INDUSTRIAL TRAINING COURSE E&D Directorate, Anveshan Bhavan ONGC, Dehradun (29.05.2017 – 29.06.2017)
Nilesh Singhal B.Tech Applied Petroleum Engineering Upstream (Upstream) 2nd Year University of Petroleum and Energy Studies
WELL LOG INTERPRETATION (APPLICATIONS IN HYDROCARBON EXPLORATION)
Certificate This is to certify that the project “Well Log Interpretation - Applications in Hydrocarbon Exploration” carried out by Nilesh Singhal, student of Applied Petroleum Engineering (Upstream), University of Petroleum and Energy Studies, Dehradun is approved as a credible work and submitted on the completion of the summer training. It is a bona-fide record of the work done by him under my supervision during his stay as an intern at Exploration and Development Directorate, ONGC, Dehradun during the period 29 th May, to 29th June 2017.
Dr. Kaustav Nag) DGM (Geology) E&D Directorate ONGC, Dehradun
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Certificate This is to certify that the project “Well Log Interpretation - Applications in Hydrocarbon Exploration” carried out by Nilesh Singhal, student of Applied Petroleum Engineering (Upstream), University of Petroleum and Energy Studies, Dehradun is approved as a credible work and submitted on the completion of the summer training. It is a bona-fide record of the work done by him under my supervision during his stay as an intern at Exploration and Development Directorate, ONGC, Dehradun during the period 29 th May, to 29th June 2017.
Dr. Kaustav Nag) DGM (Geology) E&D Directorate ONGC, Dehradun
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Acknowledgement This is to acknowledge with thanks, the help, guidance and support that I have received during my summer internship in ONGC Academy, Dehradun. I would like to thank Mr. Avinash Chandra ED-HOI, ONGC Academy, for permitting to do my training course at E&D Directorate, Dehradun. I am also thankful to Mr. Sanjay Bhutani DGM (Chemistry), ONGC Academy for his kind help and support. I offer my deep sense of reverence and gratitude to my mentor Mr. Kaustav Nag DGM (Geology) for his valuable guidance and kind supervision. His valuable suggestions were of immense help throughout my internship. Working under him was an extremely knowledgeable experience for me. I would like to take this opportunity to express my profound gratitude and deep regards to Mr. Virendra Kumar SG (Wells) for his kind help and support. I would also like to express my gratitude to Mr. Sunit Kumar Sharma DGM Geophysics (S), Dr. Kailash Bahada Manager (Reservoir), Mr. R.N. Goswami (Chief Geologist), Mr. T.R. Joshi DGM (Wells), Mr. Prafull Kumar Gupta (Drilling), Mr. Trilok Chand, Mr. Ratan Singh Vikram for sharing their pearls of wisdom with me during the course of our internship. I am grateful to Mr. Devashish Chakravarty Chakravarty GM (Geology) for the encouragement, guidance guidance and assistance they provided throughout the period of my internship. Needles to mention the team of officers from E&D Dte who have provided valuable inputs at different occasions which helped in various exploration and production activities are gratefully acknowledged. I would also like to thank Mr. R.P. Soni of UPES, Dehradun for giving me the opportunity to do my internship from ONGC Dehradun.
Place – Dehradun Date -
Nilesh Singhal B.Tech Applied Petroleum Engineering (Upstream), 2 nd
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Index 1. History of Oil Industry in India 1.1 ONGC 1.1.1 Onshore 1.1.2 Offshore 2. About “E&D Dte” 3. About Assam-Arakan Basin 3.1 Introduction 3.2 Regional Geology: An Overview 3.3 Stratigraphy 3.4 Petroleum System 3.5 Hydrocarbon Plays – Established and new plays 3.6 Assam Basin Hydrocarbon Potential 4. Category of Petroliferous Basins of India 5. Well Logging 5.1 Well Logs- A definition 5.2 Applications 5.3 Well Log Interpretation: Finding the Hydrocarbon 5.4 Cement Bond Log 5.5 Production Logging 6. The Seismic Method - Acquisition 7. Bibliography
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History of oil industry in India
1
"Barely seven years after Edwin L. Drake drilled the world's first oil well in 1859 at Titusville, Pennsylvania, USA, history registered another exploration of the black liquid gold, in the largest continent. More than a century ago, history was made in a remote corner of Assam in the midst of the dense and malaria infested jungles, by a band of intrepid pioneers searching for black gold. In 1867 Italian Engineers, commissioned by the Assam Railways and Trading Company, to build a railway line from Dibrugarh to Margherita (Headquarters of Assam Railways and Trading Company) accidentally discovered oil at Digboi around 10 miles from Margherita. ‘Dig boy, dig’, shouted the English engineer, Mr. W L Lake, at his men as they watched elephants emerging out of the dense forest with oil stains on their feet". The first well was completed in 1890 and the Assam Oil Company was established in 1899 to oversee production. At its peak during the Second World War the Digboi oil fields were producing 7,000 barrels per day. Initially, India was laid off as hydrocarbon barren and was largely ignored in terms of the hydrocarbon diplomacy.
