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Heavy oil article final_AKG 30 Dec 2013

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Heavy oil article final_AKG 30 Dec 2013

  2. 2. 2 A vital but Challenging resource…… EXTRA-HEAVY OILS, THE CHALLENGES OF MAXIMIZING RECOVERY IN ORINOCO BELT-VENEZUELA Heavy Crude oils Heavy crude oil has been defined as any liquid petroleum with an API gravity less than 20°. Physical properties that differ between heavy crude oils and lighter grades include higher viscosity and specific gravity, as well as heavier molecular composition. In 2010 the World Energy Council(WEC) defined extra heavy oil as crude oil and is commonly defined as oil having a gravity of less than 10° and a reservoir viscosity of no more than 10000 centipoises. When reservoir viscosity measurements are not available, extra-heavy oil is considered by the WEC, to have a lower limit of 4° API.(WEC 2007) i.e. with density greater than 1000 kg/m3 or, equivalently, a specific gravity greater than 1 and a reservoir viscosity of no more than 10,000 centipoises. Heavy oils and asphalt are dense non aqueous phase liquids (DNAPLs). They have a "low solubility and are with viscosity and density higher than water."Large spills of DNAPL will quickly penetrate the full depth of the aquifer and accumulate on its bottom." Heavy oil is petroleum that has become extremely viscous as a result of biodegradation: bacteria active at the low temperatures associated with shallow deposits consume the lighter hydrocarbons, leaving behind the more complex compounds such as resins and asphaltenes. At viscosity values up to 10,000 centipoise (cP), the oil is highly viscous but remains mobile in reservoir conditions. This is termed ―extra-heavy‖ oil, and can be recovered using cold production methods. Petroleum with viscosity above 10,000 cP is called bitumen, and is so viscous that it is immobile at reservoir conditions. Mining methods are feasible to extract the
  3. 3. 3 bitumen to a depth of up to 100 metres. For deeper deposits, thermal recovery methods are required to mobilize the oil by heating it. • 2 characteristics by definition: - Gravity: very dense, between 7 and 25° API - Viscosity (reservoir conditions): highly viscous, from 10 up to over 10,000 cP • 3 categories of heavy oil: Categories Definition ‗A‘ Class Gravity < 25° API Heavy oil 10 < Viscosity < 100 cP Mobile ‗B‘ Class Gravity < 20° API Extra-heavy oil 100< Viscosity < 10,000 cP Non-mobile ‗C‘ Class 7 < Gravity < 12° API Oil sands - bitumen Viscosity > 10,000 cP For convenience purposes, in general terms « heavy oils » include categories A+B+C, and « extra-heavy oils » include categories B+C, i.e. extra-heavy oils and oil sands. Resource Background: The Americas, from North to South Some 80% of all heavy oils are extra-heavy (EHCO); these include oil sands, which are highly complicated as well as costly to develop. Although found in all parts of the world (e.g., Russia, USA, Middle East, Africa, Cuba, Mexico, China, Brazil, Madagascar, Europe and Indonesia), the largest accumulations of EHCO in the form of oil are located in Venezuela (the Orinoco Belt) and as Oil Sands at Canada (Province of Alberta). Combined, these two regions represent nearly 3,000 billion barrels of oil-in-place. They also account for 95% of global production of heavy oils (2.2 -2.8 million barrels per day in 2008-2012, two-thirds of which are in Canada and one-third in Venezuela). Although less than 1% of these resources are produced or under active development today, output should nearly quadruple, reaching at least 7 or 8 Mb/d by 2030. Given the considerable resources they represent, extra-heavy crudes and oil sands are a major potential source of supplying world energy demand. While industrial performance is part of the equation, energy intensive production of these heavy oils also presents an important environmental challenge which must be addressed. At the current rate of production, conventional oil reserves are expected to last for fifty years. Heavy oils can supply an additional twenty years‘ worth of production. However, these oils are complex to extract, and there are a number of technical and environmental issues that must be addressed in order to develop them responsibly.
  4. 4. 4 Heavy oils are an essential component of the world‘s future energy mix. The volume of oil-in- place is estimated to be between 4,000 and 5,000 billion barrels (Gb), translating to resources of up to 600 Gb. These figures reflect the enormous potential of heavy oils: they are equivalent to 60% of global reserves of conventional crude oil and account for 20 to 25% of the world‘s petroleum resources (source:EIA) . Reserves for The Future Heavy oils account for approximately 25% of the world‘s petroleum resources, equivalent to approximately 20 additional years' worth of hydrocarbon reserves. These unconventional oils, concentrated mainly in Venezuela and Canada, are becoming an essential component of the energy mix. Growing Energy Needs Proven global reserves of conventional oil amount to one thousand billion barrels – enough for up to 50 years supply at the current rate of production. However, as predicted by the ―peak oil‖ scenario, conventional oil and gas exploration targets are becoming increasingly rare. Indeed, as production from conventional acreage declines at a rate of about 5% per year, global demand is rising at a steady rate of 1 to 1.5% per year, driven especially by China, India and Brazil. In this environment, heavy oils can play an instrumental role in hydrocarbon reserve replacement. As a part of tomorrow‘s energy solution, they can extend the world‘s energy reserves by 20 years.
