Proven, probable and possible reserves are the three most common categories of reserves used in the oil industry. They are intended to represent the probability that a reserve exists based on the geologic and engineering data and interpretation for a given location, though many governments refuse to disclose verifying data to support their claims.
Proven Reserves - defined as oil and gas "Reasonably Certain" to be producible using current technology at current prices, with current commercial terms and government consent, also known in the industry as 1P. Some industry specialists refer to this as P90, i.e., ideally having a 90% certainty of being produced. Proven reserves are further subdivided into "Proven Developed" (PD) and "Proven Undeveloped" (PUD). PD reserves are reserves that can be produced with existing wells and perforations, or from additional reservoirs where minimal additional investment (operating expense) is required. PUD reserves require additional capital investment (drilling new wells, installing gas compression, etc.) to bring the oil and gas to the surface.
Probable Reserves - defined as oil and gas "Reasonably Probable" of being produced using current or likely technology at current prices, with current commercial terms and government consent. Some Industry specialists refer to this as P50, i.e., ideally having a 50% certainty of being produced. This is also known in the industry as 2P or Proven plus probable.
Possible Reserves - i.e., "having a chance of being developed under favourable circumstances". Some industry specialists refer to this as P10, i.e., ideally having a 10% certainty of being produced in the foreseeable future. This is also known in the industry as 3P or Proven plus probable plus possible.
Tuesday, March 4, 2008
Oil reserves
Oil reserves refer to portions of oil in place that are claimed to be recoverable under current economic constraints. In this context, oil refers to conventional oil and excludes oil from coal, oil shale, bitumen and extra-heavy oil (tar sands).[1]
Oil in the ground is not a "reserve" unless it is claimed to be economically recoverable, since as the oil is extracted, the cost of recovery increases incrementally as the amount of oil remaining is reduced. The recovery factor (RF) is the percentage of oil in place which is expected to be economically recoverable under a given set of conditions. (It is therefore important to realize that as the price of oil goes up on the markets, the amount of petroleum in the ground that is economically recoverable goes up, because the oil that is more expensive to get is now recoverable at a profit. As the price goes down, the amount that is economically recoverable goes down. So the amount of oil you can say you have in your SEC statements--i.e. "bookable barrels"--depends on the price of oil on the markets as well as the actual amount of oil in the ground. A large change in price will radically change the amount of oil understood to be part of the reserve, regardless of whether any oil has been lifted from the wells in question or not.)
Oil reserve estimates are ideally a measure of geological and economic risk — of the probability of oil existing and being producible under current economic conditions using current technology. The international authority for reserves definitions is generally the Society of Petroleum Engineers. The U.S. Securities and Exchange Commission demands that oil companies with exchange listed stock adopt reserves accounting standards that are consistent with common industry practice. However these standards are based on historical production practices and are not always meaningful in dealing with deep-water and non-conventional oil fields that are becoming the source of more and more of the world's oil production. In addition, many of the world's largest oil-producing countries do not follow normal industry standards in estimating their oil reserves and do not publish any data which would allow their estimates to be verified.
Oil in the ground is not a "reserve" unless it is claimed to be economically recoverable, since as the oil is extracted, the cost of recovery increases incrementally as the amount of oil remaining is reduced. The recovery factor (RF) is the percentage of oil in place which is expected to be economically recoverable under a given set of conditions. (It is therefore important to realize that as the price of oil goes up on the markets, the amount of petroleum in the ground that is economically recoverable goes up, because the oil that is more expensive to get is now recoverable at a profit. As the price goes down, the amount that is economically recoverable goes down. So the amount of oil you can say you have in your SEC statements--i.e. "bookable barrels"--depends on the price of oil on the markets as well as the actual amount of oil in the ground. A large change in price will radically change the amount of oil understood to be part of the reserve, regardless of whether any oil has been lifted from the wells in question or not.)
Oil reserve estimates are ideally a measure of geological and economic risk — of the probability of oil existing and being producible under current economic conditions using current technology. The international authority for reserves definitions is generally the Society of Petroleum Engineers. The U.S. Securities and Exchange Commission demands that oil companies with exchange listed stock adopt reserves accounting standards that are consistent with common industry practice. However these standards are based on historical production practices and are not always meaningful in dealing with deep-water and non-conventional oil fields that are becoming the source of more and more of the world's oil production. In addition, many of the world's largest oil-producing countries do not follow normal industry standards in estimating their oil reserves and do not publish any data which would allow their estimates to be verified.
Thursday, November 29, 2007
High Integrity Protection Systems (HIPS) – Making SIL Calculations Effective
the oil industry, traditional protection systems as defined in American Petroleum Institute (API) 14C are more and more often replaced by high integrity protection systems (HIPS). In particular, this encompasses the well-known high integrity pressure protection systems (HIPPS) used to protect specifically against overpressure. As safety instrumented systems (SIS) they have to be analysed through the formal processes described in the International Electrotechnical Commission (IEC) 61508 and IEC 61511 Standards in order to assess which Safety Integrity Levels (SIL) they are able to claim. What is really important when dealing with safety systems is that the probability of accident is sufficiently low to be acceptable according to the magnitude of the consequences. This can be done in a lot of different ways: applying rules, know-how or standards that may be deterministic, probabilistic, qualitative or quantitative, using reliability analysis and reliability methods and tools, collecting statistics, etc. Among them we find SIL calculations as per IEC 61508 and IEC 61511. Then we have to keep in mind that calculating a SIL is not an end in itself. It is only a tool among many others to help engineers to master safety through the whole life cycle of the safety systems. This proves to be very efficient from organisational point of view but, unfortunately, some problems arise when probabilistic calculations are performed by analysts thinking that it is a very easy job only consisting to apply some magical formulae (found in IEC 61508-Part 6) or to build a kind of ‘Lego’ from certified SILed elements bought from the shelf. Beyond the fact that sound mathematical theorems (Bellman or Gödel) demonstrate that doing it that way gives no guarantee of good results, this is the complete negation of the spirit developed in the reliability field over the last 50 years that is based on a sound knowledge of the probabilistic concepts and in-depth analysis of systems under study. Therefore, a skilled reliability analyst who aims to use the above standards in a clever and compatible way with the traditional analysis has to solve several difficulties: this is simple for the relationship between IEC standards probability concepts and those recognised in the reliability field or for the failure taxonomy and definitions which may need improvements; it is more difficult for handling complex tests and maintenance procedures encountered in oil industry; it is almost impossible for some concepts like the ‘Safe Failure Fraction’ (SFF), which is not really relevant in our field where spurious failures have to be thoroughly considered and avoided.
SIL versus Traditional Concepts
The size of this article being limited, we will only give some indications about our way to manage SIL calculations in an efficient way for oil production installations. Figure 1 shows the links with the traditional concepts. The first protection layer works in continuous mode and the standards impose to calculate its Probability of Failure per Hour (PFH). This is actually an average frequency of failure. When the number of failures over [0, T] is small compared with 1, PFH may be assimilated to F1(T)/T. When this is not the case, T/MTTF shall be used instead. In these formulae F1(T) is the unreliability of this layer over [0,T] and MTTF its classical Mean Time To Fail. Then, in the general cases, PFH cannot be assimilated to a failure rate. Anyway this gives the demand frequency on the second layer, which runs in low demand mode (if the first layer is efficient). Its Probability of Failure on Demand (PFD) as per the standards is in fact its the average unavailability P2. Then F1(T).P2 is the probability that both protection layers fail during a given period T. If there is no more protection layer this is the probability of accident. If a third protection layer is installed this will be is the demand frequency on this layer. Note that the Risk Reduction Factor (RRF) is infinite when working in continuous mode. The standard split, the demand mode between low and high according to the demand frequency (lower or greater than 1/year). From probabilistic calculation point of view we prefer to consider the relationship between test and demand frequencies to do that: when the test frequency is big compared with the demand frequency, PFD may be used, on the contrary it is better to use the unreliability, which provides a conservative estimation. From a failure mode point of view the main problem encountered is that the genuine on demand failures are forgotten by the standards. They are likely to occur when the system experiences sudden changes of states. Therefore, they shall be taken under consideration when calculating the PFD, which comprises both hidden failure (occurring within test intervals) and genuine on-demand failures (due to tests or demands themselves). Another commonly encountered problem is that a superficial reading of the standard leads one to think that every revealed failure becomes automatically safe. This, of course, is not true. It remains unsafe as long as something is done to make it safe. This also has to be considered in the calculations.