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. In order to find the expertise necessary to reach these goals foreign experts from West Germany, Romania, the US, and the Soviet Union were brought in. The Soviet experts were the most influential and they drew up detailed plans for further oil exploration which were to form part of the second five-year plan. India thus adopted the Soviet model of economic development and the state continues to implement five-year plans as part of its drive towards modernity. The increased focus on exploration resulted in the discovery of several new oil fields most notably the off-shore Bombay High field which remains by a long margin India’s most productive well. After liberalization, ONGC was reorganized into a public limite d company (it is now called for Oil and Natural Gas Corporation) and around 2% of government held stocks were sold off. Despite this however the government still plays a pivotal role and ONGC is still responsible for 77% of oil and 81% of gas production while the Indian Oil Corporation (IOC) owns most of the refineries putting it within the top 20 oil companies in the world. The government also maintains subsidized prices. As a net importer of oil however India faces the problem of meeting the energy demands for its rapidly expanding population and economy and to this the ONGC has pursued drilling rights in Iran and Kazakhstan and has acquired shares in exploration ventures in Indonesia, Libya, Nigeria, and Sudan.
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ONGC
1.1
Oil and Natural Gas Corporation Lt d. (ONGC) is the flagship National Oil Company of India, a 'Maharatna', with interests in E&P, Refining, LNG, Power, Petrochemicals & New sources of energy. It has been reliable energy solution provider for the country for more than six decades now. Pursuing the vision to be global leader in integrated energy business through sustainable growth, knowledge excellence and exemplary governance practices, ONGC today holds leadership position in several aspects of its business amongst international companies. It has capabilities in entire gamut of E&P sector. As on 01.04.2016, ONGC is operating in 14 basins and has established hydrocarbons in 9 basins. So far, 83% of established reserves in India have been discovered by ONGC. It is the largest exploration acreage and mining lease holder in India. ONGC has been the largest oil and gas producer in India contributing 69.6% of oil and 70% of natural gas production during FY 2015-16.
ONSHORE
1.1.1
ONGC has got seven producing assets in Onshore - Ahmedabad, Mehsana, Ankleshwar, Assam, Tripura, Rajahmundry and Cauvery Assets.
Two producing basins- Cambay and Assam Arakan Fold Belt (AAFB).
IOR schemes implemented in 13 major onshore fields.
OFFSHORE
1.1.2
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 GS15 Offshore fields in East Coast, KG Basin, B-22 cluster, etc.
Oil and Gas produced from offshore processed at Uran and Hazira plant.
Crude oil production by ONGC during March, 2017 was 1931.29 TMT. Natural gas production by ONGC during March, 2017 was 1972.33 MMSCM On 31 March 2013, its market capitalization was INR 2.6 trillion (US $48.98billion), making it India’s second largest publicly traded company. In a government survey for FY 2011-12, it was ranked as the largest profit making PSU in India. ONGC has been ranked 357 th in the Fortune Global 500 list of the world’s biggest corporations for the year 2012. It is ranked 22nd among the Top 250 Global Energy Companies by Platt. Despite a global downturn in investments due to fall in crude oil prices, the company has largely maintained its capex levels – the capex in FY'15 and FY'16 was Rs 29,997 Crore and Rs 30,110Crore respectively and the budgeted commitment for FY'17 stands at Rs 29,307 Crore.
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As many as five development projects valued at Rs 24,800 Crore were completed in FY'16 and seven projects worth Rs 48,000 Crore were approved in the last fiscal. Cumulatively, in the past two years, ONGC's Board has approved projects worth over Rs 75,000 Crore. These will t ranslate to additional oil and gas production of over 170 Million Metric tons of Oil plus Oil Equivalent Gas (O+OEG). This includes the approval of the biggest investment ever decision to develop the Cluster 2 fields of KG-DWN-98/2 block worth over USD 5 billion. In the international arena, ONGC Videsh a wholly-owned subsidiary is operating 38 projects in 17 countries. ONGC Videsh has provisional 3P reserves of approx. 743 MMTOE as on 01.04.2017. Furthermore, ONGC has also taken structured initiatives to tap unconventional energy sources, be it unconventional gases like Coal Bed Methane (CBM), Underground Coal Gasification (UCG), Shale Gas and Gas Hydrates, or unconventional energy sources like wind, solar etc.
It owns and operates over 11,000 kilometers of pipelines in the country. Against a global decline of production from matured fields, ONGC has maintained production from its brown fields like Mumbai High, with the help of aggressive investments in various IOR (Improved Oil Recovery) and EOR (Enhanced Oil Recovery) schemes. ONGC has many matured fields with a current recovery factor of 25-33%. During FY 2012-13, ONGC had to share the highest ever underrecovery of INR 494.2 million. ONGC was the first to establish shale gas presence in India and has also supported Govt. of India in assessing shale gas potential in India. ONGC has forayed into petrochemicals through two world-class petrochemicals plants, ONGC Petro-additions Ltd (Opal) and ONGC Mangalore Petrochemicals Ltd (OMPL). ONGC is already generating 51 MW of wind power in Gujarat and another 102 MW has been recently commissioned in Rajasthan. Various R&D activities are carried out by 12 Institutes. ONGC invests in community development activities through CSR projects and spent Rs. 421 Crore on CSR activities in FY 1516. ONGC has been actively pursuing a number of Clean Development Mechanism projects and Carbon Neutrality. 12 CDM projects have been registered with UNFCCC. All operational units of ONGC are certified with ISO 9001, 14001 and OHSAS- 18001. Honorable Prime Minister has made a visionary call to realize a 10 percent reduction in the country's crude imports by 2022. Achieving the targeted reduction in imports would require a renewed impetus to increase the production of oil and gas in India.
