ppf)

Collapse Resistance(kg/cm2)

Pipe Yield(in Tonnes)

Joint Strength(BTC)

(in Tonnes)

Burst Resistance(kg/cm2)

J-55,13 3/8’’ 61 108 436.35 464.35 217 N-80,9 5/8’’ 40 217 415.5 444 404 N-80,5 ½’’ 17 442 180 202.3 544

Design Factors Calculations:

CasingLoads

Surface Casing

IntermediateCasing

Production Casing

Design Factors

Collapse Pressure 15.9kg/sq.cm 96 kg/sq.cm 250kg/sq.cm 6.67,2.26,1.768,

Burst Pressure 27.44 kg/sq.cm

139.496 kg/sq.cm

319.12kg/sq.cm 7.91,2.89,1.70

Tensile Load 11.777Tonnes 44.30Tonnes 69.41 Tonnes 39.47,10.02,2.91

REFERENCES:

Institute of Drilling Technology, ONGC, Dehradun -- Drilling Operations Manual; First Edition 1994

Drilling & Well Completion, Gatlin, Carl Baker Hughes INTEQ - Oil Field Familiarization Training Guide Baker Hughes INTEQ (1995) - Drilling Engineering Workbook Herriot-Watt University – Drilling Engineering book Mud Engineering by Prof. Abdel-Alim Hashem Well Engineering & Construction, Rabia, H

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