SIL versus Traditional Concepts
The size of this article being limited, we will only give some indications about our way to manage SIL calculations in an efficient way for oil production installations. Figure 1 shows the links with the traditional concepts. The first protection layer works in continuous mode and the standards impose to calculate its Probability of Failure per Hour (PFH). This is actually an average frequency of failure. When the number of failures over [0, T] is small compared with 1, PFH may be assimilated to F1(T)/T. When this is not the case, T/MTTF shall be used instead. In these formulae F1(T) is the unreliability of this layer over [0,T] and MTTF its classical Mean Time To Fail. Then, in the general cases, PFH cannot be assimilated to a failure rate. Anyway this gives the demand frequency on the second layer, which runs in low demand mode (if the first layer is efficient). Its Probability of Failure on Demand (PFD) as per the standards is in fact its the average unavailability P2. Then F1(T).P2 is the probability that both protection layers fail during a given period T. If there is no more protection layer this is the probability of accident. If a third protection layer is installed this will be is the demand frequency on this layer. Note that the Risk Reduction Factor (RRF) is infinite when working in continuous mode. The standard split, the demand mode between low and high according to the demand frequency (lower or greater than 1/year). From probabilistic calculation point of view we prefer to consider the relationship between test and demand frequencies to do that: when the test frequency is big compared with the demand frequency, PFD may be used, on the contrary it is better to use the unreliability, which provides a conservative estimation. From a failure mode point of view the main problem encountered is that the genuine on demand failures are forgotten by the standards. They are likely to occur when the system experiences sudden changes of states. Therefore, they shall be taken under consideration when calculating the PFD, which comprises both hidden failure (occurring within test intervals) and genuine on-demand failures (due to tests or demands themselves). Another commonly encountered problem is that a superficial reading of the standard leads one to think that every revealed failure becomes automatically safe. This, of course, is not true. It remains unsafe as long as something is done to make it safe. This also has to be considered in the calculations.
Health and Safety issues in the offshore industry – a precautionary tale
There have been significant improvements in health and safety in the offshore industry since the catastrophic Piper Alpha disaster in 1988, when an explosion and the resulting fire cost the lives of 167 workers. Despite these improvements, risks for the 20000 workforce in the offshore industry are still ever present - fire, explosion and infrastructure failure all have the potential to cause major loss of life.
News on Tuesday evening broke that offshore workers, based 120 miles offshore, had been helicoptered from a semi-submersible drilling rig following an engine fire.
In fact a total of 32 of the 87 personnel were taken off the Ocean Guardian, owned by Diamond Offshore, before the fire was brought under control. Fortunately no-one was injured.
"We have had a fire in the engine room," said a spokesman for Diamond. "As a precaution we began down-manning non-essential personnel."
A fire suppression system was activated when the fire broke out. Innovative water mist systems are in high regard in the industry and are becoming the sought after solution to fire on offshore installations.
With the geographically isolated workforce, as well as the inherent dangers in working offshore, the industry needs the best health and safety management. The quality of management that Diamond Offshore showed through their precautionary evacuation.
News on Tuesday evening broke that offshore workers, based 120 miles offshore, had been helicoptered from a semi-submersible drilling rig following an engine fire.
In fact a total of 32 of the 87 personnel were taken off the Ocean Guardian, owned by Diamond Offshore, before the fire was brought under control. Fortunately no-one was injured.
"We have had a fire in the engine room," said a spokesman for Diamond. "As a precaution we began down-manning non-essential personnel."
A fire suppression system was activated when the fire broke out. Innovative water mist systems are in high regard in the industry and are becoming the sought after solution to fire on offshore installations.
With the geographically isolated workforce, as well as the inherent dangers in working offshore, the industry needs the best health and safety management. The quality of management that Diamond Offshore showed through their precautionary evacuation.
Deepwater Activity in the US Gulf of Mexico Continues to Drive Innovation and Technology
The deepwater Gulf of Mexico (GOM) is an integral part of US energy supply and one of the world’s most important oil and gas provinces. As a result of its proximity to key markets and a long history of exploration and development, the region is now seeing a transition towards deeper and more challenging exploration and development, including both deeper water and deeper wells. These trends are the motivation behind a renewed drive towards advancing the state of key technologies.
Growth of US Deepwater:
The distinction between shallow and deepwater can range from 656ft (200m) to 1,500ft (457m) water depth. Here, Minerals Management Service (MMS) information is used, which defines deepwater as water depths greater than or equal to 1,000ft (305m) and ultra-deepwater as water depths greater than or equal to 5,000ft (1,524m).1 As of early 2006, there were 118 deepwater projects on production. Production from deepwater by the end of 2004 was approximately 950,000 barrels of oil and 3.8 billion cubic feet of natural gas per day. More than 980 deepwater exploration wells have been drilled since 1995 and at least 126 deepwater discoveries have been announced from that effort. In the last six years, there have been 22 discoveries in water depths greater than 7,000ft (2,134m), with 11 of those discoveries in the last two years. Approximately one-third of the world’s deepwater rig fleet is committed to GOM service. The average size of a deepwater GOM field discovery is several times larger than the average shallow-water discovery, and deepwater fields are some of the most prolific producers in the GOM. Announced volumes for these deepwater discoveries are more than 1.8 billion barrels of oil equivalent (BOE). The growth of activity in the deepwater GOM has accelerated over the last few years, although it has been developing for over two decades. Deepwater production began in 1979 with Shell’s Cognac field, and it took five more years before the next deepwater field (ExxonMobil’s Lena field) came online. Both developments relied on extending platform technology to greater water depths. Over the last 14 years, all phases of deepwater activity have expanded. There are over 8,200 active GOM leases with 54% of those in deepwater. Contrast this with approximately 5,600 active GOM leases in 1992, with only 27% in deepwater. On average, there were 30 rigs drilling in deepwater in 2005 compared with only three rigs in 1992. In the period 1992–2002, deepwater oil production rose by over 840% and deepwater gas production increased by about 1,600%. The Deep Water Royalty Relief Act (DWRRA), which provides economic incentives to develop leases in deepwater, has clearly had a significant impact on deepwater GOM activities. Deepwater exploration and production growth have been enabled by remarkable technology advances over time. These advances continue today, with many new technologies currently in the research phase for future deployment.