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About “E&D Dte”
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Exploration and Development Directorate, is the nodal agency at Headquarters for exploration planning, evaluation, inter and intra basinal integration, reserves accretion, and monitoring of all exploration & development activities of ONGC on behalf of Director (Exploration). Broad Functions which are undertaken are given bel ow: 1. Annual Exploration Programme 2. Five year Plans 3. Prospect generation & Prioritization 4. Monitoring and mid-course correction of exploratory activities 5. Reserve accretion & Estimation 6. Monitoring and participation in Field Development activities 7. Co-ordinate NELP bidding 8. Management Support 9. Key Member for formulating Perspective plan PP-2030 of ONGC In ONGC, there is a variety of database. In terms of exploration, there are databases in the form of reports which have been scanned such as those kept at CEGDIS, E&D Directorate or KDMIPE at Dehradun.
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About Assam-Arakan Basin Introduction:
3 3.1
Oil exploration in India commenced with the discovery of the Digboi oilfield in Upper Assam more than 100 years ago, when, based on surface oil shows, a well was drilled on an exposed anticline, associated with the Naga thrust. Other significant milestones in oil exploration in Upper Assam were the discoveries of the Nahorkatiya, Moran and Rudrasagar oil fields in 1953, 1956 and 1960, respectively. Subsequently, more than 100 oil and gas fields, including Jorajan, Kumchai, Hapjan, Shalmari, Lakwa, Lakhmani, Geleki, Amguri, Charali, Borholla, Khoraghat, Baghjan, Dirok etc. have been discovered.
REGIONAL GEOLOGY: AN OVERVIEW
3.2
The Assam-Arakan Basin is situated in the north-eastern part o f India categorized as category-I basin. The basin covers an area of 116000 Sq.Km. Major tectonic elements of the basin are:
• Assam Shelf • Naga Schuppen belt • Assam-Arakan Fold belt.
Figure 1: Generalized geological map of Assam province
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Stratigraphy
3.3
Sedimentary sequences ranging in age from Late Mesozoic to Cenozoic are exposed in the Assam-Arakan Basin. The sequences can be divided into shelf facies and basinal (geosynclinal) facies. The shelf facies occur in Garo hills, Khasi-Jaintia hills, parts of North Cachar hills and Mikir hills, and below the alluvial cover in Upper Assam, Bengal and Bangladesh. The basinal facies occur in the Patkai range, Naga Hills, parts of North Cachar hills, Manipur, Surma valley, Tripura, Chittagong hills of Bangladesh and Chin hills o f Myanmar (Burma).
Figure 2: Generalized cross section showing development of Assam Shelf
Figure 3: Oil and gas field and identified prospects in Assam geological province
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The oldest sedimentary rocks reported near the Assam geologic province are thin Cretaceous limestones to the south, in eastern Manipur. Within the Assam geologic province, the oldest sedimentary rocks are the continental to lagoonal sandstones and interbedded shales of the Upper Cretaceous and Paleocene Dergaon and Disang Formations. The top of the Dergaon and Disang is marked by an unconformity
and overlain by the medium-grained massive sandstones of the Paleocene and Eocene Jaintia Group Tura and Langpar Formations
Figure 4: Generalized Stratigraphy of Assam Shelf
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Petroleum System
3.4
All the oil and gas fields, discovered till date in the Upper Assam shelf, are situated mostly on the southeastern slope of the Brahmaputra arch, and almost all the major oil fields like Nahorkatiya, Lakwa, Lakhmani, Geleki, Dikom Kathaloni etc. lie in a belt bordering the Naga thrust. In the Dhansiri valley also, oil fields like the Borholla and Khoraghat and Nambar lie in the same belt. In the Naga Schuppen belt, oil accumulations in the Lakshmijan and the Champang oil fields occur in that zone of the shelf which is overridden by the Naga thrust. In the Digboi and Kharsang oil fields, oil occurs in Tipam Sandstone and Girujan Clay formations, respectively, overlying the Naga thrust. Source Rock and Hydrocarbon Generation
3.4.1
The important source rock sequences occur within the argillaceous Kopili Formation and in the Coal-Shale Unit of the Barail Group. The average TOC of shales within the Sylhet Formation is about 0.60%, in the Kopili Formation, about 2.5% and in the Barail Coal-Shale Unit, about 3.8%. The average TOC ranges of different formations (shale samples) are as follows:
Formation
Average TOC Range
Remarks
Barail (shales) Kopili (shales) Sylhet Limestone Basal Sandstone
2.5% to 4.5% 1% to 3% ~ 0.61% ~ 0.62%
Excellent source potential Excellent source potential Poor source potential Poor source potential
Organic matter richness of shales increases towards the Naga thrust. In both Kopilis and Barails, the organic matter is terrestrial type-III with varying contributions of Type-II. Barail Coal-Shale Unit in the Schuppen belt also form important source rock sequence. In the Naga fold belt, in addition to above, Disang shales also possess excellent source rock characteristics with TOC around 4% and VRo varying from 0.69% to 1.94%. Geochemical analysis of exposed sediments from the Schuppen belt show a TOC range of 0.64-1.20% for Barail shales. The dominant organic matter type is structured terrestrial. Presence of amorphous (upto 60%) and extractable organic matter (upto 55%) indicates a fairly good liquid hydrocarbon generating potential.