  5. 5. 5 High Concentrations in Venezuela and Canada Extra-heavy oils and oil sands make up 80% of all heavy oils, and are both complicated and costly to produce and upgrade.
  6. 6. 6 Although found in all parts of the world, the largest extra-heavy oil reserves are concentrated in Venezuela and Canada. More specifically, the two most prolific regions are:  The Orinoco Belt in Venezuela,  The province of Alberta in Canada. Together, these two regions represent a total of nearly 3,000 billion barrels in place – translating to reserves of 440 Gb. That is almost double the reserves of Saudi Arabia (260 Gb), the country with the greatest volume of conventional reserves. Heavy Oil Resources of the Orinoco Oil Belt, Venezuela One of the Largest Recoverable Oil Accumulations in the World The Orinoco Oil Belt Assessment Unit of the La Luna-Quercual Total Petroleum System encompasses approximately 50,000 km2 of the East Venezuela Basin Province that is underlain by more than 1 trillion barrels of heavy oil-in-place. As part of a program directed at estimating the technically recoverable oil and gas resources of priority petroleum basins worldwide, the U.S. Geological Survey estimated the recoverable oil resources of the Orinoco Oil Belt Assessment Unit. This estimate relied mainly on published geologic and engineering data for reservoirs (net oil-saturated sandstone thickness and extent), petrophysical properties (porosity, water saturation, and formation volume factors), recovery factors determined by pilot projects, and estimates of volumes of oil-in-place. The U.S. Geological Survey estimated a mean volume of 513 billion barrels of technically recoverable heavy oil in the Orinoco Oil Belt Assessment Unit of the East Venezuela Basin Province; the range is 380 to 652 billion barrels. The Orinoco Oil Belt Assessment Unit thus contains one of the largest recoverable oil accumulations in the world. Reserves comparison of major Oil Producers Source:BP Stats One Trillion Barrels of Heavy Oil
  7. 7. 7 The Orinoco Oil Belt Assessment Unit (AU) of the La Luna-Quercual Total Petroleum System encompasses approximately 50,000 km2 of the East Venezuela Basin Province that is underlain by more than 1 trillion barrels of heavy oil-in-place (fig. 1). As part of a program directed at estimating the technically recoverable oil and gas resources of priority petroleum basins worldwide, the U.S. Geological Survey (USGS) estimated the recoverable oil resources of the Orinoco Oil Belt AU. This estimate relied mainly on published geologic and engineering data for reservoirs (net oil-saturated sandstone thickness and extent), petrophysical properties (porosity, water saturation, and formation volume factors), recovery factors determined by pilot projects, and estimates of volumes of oil-in-place. Figure 1. Map showing the location of the Orinoco Oil Belt Assessment Unit (blue line); the La Luna-Quercual Total Petroleum System and East Venezuela Basin Province boundaries are coincident (red line). USGS image The East Venezuela Basin The East Venezuela Basin is a foreland basin south of a fold belt (fig. 2). The progressive west-to-east collision of the Caribbean plate with the passive margin of northern South America in the Paleogene and Neogene formed a thrust belt and foreland basin that together
  8. 8. 8 composes the East Venezuela Basin Province. Thrust faults associated with the fold belt caused lithospheric loading and basin formation, and the resulting burial placed Cretaceous and possibly older petroleum source rocks into the thermal window for the generation of oil. The oil migrated up dip from the deeper basin to the shallow southern basin platform, forming the Orinoco Oil Belt. The oil is considered to be concentrated along a fore bulge that formed south of the foreland basin. Figure 2. Schematic structural cross section of the East Venezuela Basin showing the updip position of the Orinoco Oil Belt relative to the deeper part of the East Venezuela Basin. Oil generated from thermally mature Cretaceous and possibly older source rocks in the deeper part of the basin migrated updip to form the accumulation in the Orinoco Oil Belt (after Jacome and others, 2003). USGS image The Miocene Oficina Formation The heavy oil in the Orinoco Oil Belt AU is largely contained within fluvial, near shore marine, and tidal sandstone reservoirs of the Miocene Oficina Formation. The reservoir sandstones, although porous and permeable, are characterized by several depositional sequences with considerable internal fluid-flow heterogeneity caused by juxtaposition of different facies and by shale barriers that reduce recovery efficiency. Sandstone reservoirs range in depth from 150 to 1,400 meters, and they contain heavy oil with a range of gravities from 4 to 16 degrees API. Viscosities are generally low, ranging from 2,000 to 8,000 centipoises. Oil Resource Assessment Methods In addition to the standard USGS methodology for assessing continuous oil accumulations such as those in the Orinoco Oil Belt, we used reservoir data, petrophysical data, oil-in-place estimates, and recovery factors taken from studies of the Orinoco Oil Belt to develop five other approaches for estimating recoverable resources and to adequately represent the geologic and engineering uncertainty in the assessment. Key data used in the assessment are summarized in table 2. The estimates of volumes of recoverable oil and associated gas reported here reflect the distribution of mean estimates obtained by the six methodologies applied to the Orinoco Oil Belt AU (table 3).