Discoveries
Recent discoveries continue to expand the exploration potential of the deepwater GOM. Of total GOM proved reserves, 99% are in Neogene-age and younger reservoirs (Pleistocene, Pliocene and Miocene). However, several recent deepwater discoveries encountered large potential reservoirs in sands of Paleogene age (Oligocene, Eocene and Paleocene). The discovery of these Paleogene-age reservoirs has opened wide areas of the deepwater GOM to further drilling, focused on two frontier plays: the Mississippi Fan Foldbelt and the Perdido Foldbelt. With the drilling of the Trident and Cascade discoveries (AC 903 and WR 206) in 2001 and 2002, the potential for an extensive Lower Wilcox sand extending from Alaminos Canyon to Walker Ridge was established. Deposition of the Lower Wilcox appears to have been largely unaffected by salt tectonics, resulting in a thick sand across a broad geographic area. The Cascade discovery established turbidite sands more than 350 miles downdip of their source deltas in south Texas. Two further subsalt discoveries have been made in the Lower Wilcox: St Malo (WR 678) and Jack (WR 759). To date, there have been five Lower Wilcox and/or Paleogene discoveries in Alaminos Canyon and four Lower Wilcox discoveries in Walker Ridge. The Paleogene-age reservoirs provide a promising exploration trend. However, there are a number of challenges that must be addressed before production can begin. Appraisal wells must be drilled to test reservoir quality and producibility. Other challenges include the completion and production of deep reservoirs in the ultra-deepwater GOM, for which infrastructure must be developed. Successful exploration has also occurred in the eastern GOM with announced discoveries in DeSoto Canyon (Spiderman/Amazon and San Jacinto) and Lloyd Ridge (Atlas, Atlas NW, Cheyenne and Mondo Northwest). At least six of these discoveries encountered Miocene-age reservoirs, and all ten are in water depths greater than 7,800ft (2,378m). The Mississippi Fan foldbelt trend saw three Lower Miocene oil discoveries in 2005: Knotty Head (GC 512), Genghis Khan (GC 652) and Big Foot (WR 29). Chevron’s successful production test at their Tahiti discovery well (GC 640) in 2004 undoubtedly spurred further exploration of the trend. Tahiti tested a structural trap beneath an 11,000ft (3,354m) thick salt canopy. The discovery well produced at a restricted rate of 15 million barrels of oil per day (MBOPD). Rate and pressure analyses indicate that the well may be capable of a sustained flow of as much as 30 MBOPD. Until recently, there had been a gradual increase of drilling depth. However, since 1996 the maximum drilling depth has increased rapidly, reaching true vertical depths (TVDs) just below 30,000ft (9,144m) in 2002. The Transocean Discoverer Spirit drilled the deepest well in the GOM to date: Chevron/Unocal’s Knotty Head discovery in Green Canyon Block 512 at a TVD of 34,157ft (10,411m) in December 2005. This recent dramatic increase in TVD may be attributed to several factors, including enhanced rig capabilities, deeper exploration targets and the general trend towards greater water depths. In the last five years, 12 wells have been drilled in water depths exceeding 9,000ft (2,744m) and, in December 2003, the first well in water depths over 10,000ft (3,050m) was drilled. The water depth drilling record of 10,011ft (3,051m) was set by Chevron in Alaminos Canyon Block 951 in late 2003.
Productivity
High production rates have been a driving force behind the success of deepwater operations. For example, a Shell Bullwinkle well produced approximately 5,000 barrels of oil per day (BOPD) in 1992. In 1994, a Shell Auger well set a new record, producing about 10,000 BOPD. From 1994 to mid 1999, maximum deepwater oil production rates continued to climb. BP’s Horn Mountain project came online in early 2002 in a water depth of 5,400ft (1,646m), with a single well maximum rate of more than 30,000 BOPD. Since mid 2002, oil production rates have declined in the 1,500–4,999ft (457–1,524m) water-depth interval. However, production rates have increased steeply in the greater than and equal to 5,000ft (1,524m) water-depth interval. The record daily oil production rate (for a single well) is 41,532 BOPD (Troika). In terms of gas production, maximum well rates were around 25 million cubic feet per day (MMCFPD) until a well in Shell’s Popeye field raised the deepwater production record to over 100 MMCFPD in 1996. Since then, the deepwater has yielded even higher maximum production rates. In 1997, Shell’s Mensa field showed the potential for deepwater production rates beyond the 5,000ft (1,524m) waterdepth interval. The record GOM daily gas production rate is 158 MMCFPD (Mensa). The average GOM deepwater oil well currently produces at about 25 times the rate of the average shallow-water oil well, while the average GOM deepwater gas well currently produces at about eight times the rate of the average shallow-water gas well. Subsea Toolkit There were fewer than ten subsea completions per year until 1993, but this number increased dramatically throughout the 1990s. Shallowwater subsea wells began to make up a significant proportion of the total number of GOM subsea wells, accounting for 151 of the 348 subsea wells by year-end 2005. Operators have found subsea tiebacks to be valuable for marginal shallow-water fields because of the extensive infrastructure of available platforms and pipelines. As a result of these factors, there has been an increasing reliance on subsea technology to develop shallow-water and deepwater fields. The technology required to implement subsea production systems in deepwater has evolved significantly in the last 17 years. A water depth of 350ft (107m) was the deepest subsea completion until 1988, when the water depth record for the GOM jumped to 2,243ft or 684m (Green Canyon 31 project). In 1996, another record was reached with a subsea completion in 2,956ft (901m) of water (Mars project), followed by a 1997 subsea completion in 5,295ft (1,614m) of water (Mensa project). Currently, Coulomb has the deepest subsea production in the GOM, in a water depth of 7,591ft (2,313m). Nearly 70% of subsea completions are in water depths of less than 2,500ft (762m). In order for subsea wells to continue to advance to greater water depths and harsher environments, technological improvements are needed. Currently, the industry is working to ensure that new advancements are developed in a safe and environmentally conscientious manner. Technologies currently under evaluation include high-integrity pressure protection systems (HIPPS), high-pressure, hightemperature (HPHT) materials and subsea processing.
High-pressure, High-temperature Future
As deepwater wells are drilled to greater depths, they begin to encounter the same HPHT conditions that shallow-water wells see at shallower depths. HPHT development is therefore one of the greatest technical challenges facing the oil and gas industry today. Materials that have been used for many years now face unique and critical environmental conditions. The industry is working on a number of collaborative fronts to evaluate these issues and to develop appropriate technologies to mitigate potential hazards. Such efforts include joint research, knowledge sharing via industry conferences and focused standards development via technical committees of the American Petroleum Institute (API), National Association of Corrosion Engineers (NACE) and other groups.
Summary
Significant challenges exist for deepwater exploration and development. Deepwater operations are expensive and require significant amounts of time between initial discovery and first production. Despite these challenges, deepwater fields have demonstrated prolific performance with successful developments providing great rewards. In order for growth and deepening trends to continue, technology will be a required point of leverage. It will be required to resolve current gap challenges, such as those posed by HPHT prospects in deepwater, and to bring further cost efficiencies into the exploration, development and production phases.
Growth of US Deepwater:
The distinction between shallow and deepwater can range from 656ft (200m) to 1,500ft (457m) water depth. Here, Minerals Management Service (MMS) information is used, which defines deepwater as water depths greater than or equal to 1,000ft (305m) and ultra-deepwater as water depths greater than or equal to 5,000ft (1,524m).1 As of early 2006, there were 118 deepwater projects on production. Production from deepwater by the end of 2004 was approximately 950,000 barrels of oil and 3.8 billion cubic feet of natural gas per day. More than 980 deepwater exploration wells have been drilled since 1995 and at least 126 deepwater discoveries have been announced from that effort. In the last six years, there have been 22 discoveries in water depths greater than 7,000ft (2,134m), with 11 of those discoveries in the last two years. Approximately one-third of the world’s deepwater rig fleet is committed to GOM service. The average size of a deepwater GOM field discovery is several times larger than the average shallow-water discovery, and deepwater fields are some of the most prolific producers in the GOM. Announced volumes for these deepwater discoveries are more than 1.8 billion barrels of oil equivalent (BOE). The growth of activity in the deepwater GOM has accelerated over the last few years, although it has been developing for over two decades. Deepwater production began in 1979 with Shell’s Cognac field, and it took five more years before the next deepwater field (ExxonMobil’s Lena field) came online. Both developments relied on extending platform technology to greater water depths. Over the last 14 years, all phases of deepwater activity have expanded. There are over 8,200 active GOM leases with 54% of those in deepwater. Contrast this with approximately 5,600 active GOM leases in 1992, with only 27% in deepwater. On average, there were 30 rigs drilling in deepwater in 2005 compared with only three rigs in 1992. In the period 1992–2002, deepwater oil production rose by over 840% and deepwater gas production increased by about 1,600%. The Deep Water Royalty Relief Act (DWRRA), which provides economic incentives to develop leases in deepwater, has clearly had a significant impact on deepwater GOM activities. Deepwater exploration and production growth have been enabled by remarkable technology advances over time. These advances continue today, with many new technologies currently in the research phase for future deployment.