Organic matter is mainly humic and sapropelic. TAI of 2.6 to 2.75 and VRo of 0.57 to 0.67% show that the sediments are thermally mature and within oil window. In the subthrust, the source sequences occur at greater depths and, therefore, should be in a higher state
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of thermal maturity. It is expected that the source sequences within the Kopili and Barail formations in the subthrust would be at the peak oil generating state. Reservoir Facies
3.4.2
Barring the Borholla and Champang oil fields of the Dhansiri valley and the adjacent schuppen zone respectively, where oil occurs in fractured granitic basement rock (Precambrian) and Tura sandstones (Upper Paleocene/ Lower Eocene), oil in the Upper Assam Shelf and schuppen belt occurs in sandstone reservoirs ranging in age from Upper Paleocene-Lower Eocene to Mio-Pliocene. However, the major accumulations occur in Upper Paleocene + Lower Eocene, Oligocene (Barail Formation) and Miocene (Tipam Sandstone) sandstones. Cap Rock and Entrapment
3.4.3
There are three well developed regional cap rocks within the Tertiary sedimentary succession, the lower one, occurring in the Upper Eocene is the argillaceous Kopili Formation, the middle one is the Barail Coal-Shale Unit and the upper one, overlying the Tipam Sandstone is the Girujan Clay. Most of the oil accumulations, discovered till date in the Upper Paleocene-Lower Eocene, Oligocene (Barail) and Miocene (Tipam Sandstone) reservoirs, occur in structural combination (fold + fault) traps developed by compressive forces during Mio- Pliocene and later time.
Figure 5: Events chart summarizing stratigraphy, source rocks, reservoirs, seals, traps, and petroleum information for the SyllhetKopili/Barail-Tipam Composite Total Petroleum System.
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Hydrocarbon Plays - Established and New Plays
3.5
Oil and gas are established from clastics reservoirs of Mio-Pliocene- Girujan, Miocene -Tipam, Oligocene –Eocene –Barails, Mid-Upper Eocene –Kopilli, Lower Eocene –Lakadong and Therria and from the fractured Archean Basement. The Miocene – Oiligocene –Tipam and Barail Formations contain most of the discovered oil. Exploration of deeper plays (Tura and Basement) has been a major challenge in the Assam Shelf. Tura play (Palaeocene) is an exciting horizon in terms of deeper prospect exploration in entire North Assam Shelf and has potential to emerge as a significant play. Recent exploratory efforts by NOC’s has resulted in risk-reward perception of Tura play and identification of prospects in Lakwa and Geleki fields in the northern part of Assam S helf. There has been significant achievement in establishing fractured Basement and Kopili plays (Eocene) in southern part of the Assam Shelf in Khoraghat area which has opened up new area for exploration of deeper plays in the Assam Shelf.
Assam Basin Hydrocarbon Potential
3.6
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Category of Petroliferous Basins of India
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Category Basis for categorization of S edimentary Basins in India
1. Proven Petroliferous Basins with commercial production Assam Shelf, Cambay, Rajasthan, Assam-Arakan fold belt, Mumbai Offshore, Krishna-Godavari and Cauvery Basins. 2. Proven Petroliferous Basins awaiting commercial production Kutch, Mahanadi-NEC (North East Coast), Basin, Andaman-Nicobar Basins. 3. Basins geologically considered prospective with hydrocarbon shows Himalayan Foreland Basin, Ganga Basin, Vindhyan Basin, Saurashtra Basin, Kerala Konkan Basin, and Bengal Basin. 4. Frontier Basins which are either poorly explored or having inadequate geological information or are rated poor based on present concepts and knowledge of petroleum geology but considered prospective by analogy with similar Basins in the world Karewa Basin, Spiti-Zanskar Basin, Satpura –South Rewa – Damodar Basin, Chhattisgarh Basin, Narmada Basin, Deccan Syneclise, Bhima-Kaladgi, Bastar Basin, Pranhita-Godavari Basin, Cuddapah Basin
Figure 6: Map of Petroliferous Basins of India showing the c ategories (after DGH)
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Well Logging
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Log can be defined as the systematic recording of data, versus depth or time, in wells being drilled or produced to obtain various characteristics of downhole formations. It is from Interpreting Log data that we can provide most of the answers needed for Formation Evaluation Well logs – A definition
5.1
The continuous recording of a geophysical parameter along a borehole produces a geophysical well log. The value of the measurement is plotted continuously against depth in the well. The most appropriate name for this continuous depth related recor d is a wire line geophysical well log, conveniently shortened to well log or log. It has often been called an ‘electrical log’ because historically the first logs were elec trical measurements of electrical properties. However, the measurements are no longer electrical, and modern methods of data transmission do not necessarily need a wire line. First well log was invented by Conrad Schlumberger and Henri Doll at France in 1927.
Figure 7: Representation of first “Well log” made at France
1. Well logging plays a central role in the successful development of a hydrocarbon reservoir. Its measurements occupy a position of central importance in the life of a well, between two milestones: the surface seismic survey, which has influenced the decision for the well location, and the production testing. The traditional role of wire line logging has been limited to participation primarily in two general domains: formation evaluation and completion evaluation.
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The goals of formation evaluation can be summarized by a statement of four questions of primary interest in the production of hydrocarbons: 1. Are there any hydrocarbons, and if so are they oil or gas? First, it is necessary to identify or infer the presence of hydrocarbons in formations traversed by the wellbore. 2. Where are the hydrocarbons? The depth of formations, which contain accumulations of hydrocarbons, must be identified. 3. How much hydrocarbon is contained in the formation? An initial approach is to quantify the fractional volume available for hydrocarbon in the formation. This quantity, porosity, is of utmost importance. A second aspect is to quantify the hydrocarbon fraction of the fluids within the rock matrix. The third concerns the areal extent of the bed, or geological body, which contains the hydrocarbon. This last item falls largely beyond the range of traditional well logging. 4. How producible are the hydrocarbons? In fact, all the questions really come down to just this one practical concern. Unfortunately, it ithe most difficult to answer from inferred formation properties. The most important input is a determination of permeability. Many empirical methods are used to extract this parameter from log measurements with varying degrees of success. Another key factor is oil viscosity, often loosely referred to by its weight, as in heavy or light oil. Formation evaluation is essentially performed on a well-by-well basis. A number of me asurement devices and interpretation techniques have been developed. They provide, principally, values of porosity, shaliness and hydrocarbon saturation, as a function of depth, using the knowledge of local geology and fluid properties that is accumulated as a reservoir is developed. Because of the wide variety of subsurface geological formations, many different logging tools are needed to give the best possible combination of measurements for the rock type anticipated. Despite the availability of this rather large number of devices, each providing complementary information, the final answers derived are mainly three: the location of oil bearing and gas-bearing formations, an estimate of their producibility, and an assessment of the quantity of hydrocarbon in place in the reservoir.