  9. 9. 9 Table 1:Faja Orinico Belt Data (source:Petroleum Society) Geology Units FAJA OOIP developed 10 6 bbls 100000+ Depth m. 450-650 BHSP MPa 4.5-6.5 BHST C 60 Avg. Porosity % 31% Sw % 14% Permeability D 5-15 Thickness of each sand body ft 20-80 k.h/ ft.md/cp 40 -1000 Fluids 0 API 8—10 Viscosity @ Pr and Tr cP 1000-5000 Rs Scf /bbl 50-80 Production rates Spacing vertical wells Mt ? Vertical wells conventional rates bopd/sand 20-250 Wells rates bopd 1000-2000 (Horzn) Recovery Primary recovery factor % 8-12 (Horzn) Ultimate % ? Minimum Median Maximum Orinoco oil-in-place (BBO) 900 1,300 1,400 Recovery factor (%) 15 45 70 Net oil-saturated sandstone thickness (ft) 1 150 350 Porosity (%) 20 25 38 Water saturation (%) 10 20 25 Formation volume factor 1.05 1.06 1.08 Gas/oil ratio (scf/bbl) 80 110 600 Table 2. Key input data for assessment of Orinoco Oil Belt Assessment Unit. Oil (BBO) F95 F50 F5 Mean 380 512 652 513 Gas (TCFG) F95 F50 F5 Mean 53 122 262 135 NGL (BBNGL) F95 F50 F5 Mean 0 0 0 0 Table 3. Orinoco Oil Belt Assessment Unit assessment results. [BBO, billion barrels of oil; TCFG, trillion cubic feet of gas; NGL, natural gas liquids; BBNGL, billion barrels natural gas liquids. Results shown are fully risked estimates. F95 represents a 95 percent chance of at least the amount tabulated. Other fractiles are defined similarly]
  10. 10. 10 Permeabilities and kh/α Values The Venezuelan reservoirs range from 2 to 15 Darcy in permeability based on back- calculations from tests on wells in the northern part of the Faja,, and most of the Heavy Oil Belt reservoirs are from 1 to 3 Darcy average permeability. Samples of Faja sand that were medium grained (D50 ~ 250αm) and quite free of clay gave permeability values of less than 10 D. Venezuelan reservoirs in the Faja del Orinoco are of substantially higher quality than Canadian heavy oil reservoirs: they have higher permeability, slightly higher porosity and oil saturation, slightly higher formation compressibility, higher average gas contents, lower clay content.The mobility of the oil in the Venezuelan deposits appears to be from 2 to 3 times more than in the Canadian heavy oil deposits. The individual beds in the Venezuelan reservoirs of the Faja del Orinoco have productivity potentials that are on the order of several times to ten times those in Canada. In units of ft-mD/cP (commonly used in Venezuela), Canadian Heavy Oil Belt reservoirs typically have values of 14-140, whereas the beds in the Faja have values on the order of 40-1000. Clearly, the production potential of the Faja reservoirs is far greater than the Canadian reservoirs. It is anticipated that there is an active foamy oil drive mechanism in these Faja wells, and that this provides an additional component of well productivity. These effects include the presence of a strongly negative skin zone developing because of some sand production, and the consequences of a strong foamy drive because of the dissolved gas. Rising Production Venezuela and Canada together account for 95% of the global output of extra-heavy oils and oil sands (2.2 -2.8 million barrels per day in 2008-2012, two-thirds of which are in Canada and one-third in Venezuela; Source: U.S E.I.A). Although less than 1% of these resources are produced or under active development today, output should nearly quadruple, reaching at least 7 or 8 Mb/d by 2030. The increasing prevalence of extra-heavy oils in the global energy mix is inevitable. It also presents significant challenges. Limiting Environmental Impacts The processes involved in extracting and up- grading these oils requires huge quantities of energy and water. For this reason, developing them sustainably on a large scale poses major economic, environmental and technological challenges. Improvements focus on driving down technical costs; enhancing recovery factors and energy efficiency; curbing CO2 emissions and limiting water consumption and the footprint of these huge developments. There is no question that the complexity of these challenges is of another order of magnitude compared to conventional oil developments. Backed by Engineering and Research & Development of technological front can steer the skills and innovative capacities to develop these promising resources responsibly. Exploration and production Energy Information Administration (EIA),U.S estimates that the Venezuela produced around 2.47 million bbl/d of oil in 2011. Crude oil represented 2.24 million bbl/d of this total, with condensates and natural gas liquids (NGLs) accounting for the remaining production. Estimates of Venezuelan production vary from source to source, partly due to measurement methodology.