Discoveries
Recent discoveries continue to expand the exploration potential of the deepwater GOM. Of total GOM proved reserves, 99% are in Neogene-age and younger reservoirs (Pleistocene, Pliocene and Miocene). However, several recent deepwater discoveries encountered large potential reservoirs in sands of Paleogene age (Oligocene, Eocene and Paleocene). The discovery of these Paleogene-age reservoirs has opened wide areas of the deepwater GOM to further drilling, focused on two frontier plays: the Mississippi Fan Foldbelt and the Perdido Foldbelt. With the drilling of the Trident and Cascade discoveries (AC 903 and WR 206) in 2001 and 2002, the potential for an extensive Lower Wilcox sand extending from Alaminos Canyon to Walker Ridge was established. Deposition of the Lower Wilcox appears to have been largely unaffected by salt tectonics, resulting in a thick sand across a broad geographic area. The Cascade discovery established turbidite sands more than 350 miles downdip of their source deltas in south Texas. Two further subsalt discoveries have been made in the Lower Wilcox: St Malo (WR 678) and Jack (WR 759). To date, there have been five Lower Wilcox and/or Paleogene discoveries in Alaminos Canyon and four Lower Wilcox discoveries in Walker Ridge. The Paleogene-age reservoirs provide a promising exploration trend. However, there are a number of challenges that must be addressed before production can begin. Appraisal wells must be drilled to test reservoir quality and producibility. Other challenges include the completion and production of deep reservoirs in the ultra-deepwater GOM, for which infrastructure must be developed. Successful exploration has also occurred in the eastern GOM with announced discoveries in DeSoto Canyon (Spiderman/Amazon and San Jacinto) and Lloyd Ridge (Atlas, Atlas NW, Cheyenne and Mondo Northwest). At least six of these discoveries encountered Miocene-age reservoirs, and all ten are in water depths greater than 7,800ft (2,378m). The Mississippi Fan foldbelt trend saw three Lower Miocene oil discoveries in 2005: Knotty Head (GC 512), Genghis Khan (GC 652) and Big Foot (WR 29). Chevron’s successful production test at their Tahiti discovery well (GC 640) in 2004 undoubtedly spurred further exploration of the trend. Tahiti tested a structural trap beneath an 11,000ft (3,354m) thick salt canopy. The discovery well produced at a restricted rate of 15 million barrels of oil per day (MBOPD). Rate and pressure analyses indicate that the well may be capable of a sustained flow of as much as 30 MBOPD. Until recently, there had been a gradual increase of drilling depth. However, since 1996 the maximum drilling depth has increased rapidly, reaching true vertical depths (TVDs) just below 30,000ft (9,144m) in 2002. The Transocean Discoverer Spirit drilled the deepest well in the GOM to date: Chevron/Unocal’s Knotty Head discovery in Green Canyon Block 512 at a TVD of 34,157ft (10,411m) in December 2005. This recent dramatic increase in TVD may be attributed to several factors, including enhanced rig capabilities, deeper exploration targets and the general trend towards greater water depths. In the last five years, 12 wells have been drilled in water depths exceeding 9,000ft (2,744m) and, in December 2003, the first well in water depths over 10,000ft (3,050m) was drilled. The water depth drilling record of 10,011ft (3,051m) was set by Chevron in Alaminos Canyon Block 951 in late 2003.
Productivity
High production rates have been a driving force behind the success of deepwater operations. For example, a Shell Bullwinkle well produced approximately 5,000 barrels of oil per day (BOPD) in 1992. In 1994, a Shell Auger well set a new record, producing about 10,000 BOPD. From 1994 to mid 1999, maximum deepwater oil production rates continued to climb. BP’s Horn Mountain project came online in early 2002 in a water depth of 5,400ft (1,646m), with a single well maximum rate of more than 30,000 BOPD. Since mid 2002, oil production rates have declined in the 1,500–4,999ft (457–1,524m) water-depth interval. However, production rates have increased steeply in the greater than and equal to 5,000ft (1,524m) water-depth interval. The record daily oil production rate (for a single well) is 41,532 BOPD (Troika). In terms of gas production, maximum well rates were around 25 million cubic feet per day (MMCFPD) until a well in Shell’s Popeye field raised the deepwater production record to over 100 MMCFPD in 1996. Since then, the deepwater has yielded even higher maximum production rates. In 1997, Shell’s Mensa field showed the potential for deepwater production rates beyond the 5,000ft (1,524m) waterdepth interval. The record GOM daily gas production rate is 158 MMCFPD (Mensa). The average GOM deepwater oil well currently produces at about 25 times the rate of the average shallow-water oil well, while the average GOM deepwater gas well currently produces at about eight times the rate of the average shallow-water gas well. Subsea Toolkit There were fewer than ten subsea completions per year until 1993, but this number increased dramatically throughout the 1990s. Shallowwater subsea wells began to make up a significant proportion of the total number of GOM subsea wells, accounting for 151 of the 348 subsea wells by year-end 2005. Operators have found subsea tiebacks to be valuable for marginal shallow-water fields because of the extensive infrastructure of available platforms and pipelines. As a result of these factors, there has been an increasing reliance on subsea technology to develop shallow-water and deepwater fields. The technology required to implement subsea production systems in deepwater has evolved significantly in the last 17 years. A water depth of 350ft (107m) was the deepest subsea completion until 1988, when the water depth record for the GOM jumped to 2,243ft or 684m (Green Canyon 31 project). In 1996, another record was reached with a subsea completion in 2,956ft (901m) of water (Mars project), followed by a 1997 subsea completion in 5,295ft (1,614m) of water (Mensa project). Currently, Coulomb has the deepest subsea production in the GOM, in a water depth of 7,591ft (2,313m). Nearly 70% of subsea completions are in water depths of less than 2,500ft (762m). In order for subsea wells to continue to advance to greater water depths and harsher environments, technological improvements are needed. Currently, the industry is working to ensure that new advancements are developed in a safe and environmentally conscientious manner. Technologies currently under evaluation include high-integrity pressure protection systems (HIPPS), high-pressure, hightemperature (HPHT) materials and subsea processing.
High-pressure, High-temperature Future
As deepwater wells are drilled to greater depths, they begin to encounter the same HPHT conditions that shallow-water wells see at shallower depths. HPHT development is therefore one of the greatest technical challenges facing the oil and gas industry today. Materials that have been used for many years now face unique and critical environmental conditions. The industry is working on a number of collaborative fronts to evaluate these issues and to develop appropriate technologies to mitigate potential hazards. Such efforts include joint research, knowledge sharing via industry conferences and focused standards development via technical committees of the American Petroleum Institute (API), National Association of Corrosion Engineers (NACE) and other groups.
Summary
Significant challenges exist for deepwater exploration and development. Deepwater operations are expensive and require significant amounts of time between initial discovery and first production. Despite these challenges, deepwater fields have demonstrated prolific performance with successful developments providing great rewards. In order for growth and deepening trends to continue, technology will be a required point of leverage. It will be required to resolve current gap challenges, such as those posed by HPHT prospects in deepwater, and to bring further cost efficiencies into the exploration, development and production phases.