Applications
5.2
In the most straightforward application, the purpose of well logging is to provide measurements, which can be related to the volume fraction and type of hydrocarbon present in porous formations. Measurement techniques are used from three broad disciplines: electrical, nuclear, and acoustic. Usually a measurement is sensitive either to the properties of the rock or to the pore-filling fluid. Uses of well logging in petroleum engineering. (Adapted from Pickett)
1. Logging applications for petroleum engineering 2. Rock typing 3. Identification of geological environment 16
4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14.
Reservoir fluid contact location Fracture detection Estimate of hydrocarbon in place Estimate of recoverable hydrocarbon Determination of water salinity Reservoir pressure determination Porosity/pore size distribution determination Water flood feasibility Reservoir quality mapping Interzone fluid communication probability Reservoir fluid movement monitoring
Well Log Interpretation: Finding the Hydrocarbon
5.3
The three most important questions to be answered by wellsite interpretation are: 1. Does the formation contain hydrocarbons, and if so at what depth and are they Oil or gas? 2. If so, what is the quantity present? 3. Are the hydrocarbons recoverable?
INTERPRETATION PROCEDURE
5.3.1
The basic logs, which are required for the adequate formation evaluation, are: 1. Permeable zone logs (SP, GR, and Calliper) 2. Resistivity logs (MFSL, Shallow and Deep resistivity logs) 3. Porosity logs (Density, Neutron and Sonic).
The Field Operation
5.3.2
Wireline electrical logging is done from a logging truck, sometimes referred to as a ”mobile laboratory”. The truck carries the downhole measurement instruments into the borehole, the surface instruments into borehole, the surface instrumentation needed to power the downhole instruments and to receive and process their signals, and the equipment needed to make a permanent recording of the “log”.
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Figure 2: A typical CSU Well Site mobile laboratory
Figure 3: Wireline Logging Operation
Figure: Assembling a Logging tool on rig floor
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Basic Logs Tools and their measurements
5.3.3
SP Log record
Also known as Self Potential Log. SP Log record weak electrical currents that flow naturally in the rock next to the wellbore (natural electricity). The log shows the boundaries and thickness of each layer of rock, especially Permeable (sandstone) and Impermeable (shale). Because the SP Log is so simple to obtain and provide such basic information, it is the most common log . Useful for: Detecting permeable beds and it thickness. Locating their boundaries and permitting correlation of such beds. Determining formation water resistivity. Qualitative indication of bed shaliness •
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Calliper Log 1. A representation of the measured diameter o f a borehole along its depth. Caliper logs are usually measured mechanically, with only a few using sonic devices. 2. The tools measure diameter at a specific chord across the well. Since wellbores are usually irregular (rugose), it is important to have a tool that measures diameter at several different locations simultaneously. Such a tool is called a multifinger caliper. 3. Drilling engineers or rigsite personnel use c aliper measurement as a qualitative indication of both the condition of the wellbore and the degree to which the mud system has maintained hole stability. Caliper data are integrated to determine t he volume of the openhole, which is then used in planning cementing operations.
Figure 4: Calliper Log
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Calliper Log
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Resistivity Logs •
•
•
Use to measure the resistivity of the formation, and thus the possibility of hc shows. A sonde sends an electrical signal through the formation and relays it back to a receiver at the surface (induced electricity). The surface detector will measure the formation’s resistance to the current. A rock which contains an oil and/or gas saturation will have a higher resistivity than the same rock completely saturated with formation water. See below.
Figure: Zones of Invasion about a borehole
Induction Logs •
•
•
•
Use to measure the conductivity of the formation, and thus the possibility of the hydrocarbon shows. A rock which contains an oil and/or gas saturation will have a lower conductivity than the same rock completely saturated with formation water. Induction logs use an electric coil in the sonde to generate an alternating current loop in the formation by induction. Induction tools give best results when mud resistivity is high with respect to formation resistivity, i.e., fresh mud or non-conductive fluid . In oil-base mud, which is nonconductive, induction logging is the only option available. 21
Resistivity Log
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Induction log Responses in WATER SAND
Induction log Responses in OIL SANDS
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Induction log Responses in GAS
Nuclear Logs or Radioactivity logs
Just as SP and resistivity logs record natural and induced electrical currents, nuclear logs (also called radioactivity logs) record natural and induced radioactivity. Three type of logs: 1. Gamma Ray Log, 2. Neutron Log and 3. Formation Density Log. •
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Gamma Ray Log •
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•
Record the natural γ-radioactivity of rocks surrounding the borehole. The γ-radiation arises from three elements present in the rocks, isotopes of potassium, uranium and thorium. Useful for defining shale beds because K, U and Th are largely concentrated in association with clay minerals. It is used to define permeable beds when SP log cannot be employed.