  11. 11. 11 For instance, some analysts directly count the extra-heavy oil produced in Venezuela's Orinoco Belt as part of Venezuela's crude oil production. Others (including EIA) count it as upgraded syncrude, whose volume is about 10 percent lower than that of the original extra-heavy feedstock. Venezuela's conventional crude oil is heavy and sour by international standards. As a result, much of Venezuela's oil production must go to specialized domestic and international refineries. The country's most prolific production area is the Maracaibo basin, which contains slightly less than half of Venezuela's oil production. Many of Venezuela's fields are very mature, requiring heavy investment to maintain current capacity. Industry analyst estimate that PdVSA must spend some $3 billion each year just to maintain production levels at existing fields, given decline rates of at least 25 percent. Orinoco heavy oil belt Venezuela contains billions of barrels in extra-heavy crude oil and bitumen deposits, most of which are situated in the Orinoco Belt in central Venezuela. According to a study released by the U.S. Geological Survey, the mean estimate of recoverable oil resources from the Orinoco Belt is 513 billion barrels of crude oil. PdVSA began the 'Magna Reserva' project in 2005, which involved dividing the Orinoco region into four areas and further divided into 28 blocks and quantifying the reserves in place. This initiative resulted in the upgrading of Venezuelan reserve estimates by more than 100 billion barrels. Following figures depict the facts: Production Comparison of Oil major countries
  12. 12. 12 “Venezuela has one of the highest Reserves-to-Production (R/P) ratios making it one of the most sought after countries for E&P activities”……. Venezuela plans to develop further the Orinoco Belt oil resources in the coming years. In 2009 Venezuela signed bilateral agreements for the development of four major blocks in the Junin area. Last year the country awarded two more major development licenses in the Carabobo region. The Carabobo Area is located within the onshore Orinoco Belt of Eastern Venezuela. The Orinoco Belt covers a huge area of approximately 55,000 km2 and is reported to contain over 1 trillion barrels of extra heavy (7.5 to 8.5 0API) crude oil in place with an estimated 235 billion barrels recoverable. Carabobo belt is considered to be one of the most prolific areas in the belt with certified reserves of 32 billion barrels. The Carabobo area is currently producing 362,000 barrels per day. Within the Carabobo Area, there are 5 undeveloped blocks referred to as Carabobo 1 through 5 and three developed blocks called Petromonagas, Cerro Negro and Petro Sinovensa. Venezuela expects these projects to add more than 2,000,000 bbl/d of heavy oil production capacity by the end of the decade (see table).Blocks in Ayacucho & Boyaca in Faja Orinoco Belt are also in the offing for production of EHCO. Venezuelan projects are being developed by long horizontal wells with multilaterals, placed in the optimum zones (highest kh/α). This is feasible because of the excellent reservoir conditions and because it is now technically possible to place wells in the best zones for their entire length. Such wells are expected to produce as much as 2000 bbl/d initially, and should keep producing for many years, expected to gradually decline to in 5-7 years. Operating expenses for these wells are less but the great majority of the costs are in the development of the wells, surface facilities and transportation, and upgrading of the viscous oil. However, on average only 40-65% (depending on the site) of the oil-bearing strata in the Faja are suitable for development using this technique. Other beds are too thin, have too low kh/α values, have unfavorable kv/kh ratios because of clay laminations. Existing and Under Development Orinoco Belt projects Grouping Project Projected start up date Planned production of EHCO(bbl/D) Partners ACTIVE PROJECTS Petroanzoategui (Petrozuata) 1998 107,000 PdVSA(100%) Petromonagas 1999 104,730 PdVSA (83.34%),BP* (16.66%)
  13. 13. 13 (Cerro Negro) Petrocedeno (Sincor) 2000 144,000 PdVSA (60%), Total (30.3%), Statoil (9.7%) Petropiar (Hamaca) 2001 131,100 PdVSA (70%), Chevron (30%) U N D E R D E V L M T Petromarcarco 2012 200,000 PDVSA (60%),Petro-Vietnam(40%) PetroSinovensa 2012 400,000 PDVSA (60%), CNPC (40%) Petrojunin 2013 240,000 PDVSA (60%), ENI (40%) Petromiranda 2014 450,000 PDVSA (60%),Russian Comp (40%) PetroCarabobo-1 2013 400,000 PDVSA (60%), Indian Comp (18%), Petronas(11%)**,Repsol YPF (11%) Petroindependencia Carabobo-3 2013 400,000 PDVSA (60%), Chevron(34%), Japanese Consortium (5%), Suelopetrol (1%) Petrobicentanario 2022 350,000 PDVSA (60%), ENI (40%) OVL & RELIANCE of India have signed MoU/intent in Oct 2013 to acquire more blocks in Ayacucho 3 & 8 respectively. *BP sold shares to TNK-BP **Petronas had quit the project in July 2013; Sources: PdVSA, Global Insight, Wood Mackenzie Heavy/Extra Heavy Oil Production Methodology: Usually in the field technology of production of Heavy/Extra heavy oil following processes are adopted depending upon crude characteristics and depth of field/mines for oil sand (bitumen),they are:  CHOPS:Cold Heavy Oil Production with Sands  CSS :Cyclic Steam Stimulation  SAGD :Steam Assisted Gravity Drainage  THAI :Toe to Heel Air Injection  VAPEX :Vapor Extraction