Saturday, November 24, 2007
Arctic National Wildlife Refuge
The Arctic National Wildlife Refuge (ANWR) covers 19,049,236 acres (79,318 km²) in northeastern Alaska, in the North Slope region. It was originally protected in 1960 by order of Fred A. Seaton, the Secretary of the Interior under U.S. President Dwight D. Eisenhower. As part of Alaska National Interest Lands Conservation Act, the refuge was expanded by the United States Congress in 1980 through the lobbying efforts of Olaus and Margaret Murie, with The Wilderness Society.
Eight million acres (32,375 km²) of the refuge are designated as U.S. Wilderness Area. The 1980 expansion of the refuge designated 1.5 million acres (6,070 km²) of the coastal plain as the 1002 area and mandated studies of the natural resources of this area, especially petroleum. Congressional authorization is required before oil drilling may proceed in this area. The remaining 10.1 million acres (40,873 km²) of the refuge are designated as "Minimal Management," a category intended to maintain existing natural conditions and resource values. These areas are suitable for wilderness designation, although there are presently no proposals to designate them as wilderness.
There are presently no roads within or leading into the refuge, though there are settlements there. On the northern edge of the Refuge is the Inupiaq village of Kaktovik and on the southern boundary the Gwich'in settlement of Arctic Village. A popular wilderness route and historic passage exists between the two villages, traversing the Refuge and all its ecosystem types from boreal, interior forest to Arctic Ocean coast. Generally, visitors gain access to the land by aircraft, but it is also possible to reach the refuge by boat or by walking (the Dalton Highway passes near the western edge of the refuge). In the United States of America, the geographic location most remote from human trails, roads, or settlements is found here, at the headwaters of the Sheenjek River.
Wildworld.
The refuge supports a greater variety of plant and animal life than any other protected area in the circumpolar arctic. A continuum of six different ecozones spans some 200 miles (300 km) north to south.
Along the northern boundary of the refuge, barrier islands, coastal lagoons, salt marshs, and shorebirds. Fish such as dolly varden and arctic cisco are found in nearshore waters. Coastal lands and sea ice are used by caribou seeking relief from biting insects during summer, and by polar bears hunting seals and giving birth in snow dens during winter.
The arctic coastal plain stretches southward from the coast to the foothills of the Brooks Range. This area of rolling hills, small lakes, and north-flowing, braided rivers is dominated by tundra vegetation consisting of low shrubs, sedges, and mosses. Caribou travel to the coastal plain during June and July to give birth and raise their young. Migratory birds and insects flourish here during the brief arctic summer. Tens of thousands of snow geese stop here during September to feed before migrating south, and musk oxen live here year-round.
South of the coastal plain, the mountains of the eastern Brooks Range rise to over 9,000 feet (3,000 m). This northernmost extension of the Rocky Mountains marks the continental divide, with north-flowing rivers emptying into the Arctic Ocean and south-flowing rivers joining the great Yukon River. The rugged mountains of the Brooks Range are incised by deep river valleys creating a range of elevations and aspects that support a variety of low tundra vegetation, dense shrubs, rare groves of poplar trees on the north side and spruce on the south. During summer, peregrine falcons, gyrfalcons, and golden eagles build nests on cliffs. Harlequin ducks and red-breasted mergansers are seen on swift-flowing rivers. Dall sheep and wolves are active all year, while grizzly bears and arctic ground squirrels are frequently seen during summer but hibernate in winter.
The southern portion of the Arctic Refuge is within the boreal forest of interior Alaska. Beginning as predominantly treeless tundra with scattered islands of black and white spruce trees, the forest becomes progressively denser as the foothills yield to the expansive flats north of the Yukon River. Frequent forest fires ignited by lightning result in a complex mosaic of birch, aspen, and spruce forests of various ages. Wetlands and south-flowing rivers create openings in the forest canopy. Neotropical migratory birds breed here in spring and summer, attracted by plentiful food and the variety of habitats. Caribou travel here from farther north to spend the winter. Year-round residents of the boreal forest include moose, lynx, marten, wolverines, black and grizzly bears, and wolves.
Each year, thousands of waterfowl and other birds nest and reproduce in areas surrounding Prudhoe Bay and Kuparuk fields and a healthy and increasing caribou herd migrates through these areas to calve and seek respite from annoying pests such as human activity. Oil field facilities have been located and designed to accommodate wildlife and utilize the least amount of tundra surface.
Arctic Refuge drilling controversy.
Because the Arctic National Wildlife Refuge is known to contain a large supply of crude oil, the issue of drilling for oil in roughly 2000 of the 19,600,000 acre area has been a debated topic since World War II. The controversy has been a political football for every U.S. President since Jimmy Carter
Eight million acres (32,375 km²) of the refuge are designated as U.S. Wilderness Area. The 1980 expansion of the refuge designated 1.5 million acres (6,070 km²) of the coastal plain as the 1002 area and mandated studies of the natural resources of this area, especially petroleum. Congressional authorization is required before oil drilling may proceed in this area. The remaining 10.1 million acres (40,873 km²) of the refuge are designated as "Minimal Management," a category intended to maintain existing natural conditions and resource values. These areas are suitable for wilderness designation, although there are presently no proposals to designate them as wilderness.
There are presently no roads within or leading into the refuge, though there are settlements there. On the northern edge of the Refuge is the Inupiaq village of Kaktovik and on the southern boundary the Gwich'in settlement of Arctic Village. A popular wilderness route and historic passage exists between the two villages, traversing the Refuge and all its ecosystem types from boreal, interior forest to Arctic Ocean coast. Generally, visitors gain access to the land by aircraft, but it is also possible to reach the refuge by boat or by walking (the Dalton Highway passes near the western edge of the refuge). In the United States of America, the geographic location most remote from human trails, roads, or settlements is found here, at the headwaters of the Sheenjek River.
Wildworld.
The refuge supports a greater variety of plant and animal life than any other protected area in the circumpolar arctic. A continuum of six different ecozones spans some 200 miles (300 km) north to south.
Along the northern boundary of the refuge, barrier islands, coastal lagoons, salt marshs, and shorebirds. Fish such as dolly varden and arctic cisco are found in nearshore waters. Coastal lands and sea ice are used by caribou seeking relief from biting insects during summer, and by polar bears hunting seals and giving birth in snow dens during winter.
The arctic coastal plain stretches southward from the coast to the foothills of the Brooks Range. This area of rolling hills, small lakes, and north-flowing, braided rivers is dominated by tundra vegetation consisting of low shrubs, sedges, and mosses. Caribou travel to the coastal plain during June and July to give birth and raise their young. Migratory birds and insects flourish here during the brief arctic summer. Tens of thousands of snow geese stop here during September to feed before migrating south, and musk oxen live here year-round.
South of the coastal plain, the mountains of the eastern Brooks Range rise to over 9,000 feet (3,000 m). This northernmost extension of the Rocky Mountains marks the continental divide, with north-flowing rivers emptying into the Arctic Ocean and south-flowing rivers joining the great Yukon River. The rugged mountains of the Brooks Range are incised by deep river valleys creating a range of elevations and aspects that support a variety of low tundra vegetation, dense shrubs, rare groves of poplar trees on the north side and spruce on the south. During summer, peregrine falcons, gyrfalcons, and golden eagles build nests on cliffs. Harlequin ducks and red-breasted mergansers are seen on swift-flowing rivers. Dall sheep and wolves are active all year, while grizzly bears and arctic ground squirrels are frequently seen during summer but hibernate in winter.
The southern portion of the Arctic Refuge is within the boreal forest of interior Alaska. Beginning as predominantly treeless tundra with scattered islands of black and white spruce trees, the forest becomes progressively denser as the foothills yield to the expansive flats north of the Yukon River. Frequent forest fires ignited by lightning result in a complex mosaic of birch, aspen, and spruce forests of various ages. Wetlands and south-flowing rivers create openings in the forest canopy. Neotropical migratory birds breed here in spring and summer, attracted by plentiful food and the variety of habitats. Caribou travel here from farther north to spend the winter. Year-round residents of the boreal forest include moose, lynx, marten, wolverines, black and grizzly bears, and wolves.