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Gamma Ray Log
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Neutron Log •
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•
To obtain a neutron log, a sonde sends atomic particles called neutrons through the formation. When the neutrons collide with hydrogen, the hydrogen slows them down. The response of the devise is primarily a function of the hydrogen nuclei concentration. When the detector records slow neutrons, it means a lot of hydrogen is present – main component of water and hydrocarbon, but not of rocks. Considered as porosity log because hydrogen is mostly present in pore fluids (water, hydrocarbons) the count rate can be converted into apparent porosity.
Formation Density Log •
•
•
This devise measure number of photon then be related to electron density of the formation. Electron density is related to an apparent bulk density which equivalent to formation bulk density. Useable to detect formation lithology.
Neutron-Density log combo
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Neutron Density Log Responses in Shale
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Neutron Density Log Responses in Water S and
Neutron Density Log Responses in Oil Sand
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Neutron Density Log Responses in Gas
Typical Density Neutron Crossplot
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Neutron-Density Crossplot
Sonic or Acoustic Logs
Provide continuous record of the time taken in microsecond/foot by sound wave to travel from the transmitter to the receiver and the sonde. Velocity of sound through a given formation is a function of its lithological and porosity. Dense, low porosity rocks are characterized by high velocity of sound wave and vise-versa for porous and less dense formation. •
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Logging While Drilling •
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5.3.4
One of the major drawbacks of wireline information is that it is received several hours to several weeks after the borehole is drilled. During this time period, the formation can undergo significant alteration, especially in its fluid saturation, effective porosity, and relative perm. LWD allow wireline-type information to be available as near as real-time as possible. Logging While Drilling (LWD) is a technique of conveying well logging tools into the well borehole downhole as part of the bottom hole assembly (BHA).
Some available measurement in LWD technology: Gamma Ray Resistivity Density Neutron Sonic (fairly recent) Formation pressure Formation fluid sampler Borehole caliper (Ultra sonic caliper, and density caliper). •
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Petrophysical Interpretation Qualitative assessment
5.3.5
Assessment of reservoir properties, fluid type form log pattern. Identification of Reservoir or Non-reservoir
Low gamma ray Reservoir rock
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Identification of hydrocarbon or water bearing zone
Identification of oil or gas bearing zone
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Quantitative assessment
Numerical estimation of reservoir properties viz. % of oil, water etc. Estimation of effective porosity & permeability. Estimation of volume of clay fraction. Estimation of hydrocarbon saturation. Determination of the depth and thickness of net pay. Estimation of reserves of hydrocarbon
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Estimation of hydrocarbon saturation
5.3.6
Cannot be measured directly but inferred from determination of WATER SATURATION (Sw) from RESISTIVITY and POROSITY logs.
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Sw – Fraction of pore space occupied by water. Sh – Fraction of pore space occupied by hydrocarbon.
Water saturation estimation
5.3.7
Objective: whether the pores of the formation is completely saturated with formation water or the pore space is partially saturated with oil/gas.
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Determining Formation Water Resistivity (Rw) by the Inverse Archie Method:
5.3.8
Determining a value for formation water resistivity (Rw) from logs may not always provide reliable results; however, in many cases logs provide the only means of determining Rw. Two of the most common methods of determining Rw from logs are the inverse-Archie method and the SP method. Another method of Rw determination is by means of Hingle plot. INVERSE ARCHIE METHOD: Rwa
Where: Rt = resistivity of the uninvaded zone Φ = porosity
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Sw Calculations: Water saturation may now be calculated for those zones that appear to be hydrocarbon bearing. The water saturation equation for clean formations is as follows: Archie's Equation
Where: Sw = water saturation n = saturation exponent a = tortuosity factor. Φ = porosity. m = cementation exponent. Rt = formation resistivity Rw = formation water resistivity
Among the most difficult variables to determine, but o ne which has a tremendous impact upon calculated values of water saturation (Sw). Often best obtained from the customer, but can be obtained from logs under ideal conditions. Other sou rces include measured formation water samples (DST or SFT), produced water samples, or simply local reservoir history. Moveable Hydrocarbon Index (MHI) One way to investigate the moveability of hydrocarbons is to determine water saturation of the flushed zone (Sxo). This is accomplished by substituting into the Archie equation those parameters pertaining to the flushed zone.
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Where: Rmf = resistivity of mud filtrate. Rxo = resistivity of flushed zone. Once flushed zone water saturation (Sxo) is calculated, it may be compared with the value for water saturation of the uninvaded zone (Sw) at the same depth to determine whether or not hydrocarbons were moved from the flushed zone during invasion. If the value for Sxo is much greater than the value for Sw, then hydrocarbons were likely moved during invasion, and the reservoir will produce. An easy way of quantifying this relationship is through the moveable hydrocarbon index (MHI).
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Exercise
5.3.9
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Calculate Sw for Object -1 and 2. (Take Rw = 0.25)
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CEMENT BOND LOG (CBL)
5.4
A cement bond log (CBL) is a type of log that measures the loss of acoustic energy as it passes through casing. A cement bond log documents an evaluation of the integrity of cement work performed on an oil well. In the process of drilling and completing a well, cement is injected through the wellbore and rises up the annulus between the steel casing and the formation. A sonic tool is typically run on wireline by a service company that detects the bond of the cement to the casing and formation via a principle based on resonance. Casing that is not bound has a higher resonant vibration than that which is bound, causing the imparted energy from the sonic signal to be transferred to the formation. In this sense, the amplitude of the waveform received is the basic measurement that is evaluated. Cement bond logs are used to detect the presence or absence of external cement behind casing. Proper cement placement between the well casing and the formation is essential: 1. To support the casing (shear bond) 2. To prevent fluid from leaking to the surface 3. For isolating producing zones from water-bearing zones (hydraulic bond)
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Production logging
5.5
While most types of logs are used to characterize the wellbore, formation, and fluids prior to well completion, a number of logging tools are available to provide information during production operations and beyond. This article discusses the various types of production logs and how they can often be used together to provide crucial information for under standing and resolving problems.