  14. 14. 14 RECOVERY PROCESSES NON-THERMALPRIMARY THERMAL COLD PRODUCTION CHOPS STEAM BASED CSS FLOODING SAGD COMBUSTION FIRE-FLOODING THAI WATER FLOODING CHEMICAL FLOODING VAPEX Steam Based Thermal Recovery Processes are most extensively used CHOPS:Cold Heavy Oil Production with Sands CSS:Cyclic Steam Stimulation SAGD:Steam Assisted Gravity Drainage THAI:Toe to Heel Air Injection VAPEX:Vapor Extraction HEAVY OIL RECOVERY PROCESSES DILUENT SUPPLY FOR PRIMARY Source: www.HeavyOilinfo.com
  15. 15. 15  Single well operation • Injection/production cycle: - Steam injection -Shut-in (soak)- Oil production • Recovery factor (RF) ~15% OOIP (original oil-in- Place) CYCLIC STEAM STIMULATION (CSS) Source: www.HeavyOilinfo.com
  16. 16. 16  Multi-well operation in regular pattern • Inject steam into one or more wells • Drive oil to separate producers • Recovery factor (RF)~ 50% OOIP STEAM FLOODING Source: www.HeavyOilinfo.com Steam Assisted Gravity Drainage (SAGD)  Horizontal well pair near bottom of pay of - Upper steam injector - Lower oil producer • Steam chamber rises upward,then, spreads sideway • Oil drains downward to drains of producer • Recovery factor (RF) > 50% OOIP Source: www.HeavyOilinfo.com
  17. 17. 17 Steam- Based Thermal Recovery Processes Very energy intensive and inefficient Thermal Efficiency for Each Stage: Steam Generator (75-85%) Well to Reservoir (80-95%) Flow in Reservoir (25-75%) Final Efficiency: 11-58%  Significant environmental impacts - Land: Surface footprint - Air : Greenhouse gas (GHG) emission - Water: Water usage and disposal Source: Butler, "GravDrain's Blackbook", (1998) Green House Gas Emission GHG emission from steam generation at 250°C - Burning natural gas (CO2 emission = 0.532 tonne/Mscf) 0 20 60 100 160 CO2 Emission(Kg)/Oil Recovery(bbl) 158.1 131.8 105.4 79.1 52.7 26.4 CSS & Steamflooding SAGD 1 2 3 4 5 6 Steam-Oil Ratio(SOR) Reduced GHG Emission Improved SOR Environmental Canada Data Source: www.HeavyOilinfo.com Transmission to Well (75-95%) Steam Generator (75-85%)
  18. 18. 18 CHOPS is attractive for the lower permeability and finer-grained zones that generally make up from 20 to 60% of the sequence of oil-saturated beds in the sequence of stacked Faja reservoirs. SAGD (and VAPEX) use horizontal wells, and the current Faja exploitation method involves 1500 m long mother wells, developed with a slotted liner. There are two options: Drill a vertically offset well (above or below the mother well) within 5 m and use double-well SAGD, or attempt to initiate single-well SAGD. It is believed that the latter is an attractive option to attempt first, and is likely to succeed if properly implemented. DEVELOPING PROJECTS AT CARABOBO In the Orinoco Oil Belt, situated in the central area of Venezuela in the states of Monagas, Anzoátegui and Guárico, the Carabobo area is located on the east side of the Orinoco Oil Belt. Carabobo is one of four production areas in the belt and is in the early stages of development. The other three areas are Junín, Boyacá, and Ayacucho. The Carabobo area covers approximately 1,200 square kilometers and extends through the States of Anzoátegui and Monagas. 6 2 1 3 5 4 6 5 4 3 2 1 0 Water Usage & Disposal Water usage for steam generation Water Usage (bbl) / Oil Recovery (bbl) CSS & Steamflooding SAGD Reduced Water Usage Steam-Oil Ratio(SOR) Improved SOR 1 2 3 4 5 6 Source: www.HeavyOilinfo.com
  19. 19. 