Each year, thousands of waterfowl and other birds nest and reproduce in areas surrounding Prudhoe Bay and Kuparuk fields and a healthy and increasing caribou herd migrates through these areas to calve and seek respite from annoying pests such as human activity. Oil field facilities have been located and designed to accommodate wildlife and utilize the least amount of tundra surface.
Arctic Refuge drilling controversy.
Because the Arctic National Wildlife Refuge is known to contain a large supply of crude oil, the issue of drilling for oil in roughly 2000 of the 19,600,000 acre area has been a debated topic since World War II. The controversy has been a political football for every U.S. President since Jimmy Carter
Oil refinery
An oil refinery is an industrial process plant where crude oil is processed and refined into more useful petroleum products, such as gasoline, diesel fuel, asphalt base, heating oil, kerosine, and liquefied petroleum gas.[1][2] Oil refineries are typically large sprawling industrial complexes with extensive piping running throughout, carrying streams of fluids between large chemical processing units.
Operation.
Raw oil or unprocessed ("crude") oil is not useful in the form it comes in out of the ground. Although "light, sweet" (low viscosity, low sulfur) oil has been used directly as a burner fuel for steam vessel propulsion, the lighter elements form explosive vapors in the fuel tanks and so it is quite dangerous, especially so in warships. For this and many other uses, the oil needs to be separated into parts and refined before use in fuels and lubricants, and before some of the byproducts could be used in petrochemical processes to form materials such as plastics, and foams. Petroleum fossil fuels are used in ship, automobile and aircraft engines. These different hydrocarbons have different boiling points, which means they can be separated by distillation. Since the lighter liquid elements are in great demand for use in internal combustion engines, a modern refinery will convert heavy hydrocarbons and lighter gaseous elements into these higher value products using complex and energy intensive processes.
Oil can be used in so many various ways because it contains hydrocarbons of varying molecular masses, forms and lengths such as paraffins, aromatics, naphthenes (or cycloalkanes), alkenes, dienes, and alkynes. Hydrocarbons are molecules of varying length and complexity made of only hydrogen and carbon atoms. Their various structures give them their differing properties and thereby uses. The trick in the oil refinement process is separating and purifying these.
Once separated and purified of any contaminants and impurities, the fuel or lubricant can be sold without any further processing. Smaller molecules such as isobutane and propylene or butylenes can be recombined to meet specific octane requirements of fuels by processes such as alkylation or less commonly, dimerization. Octane grade of gasoline can also be improved by catalytic reforming, which strips hydrogen out of hydrocarbons to produce aromatics, which have much higher octane ratings. Intermediate products such as gasoils can even be reprocessed to break a heavy, long-chained oil into a lighter short-chained one, by various forms of cracking such as Fluid Catalytic Cracking, Thermal Cracking, and Hydrocracking. The final step in gasoline production is the blending of fuels with different octane ratings, vapor pressures, and other properties to meet product specifications.
Oil refineries are large scale plants, processing from about a hundred thousand to several hundred thousand barrels of crude oil per day. Because of the high capacity, many of the units are operated continuously (as opposed to processing in batches) at steady state or approximately steady state for long periods of time (months to years). This high capacity also makes process optimization and advanced process control very desirable.
Major products of oil refineries.
Most products of oil processing are usually grouped into three categories: light distillates (LPG, gasoline, naptha), middle distillates (kerosene, diesel), heavy distillates and residuum (fuel oil, lubricating oils, wax, tar). This classification is based on the way crude oil is distilled and separated into fractions (called distillates and residuum) as can be seen in the above drawing.[2]
Liquid petroleum gas (LPG)
Gasoline (also known as petrol)
Naphtha
Kerosene and related jet aircraft fuels
Diesel fuel
Fuel oils
Lubricating oils
Paraffin wax
Asphalt and Tar
Petroleum coke
Common process units found in a refinery.
Desalter unit washes out salt from the crude oil before it enters the atmospheric distillation unit.
Atmospheric Distillation unit distills crude oil into fractions. See Continuous distillation.
Vacuum Distillation unit further distills residual bottoms after atmospheric distillation.
Naphtha Hydrotreater unit uses hydrogen to desulfurize naphtha from atmospheric distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit.
Catalytic Reformer unit is used to convert the naphtha-boiling range molecules into higher octane reformate (reformer product). The reformate has higher content of aromatics, olefins, and cyclic hydrocarbons). An important byproduct of a reformer is hydrogen released during the catalyst reaction. The hydrogen is used either in the hydrotreaters and hydrocracker.
Distillate Hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric distillation.
Fluid Catalytic Cracking (FCC) unit upgrades heavier fractions into lighter, more valuable products.
Hydrocracker unit uses hydrogen to upgrade heavier fractions into lighter, more valuable products.
Visbreaking unit upgrades heavy residual oils by thermally cracking them into lighter, more valuable reduced viscosity products.
Merox unit treats LPG, kerosene or jet fuel by oxidizing mercaptans to organic disulfides.
Coking units (either delayed or fluid coking) process very heavy residual oils into gasoline and diesel fuel, leaving petroleum coke as a residual product.
Alkylation unit produces high-octane component for gasoline blending.
Dimerization unit converts olefins into higher-octane gasoline blending components. For example, butenes can be dimerized into isooctene which may subsequently be hydrogenated to form isooctane. There are also other uses for dimerization.
Isomerization unit converts linear molecules to higher-octane branched molecules for blending into gasoline or feed to alkylation units.
Steam reforming unit produces hydrogen for the hydrotreaters or hydrocracker.
Liquified gas storage units for propane and similar gaseous fuels at pressure sufficient to maintain in liquid form. These are usually spherical vessels or bullets (horizontal vessels with rounded ends.
Storage tanks for crude oil and finished products, usually cylindrical, with some sort of vapor emission control and surrounded by an earthen berm to contain spills.
Amine gas treater, Claus unit, and tail gas treatment for converting hydrogen sulfide from hydrodesulfurization into elemental sulfur.
Utility units such as cooling towers for circulating cooling water, boiler plants for steam generation, instrument air systems for pneumatically operated control valves and an electrical substation.
Wastewater collection and treating systems consisting of API separators, dissolved air flotation (DAF) units and some type of further treatment (such as an activated sludge biotreater) to make such water suitable for reuse or for disposal.
Specialty end products.
These will blend various feedstocks, mix appropriate additives, provide short term storage, and prepare for bulk loading to trucks, barges, product ships, and railcars.
Gaseous fuels such as propane, stored and shipped in liquid form under pressure in specialized railcars to distributors.
Liquid fuels blending (producing automotive and aviation grades of gasoline, kerosene, various aviation turbine fuels, and diesel fuels, adding dyes, detergents, antiknock additives, oxygenates, and anti-fungal compounds as required). Shipped by barge, rail, and tanker ship. May be shipped regionally in dedicated pipelines to point consumers, particularly aviation jet fuel to major airports, or piped to distributors in multi-product pipelines using product separators called pipeline inspection gauges ("pigs").
Lubricants (produces light machine oils, motor oils, and greases, adding viscosity stabilizers as required), usually shipped in bulk to an offsite packaging plant.
Wax (paraffin), used in the packaging of frozen foods, among others. May be shipped in bulk to a site to prepare as packaged blocks.
Sulfur (or sulfuric acid), byproducts of sulfur removal from petroleum which may have up to a couple percent sulfur as organic sulfur-containing compounds. Sulfur and sulfuric acid are useful industrial materials. Sulfuric acid is usually prepared and shipped as the acid precursor oleum.
Bulk tar shipping for offsite unit packaging for use in tar-and-gravel roofing.