Production Logging is one of a number of cased hole services that includes cement monitoring, corrosion monitoring, monitoring of formation fluid contacts (and saturations), perforating and plug and packer setting. Services performed in dead, overbalanced, conditions can use relatively simple surface pressure control equipment and are often performed using large open hole style logging cables. With a well that has pressure at surface it is normal to use a small logging cable in order to; 1. Minimize the tool weight needed to overcome the well pressure trying to extrude the cable. 2. Minimize the grease injection requirements to seal around a wireline cable. Wells with surface pressure typically have a completion tubing of relatively small internal diameter, ID, compared to the casing size across the reservoir. This reduced ID means that cased hole tool strings for live wells are typically sized at 1-11/16" in order to pass through the smallest nipple in a 2-3/8" tubing. It is usual for cased hole equipment manufacturers to produce a platform of sensors with common power supplies, telemetry (or memory) to cover production logging, saturation logging, and multifinger caliper corrosion logging. Application of production logs
5.5.1
Production logs are used to allocate production on a zone by zone basis and also to diagnose production problems such as leaks or cross flow. These various tasks can be split between those where the target production is into or out of the well and those where the flow never enters the well, typically flow behind pipe. The former is usually easier and more quantitative while the latter is more qualitative. Fundamentals of production logging
5.5.2
Ideally we would like to measure radial inflow rates using a cheap and accurate sensor. Unfortunately no such sensor exists. Alternatively we could measure the axial flow rate in a well at a depths above and below the zone of interest and compute the difference and hence the inflow rate. Unfortunately there is not any practical measurement of axial flow rate beyond some special applications of oxygen activation logs. However it is possible to measure an axial velocity and combine this with an assumed or measured internal diameter to arrive at an axial flow rate. This last approach is most commonly used. Common velocity sensors include; 1. Turbine/Spinner flowmeters. 2. Markers/Tracers such as oxygen activation logs or radioactive iodine trace r logs. 48
3. Heated anemometry
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The Seismic Method (Acquisition)
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Objectives of Seismic Survey To understand geological structure and stratigraphy at depth. In the oil industry - to reduce the risk of drilling dry wells Reserve Accretion Discovery Of New Oil Pools More Oil From Known Fields Enhanced Oil Recovery •
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Types of seismic survey Seismic Refraction survey Seismic Reflection survey
Basic Requirement for Seismic Survey Source for producing seismic wave. Receiver for catching the reflected / refracted wave. Recording system to format & store seismic signal.
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SEISMIC REFLECTION SURVEY 1. Introduction of a seismic pulse into the ground. The method uses a source of energy such as a vibrating plate pressed against the ground or a dynamite charge detonated at a relatively shallow depth or may be air gun in case of marine survey. 2. Pulse spreading outwards as a down going seismic wave front. 3. Reflection at a boundary between dissimilar rock layers. Note that the wave reflects not only from the base of the first layer but from all boundaries between all layers. 4. The pulse travels upwards as a reflected wave front. 5. Recording at a receiver near or on the earth's surface.
Seismic Source Equipment
EXPLOSIVE SOURCES
Lowering of DYNAMITE into drilled hole
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VIBRATORS
Vertical vibrators produce an asymmetric radiation pattern of P-waves and S-waves
Elastic Wave Propagation and Principles
A disturbance is transmitted in a medium from one point to another by particle motion, Le., the particles of the medium vibrate to transmit this energy from one particle to another . The energy Is transferred from the source and through the medium by spherical wave fronts in a homogeneous medium following: HUYGEN’S PRINCIPLE: A point on an advancing wave front in an isotropic, homogeneous medium may be considered as a new source of spherical waves. FERMATS PRINCIPLE: A ray (perpendicular to the wave front) traveling from one point to another travels through a Minimum time path. SNELLS LAW: A wave traversing the boundary from one medium of velocity V1 to another medium of velocity V2 Is refracted.
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Definitions OF 2-D/3-D Seismic TERMS Patch A patch refers to all live receiver stations that record data from a given source point in the 3-D survey. Receiver Line A line (perhaps a road or a cut-line through bush) along which receivers are laid out at regular intervals. The in-line separation of receiver stations (receiver interval, RI) is usually equal to twice the in-line dimension of the CMP bin. Source Line A line (perhaps a road) along which source points (e.g., dynamite or vibrator points) are taken at regular intervals. Scattering Angle Assuming the presence of a point scatterer (diffraction point) at depth, the scattering angle is the angle between the vertical downgoing source-scatterer raypath and the upgoing scatterer-receiver raypath. Source Point Density (sometimes called shot density),SD The number of source points/km2 or source points/mi2 . Super Bin This term (and others like macro bin or maxi bin) applies to a group of neighboring CMP bins. Swath First, and most commonly, a swath equals the width of the area over which source stations are recorded without any cross-line rolls. Second, the term describes a parallel acquisition geometry, rather than an orthogonal geometry, in which there are some stacked lines that have no surface lines associated with them. Template A particular receiver patch into which a number of source points are recorded. Different gather type
(Red denotes shot point position Green denotes receiver position) (Yellow denotes coincidence of shot and receiver position) 53
TYPES OF SEISMIC SURVEY 2-D seismic survey 3-D seismic survey 4- D seismic survey
2D-Seismic Acquisition Setting
3D-Seismic Acquisition Setting
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Seismic Interpretation What is seismic interpretation? • Interpretation is telling the geologic story contained in seismic data. • It is correlating the features we see in seismic data with elements of g eology as we know them.