19 Carabobo1 Project, Petrocarabobo comprises the Carabobo1 North and Carabobo1 Central Blocks; Petroindependencia the other project is comprised of three blocks: 5, 2S and 3N located in the Eastern region of Petroliferous Faja of the Orinoco. The Petroindependencia production facilities will be located to the south of the Petrocarabobo, Petromonagas, and Petro Sinovensa facilities and north of the Orinoco River. The Upgrader will be located at Falconero and the export terminal at Araya. These twin projects are being developed in identical fashion and just the mirror image with projected plateau production of 400,000 bopd. SPECIFICATIONS OF PRODUCT STREAMS: AREA CARABOBO 1.Extra Heavy Crude Oil (EHCO) Specification: PROPERTIES EHCO(Note1) TYPICAL(Note2) UNITS API Gravity 8.5 +/- 1o 0 API Specific Gravity @ 60°F 1.0064 Molecular Weight UOP K Factor 11.33 Kinematic Viscosity @ 100°F 73,000 cST Kinematic Viscosity @ 120°F 19,000 cST Sulfur 3.9 Wt% Mercaptans 25 ppmw Basic Sediment and Water BS&W 1.0% (max) 9 Vol % Salt Content as NaCl 17,200 ppmw Inorganic Chlorides ppmw Nickel 79 ppmw Aluminum ppmw Vanadium 434 ppmw Iron ppmw Nitrogen 6420 ppmw Sodium ppmw H2S ppmw Acid Number 3.12 mg KOH/g Back Blended Acid 2.06 mg KOH/g Asphaltenes (C7) 13.3 %wt Paraffin's Content %wt Conradson Carbon Residue 18.5 %wt Reid Vapor Pressure psi Flash Point o F Pour Point 84.1 o F Source: Notes: 1. Chevron Hamaca EHCO analysis. Viscosity per PDVSA Reservoir Fluids Study Cerro Negro CH-26 & PVTs. 2. Schlumberger Fluid Analysis Well Head Sample Well CIS-1-0 Morichal Zone 0-12 for Sinovensa
  20. 20. 20 The Diluted Crude Oil (DCO),17°API is obtained by the mixture of 200,000 BOPD of Extra Heavy Crude Oil with Mesa-28/30 or Naphtha Diluent of 47° API during Early Production stage as per Master Development Plan of field. DCO must meet the specifications shown below: Diluted Crude Oil (DCO) Properties of Early Production: PROPERTIES DCO DCO Diluent Mesa 28/30 Naphtha DCO Gravity, 0 API Sp.Gavity@ 60 0 F 16.0 0.9604 17.3 0.951 Diluent Gravity, 0 API Diluent Flow,MBPD 28/30 51 47 84 XHO Flow,MBPD 50 200 Kinematic Viscicity@104 0 F,cST 125(187) 298 Kinematic Viscicity@122 0 F,cST 73(103) 147 Kinematic Viscicity@210 0 F,cST 30 21 Diluted Crude Oil Specification: PROPERTIES VALUE 0 API Gravity, at 15 0 C 17 Molecular Weight 467 Density at 161 0 C, Kg/m 3 852 Viscosity at 161 0 C,cST 3.2 Viscosity at 100 0 C,cST 12.9 Sulfur,%wt 3.25 Nitrogen,wt ppm 5364 BSW, vol% 2% Flash Point, 0 F 78 Pour Point, 0 F 10 Nickel,ppm 62 Vanadium,ppm 280 Asphaltene(C7),wt% 8.6
  21. 21. 21 3. UPGRADED CRUDE OIL (UCO):SYN Crude Specification: UPGRADED CRUDE OIL PROPERTIES: UCO (SYN Crude) produced in the Upgrader must meet the properties given in the following table: PROPERTIES VALUE UNITS Gravity 32-34 0 API Sp. Gravity@60oF 0.864-0.853 Molecular Weight 207 RVP ≤ 0.5 BAR A TOTAL SULFUR ≤740/0.07% Wt ppm/ wt/wt H2S ≤ 1 Wt ppm Source: MPC-460-FP147001 Basis of Design Tank Farm-Unit 60. Rev. E Note : Values at normal operation Properties Value Normal Operation NHDT Unit Upset DHDT Unit Shut-Down MHT Unit Shut-Down Flow rate t/h 986.118 493.490 992.770 1001.078 Gravity 0 API 32.0 32.0 29.5 27.7 Sulphur wt% <0.1 <0.1 <1.3 <1.6 Bromine Number <0.2 <0.2 <5.1 <1.3 Viscosity @ 38°C cSt 6.41 6.49 7.44 8.63 Viscosity @ 100°C cSt 1.66 1.68 1.79 2.37 RVP bara <0.5 <0.50 <0.5 <0.5 Total nitrogen wt ppm <401 <393 <1097 <2045 Water (H2O) Vol% <0.5 <0.5 <0.5 <0.5 Aromatics Wt% 37.49 37.41 41.69 48.78 H2S wt ppm <1 <1 <1 <1 C1 wt% 0 0 0 0 C2 wt% 0.005 .005 0.005 0.005 C3 wt% 0.409 0.315 0.375 0.361 C4 wt% 1.362 1.194 1.247 1.203 C5+ wt% 97.732 97.997 98.186 98.131 NHDT:Naphtha Hydrotreater,DHDT: Heavy Distillate Hydrotreater,MHT:Middle distillate Hydrotreater Source: MPC-200-FPC01001 Basic and FEED Petrocarabobo Upgrader Falconero, Anzoategui State, Venezuela. General Project Information Process Databook Axens Rev 2
  22. 22. 22 A DEVELOPMENTAL CASE: Pushing The Envelope of Cold Recovery Technology: PETROCEDENO PROJECT---TOTAL (47%), PDVSA(38%),STAT-OIL(15%) It was in Venezuela that TOTAL first tackled the challenge of extracting extra-heavy oils on a very large scale using "conventional" production techniques. With the Petrocedeño (formerly Sincor) project, the Group is showcasing its integrated expertise – spanning downhole technologies, surface facilities and everything in between. This project sets a global benchmark for the cold recovery of extra-heavy oil. The Dimensions of a Venezuelan Challenge December 2000 marked the start of production on Sincor, the huge extra-heavy oil development in Venezuela. As the most ambitious venture in the Orinoco Belt, the project has become a global benchmark for the cold recovery of these unconventional oils. For Total, as operator of Sincor (renamed Petrocedeño in 2008 upon its nationalization), this was the first experience with large-scale production of extra-heavy oils. The Group‘s strategy was to optimize the envelope of "existing" cold recovery technologies. This feat could not have been achieved without drawing on the full range of cutting-edge expertise from the Exploration & Production segment, from the bottom of the reservoir to the surface facilities. And the challenges were enormous indeed: extraction by natural depletion of oil with a viscosity in place of 1,500 to 4,000 cP, from a shallow reservoir, meaning low initial pressure (40 to 45 bar), in addition to a low reservoir temperature (about 50° C).