Asphalt unit. Prepares bulk asphalt for shipment.
Petroleum coke, used in specialty carbon products or as solid fuel.
Petrochemicals or petrochemical feedstocks, which are often sent to petrochemical plants for further processing in a variety of ways. The petrochemicals may be olefins or their precursors, or various types of aromatic petrochemicals.
Safety and environmental concerns.
The refining process releases numerous different chemicals into the atmosphere; consequently, there are substantial air pollution emissions[7] and a notable odor normally accompanies the presence of a refinery. Aside from air pollution impacts there are also wastewater concerns,[3] risks of industrial accidents such as fire and explosion, and noise health effects due to industrial noise.
The public has demanded that many governments place restrictions on contaminants that refineries release, and most refineries have installed the equipment needed to comply with the requirements of the pertinent environmental protection regulatory agencies. In the United States, there is strong pressure to prevent the development of new refineries, and no major refinery has been built in the country since Marathon's Garyville, Louisiana facility in 1976. However, many existing refineries have been expanded during that time. Environmental restrictions and pressure to prevent construction of new refineries may have also contributed to rising fuel prices in the United States.[8] Additionally, many refineries (over 100 since the 1980s) have closed due to obsolescence and/or merger activity within the industry itself. This activity has been reported to Congress and in specialized studies not widely publicised.
Environmental and safety concerns mean that oil refineries are sometimes located some distance away from major urban areas. Nevertheless, there are many instances where refinery operations are close to populated areas and pose health risks such as in the Campo de Gibraltar, a Spanish state owned refinery near the towns of Gibraltar, Algeciras, La Linea, San Roque and Los Barrios with a combined population of over 300,000 residents within a 5 mile radius and the CEPSA refinery in Santa Cruz on the island of Tenerife, Spain[9] which is sited in a densely-populated city center and next to the only two major evacuation routes in and out of the city. In California's Contra Costa County and Solano County, a shoreline necklace of refineries and associated chemical plants are adjacent to urban areas in Richmond, Martinez, Pacheco, Concord, Pittsburg, Vallejo and Benicia, with occasional accidental events that require "shelter in place" orders to the adjacent populations.
History.
The world's first oil refineries were set up by Ignacy Łukasiewicz near Jaslo, Austrian Empire (now in Poland) in the years 1854-56[10][11] but they were initially small as there was no real demand for refined fuel. As Łukasiewicz's kerosene lamp gained popularity the refining industry grew in the area.
The first large oil refinery opened at Ploieşti, Romania in 1856.[12] Several other refineries were built at that location with investment from United States companies before being taken over by Nazi Germany during World War II. Most of these refineries were heavily bombarded by US Army Air Forces in Operation Tidal Wave, August 1, 1943. Since then they have been rebuilt, and currently pose somewhat of an environmental concern.
Another early example is Oljeön, now preserved as a museum at the UNESCO world heritage site Engelsberg. It started operation in 1875 and is part of the Ecomuseum Bergslagen.
At one time, the world's largest oil refinery was claimed to be Ras Tanura, Saudi Arabia, owned by Saudi Aramco. For most of the 20th century, the largest refinery of the world was the Abadan refinery in Iran. This refinery suffered extensive damage during the war Iran-Iraq war. The world's largest refinery complex is the "Centro de Refinación de Paraguaná" (CRP) operated by PDVSA in Venezuela with a production capacity of 956,000 barrels per day (Amuay 635,000 bpd, Cardón 305,000 bpd and Bajo Grande 16,000 bpd). SK Corporation's Ulsan refinery in South Korea with a capacity of 840,000 bpd and Reliance Petroleum's refinery in Jamnagar, India with 660,000 bpd are the second and third largest, respectively.
Early US refineries processed crude oil to recover the kerosene. Other products (like gasoline) were considered wastes and were often dumped directly into the nearest river. The invention of the automobile shifted the demand to gasoline and diesel, which remain the primary refined products today. Refineries pre-dating the EPA were very toxic to the environment. Strict legislation has mandated that refineries meet modern air and water cleanliness standards. In fact, obtaining a permit to build even a modern refinery with minimal impact on the environment (other than CO2 emissions) is so difficult and costly that no new refineries have been built (though many have been expanded) in the United States since 1976. As a result, some believe that this may be the reason that the US is becoming more and more dependent on the imports of finished gasoline, as opposed to incremental crude oil. On the other hand, studies have revealed that accelerating merger activity in the refining and production sector has reduced capacity further, resulting in tighter markets in the United States in particular
Operation.
Raw oil or unprocessed ("crude") oil is not useful in the form it comes in out of the ground. Although "light, sweet" (low viscosity, low sulfur) oil has been used directly as a burner fuel for steam vessel propulsion, the lighter elements form explosive vapors in the fuel tanks and so it is quite dangerous, especially so in warships. For this and many other uses, the oil needs to be separated into parts and refined before use in fuels and lubricants, and before some of the byproducts could be used in petrochemical processes to form materials such as plastics, and foams. Petroleum fossil fuels are used in ship, automobile and aircraft engines. These different hydrocarbons have different boiling points, which means they can be separated by distillation. Since the lighter liquid elements are in great demand for use in internal combustion engines, a modern refinery will convert heavy hydrocarbons and lighter gaseous elements into these higher value products using complex and energy intensive processes.
Oil can be used in so many various ways because it contains hydrocarbons of varying molecular masses, forms and lengths such as paraffins, aromatics, naphthenes (or cycloalkanes), alkenes, dienes, and alkynes. Hydrocarbons are molecules of varying length and complexity made of only hydrogen and carbon atoms. Their various structures give them their differing properties and thereby uses. The trick in the oil refinement process is separating and purifying these.
Once separated and purified of any contaminants and impurities, the fuel or lubricant can be sold without any further processing. Smaller molecules such as isobutane and propylene or butylenes can be recombined to meet specific octane requirements of fuels by processes such as alkylation or less commonly, dimerization. Octane grade of gasoline can also be improved by catalytic reforming, which strips hydrogen out of hydrocarbons to produce aromatics, which have much higher octane ratings. Intermediate products such as gasoils can even be reprocessed to break a heavy, long-chained oil into a lighter short-chained one, by various forms of cracking such as Fluid Catalytic Cracking, Thermal Cracking, and Hydrocracking. The final step in gasoline production is the blending of fuels with different octane ratings, vapor pressures, and other properties to meet product specifications.
Oil refineries are large scale plants, processing from about a hundred thousand to several hundred thousand barrels of crude oil per day. Because of the high capacity, many of the units are operated continuously (as opposed to processing in batches) at steady state or approximately steady state for long periods of time (months to years). This high capacity also makes process optimization and advanced process control very desirable.
Major products of oil refineries.
Most products of oil processing are usually grouped into three categories: light distillates (LPG, gasoline, naptha), middle distillates (kerosene, diesel), heavy distillates and residuum (fuel oil, lubricating oils, wax, tar). This classification is based on the way crude oil is distilled and separated into fractions (called distillates and residuum) as can be seen in the above drawing.[2]
Liquid petroleum gas (LPG)
Gasoline (also known as petrol)
Naphtha
Kerosene and related jet aircraft fuels
Diesel fuel
Fuel oils
Lubricating oils
Paraffin wax
Asphalt and Tar
Petroleum coke
Common process units found in a refinery.
Desalter unit washes out salt from the crude oil before it enters the atmospheric distillation unit.
Atmospheric Distillation unit distills crude oil into fractions. See Continuous distillation.
Vacuum Distillation unit further distills residual bottoms after atmospheric distillation.
Naphtha Hydrotreater unit uses hydrogen to desulfurize naphtha from atmospheric distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit.