Polarity and Phase Change
Data phase and polarity critically determine seismic character. Character is more important than amplitude in directly identifying hydrocarbons with seismic data. Once data phase and polarity are determined, hydrocarbon char acter can be predicted, and this is of major importance in analyzing prospectivity in younger sediments.
Polarity Convention American polarity is described as: An increase in impedance yields positive amplitude normally displayed in blue. A decrease in impedance yields negative amplitude normally displayed in red. European (or Australian) polarity is described as the reverse, namely: An incre ase in impedance yields negative amplitude normally displayed in red. A decrease in impedance yields positive amplitude normally displayed in blue.
Resolution
The ability to separate two features that are close together The resolving power of seismic data is always measured in terms of seismic wavelength (λ=V/F) Limit of (resolution) separability = λ/4 The predominant frequency decreases with depth because the higher frequencies in the seismic signal are more quickly attenuated. Wavelength increases with depth. Resolution decreases with depth For thinner intervals amplitude is progressively attenuated until Limit of visibility=λ/25 is reached when reflection signal becomes obscured by the background noise.
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Velocity data Display
Well to seismic tie (Synthetic Seismograms) Synthetic to seismic matching before starting the interpretation helps in understanding geologic elements
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Stratigraphic interpretation
Stratigraphic interpretation is based on the identification and mapping of changes in reflection character and correlating it with analogues. A shape or pattern which is unrelated to structure may be due to depositional, erosional, lithologic or other features of interest. Horizontal sections and horizon slice scan
provide a bird’s-eye-view of ancient stratigraphy Seismic attributes improve the mapping of stratigraphic features which may be “hidden” on normal sections.
Seismic attributes Reflection seismic data helps to recognize and characterize stratigraphic entities in two ways:
•First via seismic responses, •and second via their intrinsic seismic properties •Reflectivity •Velocity • Acoustic impedance Both have limitations so the best approach is to use both of them, if possible. Seismic attributes are important for stratigraphic interpretation and reservoir characterization.
Seismic attributes
• Attributes are derivatives of basic seismic measurements/information – Seismic attributes extract information from seismic data that is otherwise hidden in the data – These information can be used for predicting, c haracterizing, and monitoring hydrocarbon reservoirs • Basic information – Time – Amplitude – Frequency – Attenuation – Phase • Most attributes are derived from normal stacked and migrated data volume can be derived from Prestack data (AVO). Seismic attributes Attribute
Information
1. Time-derived
Structural information
2. Amplitude-derived
Stratigraphic and reservoir
3. Frequency-derived
Stratigraphic and reservoir
4. Attenuation
Permeability (future)
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Seismic attributes (instantaneous) Attribute name Mathematical definition 1. Reflection strength A(t) =√ { f2 (t) + h2 (t) } 2. Instantaneous phase θ (t) = tan-1 { h(t) / f(t) } 3. Instantaneous frequency w (t) = d θ / dt Quadrature Trace h(t) is Hilbert transform of f(t), a 90 degree phase shift of f(t) The basis for all the complex trace attributes is the idea of a complex t race. Complex-trace analysis separates amplitude and phase information. Taner et al. (1979) show that a seismic trace f(t) can be considered as the real part of a complex trace, F (t) = f ( t) + ih(t). The h(t), quadrature or imaginary component is determined from f(t) by Hilbert Transform
Sweetness Sweetness Sr(t) is defined as response amplitude ar(t) divided by the square root of response frequency fr(t), Sweetness is an empirical seismic attribute designed to identify “sweet spots,” places that are oil and gas prone. In young clastic sediments, sweet spots are often characterized seismically by high amplitudes and low frequencies. Sometimes reflection strength and instantaneous frequency are used instead of response amplitude and response frequency. Sweetness closely resembles reflection strength. Sweetness anomalies of most interest are those that are relatively stronger than their corresponding reflection strength anomalies.
Time derived Horizon attributes • Residual – Arithmetic difference between high precision automatically tracked time map and its spatiallysmoothed equivalent. Subtle faults and data collection irregularities • Dip (dip magnitude) – Ms/trace – Provides structural details (faults) – Quality control the performance of horizon tracking proce ss • Azimuth (direction of dip) – Subtle faults • Dip-Azimuth – Combines dip and azimuth attributes onto the one display • Subtle faults • Curvature – Derivative of dip and azimuth • Subtle faults
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Time derived Attributes
Spectral Decomposition Spectral decomposition decomposes the seismic data with normal frequency bandwidth into a set of sections having discrete or very narrow bandwidth. It is based on the concept that reflections from a thin bed have a characteristic expression in a particular frequency domain that is indicative of temporal bed thickness. Very effective in mapping stratigraphic features (Channels)
Acoustic impedance Acoustic impedance is used to produce more accurate and detailed structural and stratigraphic interpretations than can be obtained from seismic (or seismic attribute) interpretation. In many geological environments acoustic impedance has a strong re lationship to petro physical properties such as porosity, lithology, and fluid saturation. Moreover, the acoustic impedance models are more readily understood (versus seismic attributes) because it is layer property unlike the seismic amplitude which is interface property.
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