  23. 23. 23 Mastering Complex Geology The Miocene La Oficina formation in the Orinoco Belt is a complex and heterogeneous environment. Its reservoirs of unconsolidated sand were formed by the deposition of fluvial and marine sediments with different petrophysical characteristics. Zones of relatively fine sand are juxtaposed irregularly with shale barriers. Some sections of the reservoir are fractured. There were huge technological challenges involved in developing such reservoirs using a strategy of intensive horizontal drilling. Advanced technologies (including high-resolution 3D seismic, integrated management of vast amounts of data yielded by core analyses, logs, and well tests) benefited from the close integration of geoscientific expertise to keep geologic uncertainties to a minimum. Understanding the recovery mechanisms at play in the reservoirs helps reduce uncertainties. Meanwhile, studying the recovery mechanisms at play in these reservoirs has helped to enhance the reliability of recovery factor predictions. Total relies on the state-of-the-art instruments of its geology, petrophysics and rock mechanics laboratories to perform these investigations. TECHNOLOGY FOCUS: FOAMING OILS As reservoir pressure declines with production, the gas initially dissolved in the oil comes out of solution. In the case of extra-heavy oils, the viscosity of the oil prevents the liberated gas from migrating to the top of the reservoir. Instead, it remains trapped in the oil in the form of minuscule bubbles (size of the order of a micron). Foaming oil is the result of this intimate mixture of oil and gas, and it facilitates recovery. A STRING OF TECHNOLOGICAL FIRSTS The economically viable production of the extra-heavy oils of the Petrocedeño project was made possible by the deployment of numerous technological innovations.
  24. 24. 24  Drilling trajectories of 1,400-metre-long horizontal drains were optimized in real time by using a satellite link between the drilling rigs and the offices in Caracas – a first in Venezuela. Tracking the progress of well trajectories in real time on 3D seismic images improved the positioning of the drains along the sand layers, which were sometimes of very limited thickness.  Diluent injections into the bottom of the drain, another first, significantly decreased head loss along the drains, translating to higher well productivity.  Petrocedeño advanced the use of Progressive Cavity Pumps (PCPs) in the Orinoco Belt. In Venezuela, Total decided to use PCPs, a technology initially reserved for the production of Canadian oil sands, rather than the more conventional Electrical Submersible Pumps (ESPs), to ensure better control during the start-up of the wells.  Total made Petrocedeño the leading user of Multi-Phase Pumps (MPPs) to stimulate the flow of crude at the wellhead. In addition to the savings on surface equipment, this option affords the advantage of adapting to variations in the flow, temperature and pressure of the production over the life of the field.  Innovative monitoring was developed to optimize production management over the long term. Head loss sensors were installed along the drains, which are also fitted with fiber-optic detection and control of water ingress.  Understanding the recovery mechanisms at play in the reservoirs helps reduce uncertainties PRODUCTION SYSTEM-ARTIFICIAL LIFT: PROGRESSIVE CAVITY PUMPS (PCP)-Applications Heavy oil and bitumen applications are commonly defined in the industry as those producing oil with an API gravity less than 20°. These conditions are common in Canada, Russia, Venezuela and China. Problems associated with heavy oil and bitumen are high viscosity, high flow losses, low to moderate flow rates, high sand cuts and rod string/tubing wear. Directional and horizontal wells are often used to ensure viable development of the reservoir. PC pumps are attractive in these conditions due to their ability to handle viscous, abrasive, multiphase fluids Progressing cavity pumps are positive displacement pumps which consist of a helical steel rotor and a synthetic elastomer stator that is bonded to a steel tube. Rotation of the rotor within the fixed stator causes a series of sealed cavities to form and move axially from the pump suction to discharge. The resulting pumping action increases the pressure of fluid passing through the pump so that it can be produced to surface. Numerous papers describing PC pump principles and theory have been presented elsewhere. Most PC pumping systems are rod driven with the stator run into
  25. 25. 25 the well on the bottom of the production tubing and the rotor connected to the bottom of the rod string. Advantages & Disadvantages PC pumping systems have some unique characteristics that make them advantageous when compared to other artificial lift systems. One of the most important characteristics is their high efficiencies of 55 to 75%. Some additional advantages of PC pumping systems include:  Ability to produce high viscosity fluids  Ability to produce large concentrations of sand  Ability to tolerate high percentages of free gas  No valves or reciprocating parts to clog, gas lock or wear  Good resistance to abrasion  Low internal shear rates (limits fluid emulsification)  Low capital and operating costs PC pumping systems also have several disadvantages. The most prominent of these are limitations with respect to pump capacity, lift and elastomer compatibility with high aromatic fluids. Some additional disadvantages of PC pumping systems include:  Limited production rates (max 500 m3/day or 3150 bbls/day)  Limited lift (maximum of 3000 m or 9840 ft.)  Limited temperature capability (maximum of 180°C or 350°F)  Sensitivity to fluid environment  Low volumetric efficiency when producing large amounts of gas  Rod/tubing wear in some directional and horizontal wells  Low capital and operating costs These limitations are rapidly being overcome with the development of new products and improvements in materials and equipment design. New Developments Metal-to-Metal Pumps Metal stators were considered years ago, but only recently have newer manufacturing techniques and the application of metal-to-metal PCPs in thermal heavy oil and bitumen recovery applications, such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS), brought this technology to the forefront. A metal stator does not have many of the shortcomings of elastomeric stators--specifically fluid interactions and temperature limitations. Metal stators may therefore be used in thermal applications (e.g. 160-350 0 C), or applications with highly reactive fluids. Potential problems which are actively being resolved by metal-to-metal PCP vendors include vibration and seal ability with low viscosity fluids, the