Catalytic Reformer unit is used to convert the naphtha-boiling range molecules into higher octane reformate (reformer product). The reformate has higher content of aromatics, olefins, and cyclic hydrocarbons). An important byproduct of a reformer is hydrogen released during the catalyst reaction. The hydrogen is used either in the hydrotreaters and hydrocracker.
Distillate Hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric distillation.
Fluid Catalytic Cracking (FCC) unit upgrades heavier fractions into lighter, more valuable products.
Hydrocracker unit uses hydrogen to upgrade heavier fractions into lighter, more valuable products.
Visbreaking unit upgrades heavy residual oils by thermally cracking them into lighter, more valuable reduced viscosity products.
Merox unit treats LPG, kerosene or jet fuel by oxidizing mercaptans to organic disulfides.
Coking units (either delayed or fluid coking) process very heavy residual oils into gasoline and diesel fuel, leaving petroleum coke as a residual product.
Alkylation unit produces high-octane component for gasoline blending.
Dimerization unit converts olefins into higher-octane gasoline blending components. For example, butenes can be dimerized into isooctene which may subsequently be hydrogenated to form isooctane. There are also other uses for dimerization.
Isomerization unit converts linear molecules to higher-octane branched molecules for blending into gasoline or feed to alkylation units.
Steam reforming unit produces hydrogen for the hydrotreaters or hydrocracker.
Liquified gas storage units for propane and similar gaseous fuels at pressure sufficient to maintain in liquid form. These are usually spherical vessels or bullets (horizontal vessels with rounded ends.
Storage tanks for crude oil and finished products, usually cylindrical, with some sort of vapor emission control and surrounded by an earthen berm to contain spills.
Amine gas treater, Claus unit, and tail gas treatment for converting hydrogen sulfide from hydrodesulfurization into elemental sulfur.
Utility units such as cooling towers for circulating cooling water, boiler plants for steam generation, instrument air systems for pneumatically operated control valves and an electrical substation.
Wastewater collection and treating systems consisting of API separators, dissolved air flotation (DAF) units and some type of further treatment (such as an activated sludge biotreater) to make such water suitable for reuse or for disposal.
Specialty end products.
These will blend various feedstocks, mix appropriate additives, provide short term storage, and prepare for bulk loading to trucks, barges, product ships, and railcars.
Gaseous fuels such as propane, stored and shipped in liquid form under pressure in specialized railcars to distributors.
Liquid fuels blending (producing automotive and aviation grades of gasoline, kerosene, various aviation turbine fuels, and diesel fuels, adding dyes, detergents, antiknock additives, oxygenates, and anti-fungal compounds as required). Shipped by barge, rail, and tanker ship. May be shipped regionally in dedicated pipelines to point consumers, particularly aviation jet fuel to major airports, or piped to distributors in multi-product pipelines using product separators called pipeline inspection gauges ("pigs").
Lubricants (produces light machine oils, motor oils, and greases, adding viscosity stabilizers as required), usually shipped in bulk to an offsite packaging plant.
Wax (paraffin), used in the packaging of frozen foods, among others. May be shipped in bulk to a site to prepare as packaged blocks.
Sulfur (or sulfuric acid), byproducts of sulfur removal from petroleum which may have up to a couple percent sulfur as organic sulfur-containing compounds. Sulfur and sulfuric acid are useful industrial materials. Sulfuric acid is usually prepared and shipped as the acid precursor oleum.
Bulk tar shipping for offsite unit packaging for use in tar-and-gravel roofing.
Asphalt unit. Prepares bulk asphalt for shipment.
Petroleum coke, used in specialty carbon products or as solid fuel.
Petrochemicals or petrochemical feedstocks, which are often sent to petrochemical plants for further processing in a variety of ways. The petrochemicals may be olefins or their precursors, or various types of aromatic petrochemicals.
Safety and environmental concerns.
The refining process releases numerous different chemicals into the atmosphere; consequently, there are substantial air pollution emissions[7] and a notable odor normally accompanies the presence of a refinery. Aside from air pollution impacts there are also wastewater concerns,[3] risks of industrial accidents such as fire and explosion, and noise health effects due to industrial noise.
The public has demanded that many governments place restrictions on contaminants that refineries release, and most refineries have installed the equipment needed to comply with the requirements of the pertinent environmental protection regulatory agencies. In the United States, there is strong pressure to prevent the development of new refineries, and no major refinery has been built in the country since Marathon's Garyville, Louisiana facility in 1976. However, many existing refineries have been expanded during that time. Environmental restrictions and pressure to prevent construction of new refineries may have also contributed to rising fuel prices in the United States.[8] Additionally, many refineries (over 100 since the 1980s) have closed due to obsolescence and/or merger activity within the industry itself. This activity has been reported to Congress and in specialized studies not widely publicised.
Environmental and safety concerns mean that oil refineries are sometimes located some distance away from major urban areas. Nevertheless, there are many instances where refinery operations are close to populated areas and pose health risks such as in the Campo de Gibraltar, a Spanish state owned refinery near the towns of Gibraltar, Algeciras, La Linea, San Roque and Los Barrios with a combined population of over 300,000 residents within a 5 mile radius and the CEPSA refinery in Santa Cruz on the island of Tenerife, Spain[9] which is sited in a densely-populated city center and next to the only two major evacuation routes in and out of the city. In California's Contra Costa County and Solano County, a shoreline necklace of refineries and associated chemical plants are adjacent to urban areas in Richmond, Martinez, Pacheco, Concord, Pittsburg, Vallejo and Benicia, with occasional accidental events that require "shelter in place" orders to the adjacent populations.
History.
The world's first oil refineries were set up by Ignacy Łukasiewicz near Jaslo, Austrian Empire (now in Poland) in the years 1854-56[10][11] but they were initially small as there was no real demand for refined fuel. As Łukasiewicz's kerosene lamp gained popularity the refining industry grew in the area.
The first large oil refinery opened at Ploieşti, Romania in 1856.[12] Several other refineries were built at that location with investment from United States companies before being taken over by Nazi Germany during World War II. Most of these refineries were heavily bombarded by US Army Air Forces in Operation Tidal Wave, August 1, 1943. Since then they have been rebuilt, and currently pose somewhat of an environmental concern.
Another early example is Oljeön, now preserved as a museum at the UNESCO world heritage site Engelsberg. It started operation in 1875 and is part of the Ecomuseum Bergslagen.
At one time, the world's largest oil refinery was claimed to be Ras Tanura, Saudi Arabia, owned by Saudi Aramco. For most of the 20th century, the largest refinery of the world was the Abadan refinery in Iran. This refinery suffered extensive damage during the war Iran-Iraq war. The world's largest refinery complex is the "Centro de Refinación de Paraguaná" (CRP) operated by PDVSA in Venezuela with a production capacity of 956,000 barrels per day (Amuay 635,000 bpd, Cardón 305,000 bpd and Bajo Grande 16,000 bpd). SK Corporation's Ulsan refinery in South Korea with a capacity of 840,000 bpd and Reliance Petroleum's refinery in Jamnagar, India with 660,000 bpd are the second and third largest, respectively.
Early US refineries processed crude oil to recover the kerosene. Other products (like gasoline) were considered wastes and were often dumped directly into the nearest river. The invention of the automobile shifted the demand to gasoline and diesel, which remain the primary refined products today. Refineries pre-dating the EPA were very toxic to the environment. Strict legislation has mandated that refineries meet modern air and water cleanliness standards. In fact, obtaining a permit to build even a modern refinery with minimal impact on the environment (other than CO2 emissions) is so difficult and costly that no new refineries have been built (though many have been expanded) in the United States since 1976. As a result, some believe that this may be the reason that the US is becoming more and more dependent on the imports of finished gasoline, as opposed to incremental crude oil. On the other hand, studies have revealed that accelerating merger activity in the refining and production sector has reduced capacity further, resulting in tighter markets in the United States in particular
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