  26. 26. 26 latter due to the fact that metal-to-metal PCPs have a gap between the rotor and stator and not an interference fit, as normally exists with an elastomeric stator. Source:SPE(Joslyn Field,McMurray,Canada) High Temperature Elastomers One of the major limitations of elastomeric stators is the temperature. At high temperatures and over time, most elastomers, including the nitriles typically used in PCPs, become hard and brittle and may not form a seal with the rotor. In these conditions, pumps can fail very quickly. High temperatures can be caused by the external conditions in the well (from depth, or from thermal operations), or from internal friction between the rotor and stator in the absence of sufficient cooling. Fluorocarbon elastomers can operate at higher temperatures than nitriles, but at the cost of inferior mechanical properties. Research is ongoing into ways of improving elastomer formulations for PC pumps so that continued operation at higher temperatures is possible. Fluidizing Sand PC pumps are capable of producing large quantities of sand, when the sand flows into the well on a continuous basis. Sand is known to enter the wellbore in slugs, however, and these slugs can overwhelm the pumps' capabilities of producing solids, particularly in applications where sand control is not employed (eg. in producing viscous heavy oil from unconsolidated sandstone reservoirs). Various methods of "fluidizing" sand to ensure that it can be produced through the pump have been used, and others are in development. Some methods are: the addition of a "paddle" rotor extending below the intake to continually agitate the fluid entering HORIZONTAL WELL COMPLETION OF WORLD’S 1st . (METAL TO METAL) PROGRESSIVE CAVITY PUMPS FOR SAGD PROCESS AT JOSLYN FIELD
  27. 27. 27 the pump; a hollow rotor feeding a small portion of produced fluid from the pump discharge to a jet located at the intake; and a fluidizer pump, where a large displacement-low pressure pump is installed below the main pump with holes in the tubing joint between the two so that an excess amount of fluid continually circulates in the annulus of the well and through the pump intake. High Speed Pumps Currently most PCPs are run at speeds below 500 RPM - with viscous oils, the limit is normally even much lower. To produce larger volumes without exceeding these speed limits, higher displacement pumps are needed. Higher displacement pumps are larger in diameter and/or length, have higher torque requirements, and normally result in increased axial load in the rod string. Being able to run smaller pumps at higher speeds (i.e. in excess of 500 RPM) reduces these loading effects, and also opens up "insert able" pumps (where the rotor and stator are run together on the rod string) to a larger range of applications. Failure Analysis Failure analysis is often defined as the process of collecting and analyzing data to determine the cause of a failure and how to prevent it from recurring .For PCP systems, failure analysis is the process of identifying the root cause of a PCP system failure and using the results to identify strategies to increase the PCP system run-life. A PCP system has failed if any of its components are no longer able to perform the required function. The failure cause is defined as the circumstances during design, manufacturing or use which led to a failure. Failure analysis is among the most important means of improving the performance of a PCP system. There are three main areas of failure analysis:  failure identification, root causes analysis and selection of remedial actions,  failure tracking and benchmarking.  Failure Description and Identification  It is important that failures are described and classified in a consistent manner so that similar failures can be properly grouped and analyzed.  Stator Failures (Fatigue, Wear, Fluid Incompatibility, ...)  Rotor Failures (Wear, Heat Cracking, Fatigue ...)  Rod String Failure Mechanisms (Fatigue, Excessive Torque...)  Tubing String Failures (Wear, Corrosion)  Failure Symptoms, Root Causes and Remedial Actions The main process of a failure analysis is to identify symptoms of a failure (no fluid flow, high torque) that could indicate a system failure. Once a system failure has been identified, it is
  28. 28. 28 important to understand what caused the failure. By asking the question 'why' multiple times, the root cause of the failure can be identified. Only by understanding the root cause can successful remedial actions be taken to prevent a similar system failure from recurring.  Failure Tracking and Benchmarking The goal of benchmarking is to improve system performance and to reduce costs. Benchmarking is a continuous process of measuring and evaluating progress over time to ensure decisions are made based on facts rather than opinion. Failure tracking is used to compile and store data upon which benchmarking can be performed. Failure tracking ensures the collection of quality data that reflects the system as a whole. REFERENCES: 1.Society of Petroleum Engineers 2.U.S Energy Information Administration 3.Oil & Gas Journal 4. PdVSA, Global Insight, Wood Mackenzie 5.Petroleum Society, Canadian Institute of mining, metallurgy & Petroleum 6.U.S Geological Survey(U.S.G.S) 7.Latin America News Digest 8.PdVSA 9. TOTAL 10.World Oil 11. Worldwide Projects 12. Wood MacKenzi 13.Heavy Oil Wikipedia 14.Chevron/Schlumberger/Baker Huges .