Iran’s crude oil reserves and production

Iran is a major producer in the Organization of Petroleum Exporting Countries (OPEC) and was one of its founding members when it was formed in 1960. With an average production of about 4.1 million barrels of crude oil per day (Mb/d) in 2005 (Figure 1 and Table 1), Iran supplies approximately 5% of the world’s oil production of 81.1 Mb/d, and 12% of OPEC’s production of 33.8 Mb/d (BP, 2006; quantities include natural gas liquids – NGL and oil from unconventional sources). In mid-2004, the country reported that its proved remaining recoverable crude oil and condensate reserves were about 132.5 billion barrels (Gb) or about 11.3% of the world’s reported proved oil reserves of 1,200 Gb for end-2005 (BP, 2006). The estimated proved remaining crude oil reserves are about 108 Gb, and consist of both primary and secondary reserves (Table 2).

At the June 2006 OPEC meeting in Caracas, Venezuela, Iran’s Petroleum Minister, K. Vaziri-Hamaneh, stated that the country planned to raise oil production to 4.6 Mb/d by 2009 (Middle East Economic Survey - MEES, 5 June 2006). It should be recognized, however, that such an increase represents a significant challenge because it has to overcome a production decline rate in the maturing fields of 300–400,000 (Kb/d) according to former Iranian Petroleum Minister, B. Zanganeh (MEES, 1 August 2005), or as much as 500 Kb/d according to the current Petroleum Minister Vaziri-Hamaneh (MEES, 18 September 2006). The production decline rate is not irreversible and is being overcome with infill drilling, recompletions, enhanced and improved oil recovery (e.g. gas injection programs) in many mature fields. Moreover, to achieve this 12% production capacity expansion, Iran is bringing on-stream several undeveloped fields and reservoirs.

Table 1 lists Iran’s estimated crude oil production capacity by field (Figure 2) for:

• April 2004 (Arab Petroleum Research Centre – APRC, 2005);

• end of 2005 (MEES, 13 February 2006);

• end of 2010 and end-2015 (assuming current production rates).

The planned production capacity increases are compiled from various sources and assume no delays in completing the projects (MEES, 13 February and 19 June 2006; McDonald, 2006; Petroleum Review, 2006; OPEC website). Production from the undeveloped Azadegan field (260 Kb/d after 2008, McDonald, 2006) and Kushk Hosseinieh field (300 Kb/d after 2008; McDonald, 2006) are shown as completed by 2010. The 100 Kb/d from the Azar field (announced as commercial in 2006, MEES, 19 June 2006) and 300 Kb/d from Yadvaran field (planned for 2012 or later, but may only be 180 Kb/d, Associated Press in Gulf News, 18 February, 2006) are shown in 2015. Also listed in Table 1 are the specific gravities for the oils in API units (as reconciled between various sources including: Beydoun, 1988; Alsharhan and Nairn, 1997; APRC, 2005; MEES, 13 February 2006; McDonald, 2006).

This article reviews the crude oil and condensate reserves (Tables 2 and 3) and oil production capacities in the main fields and reservoirs of Iran (Table 1), and the country’s overall production history (Figure 1). It first clarifies the nomenclature and stratigraphy of Iran’s fields (Figures 3 and 4), and then explains the sources of the database (Tables 1 – 16). One objective of this article is to provide a quantitative data base of Iran’s reserves and production that illustrates the relationships between initial-oil-in-place (IOIP), estimated ultimate recoverable reserves (EURR), remaining primary and secondary reserves (PRR, SRR), total remaining reserves (TRR), reserves growth, cumulative production (CP), recovery factor (RF), decline rates and production. A second objective is to show the relative importance of the reserves and production from the Asmari reservoir in Iran’s four supergiant fields (Agha Jari, Ahwaz, Gachsaran and Marun; Figure 2).

The onshore reservoirs in Iran are named after formations and groups in which they occur, as shown in Figure 3 (Stöcklin and Setudehnia, 1972; Szabo and Kheradpir, 1978; NIOC, 1998). The offshore reservoirs are named after either Iranian or Arabian formations (Figure 4). Alsharhan and Nairn (1997) provide a comprehensive review of the petroleum systems covering the reservoirs, seals, source rocks and oil types.

Tables 2 and 3 provide an overview of the distribution of oil and condensate by field and reservoir, indicating a total crude oil in-place (IOIP) of about 600 Gb and condensate in-place (ICP) of about 32 Gb. The Asmari and Bangestan reservoirs are found in many fields and account for about 260 Gb and 150 Gb, respectively, representing approximately 43% and 25% of initial-oil-in-place. The main reservoirs are briefly discussed in the following sections.

The Asmari Formation contains the most prolific and productive reservoir, holding some 43% of IOIP. Table 4 shows the relative importance of the Asmari reservoir in those fields having IOIP of in excess of one billion barrels. The four supergiant fields, namely Gachsaran, Marun, Agha Jari and Ahwaz, contain about 152 Gb, or 60% of the Asmari-reservoired IOIP, and about 25% of the country’s total. Nine more giant fields, each containing more than 5 Gb initial-oil-in-place, represent another 30% of Asmari-reservoired IOIP; namely Bibi Hakimeh, Parsi, Rag-e-Safid, Ramin, Karanj, Haft Kel, Pazanan, Masjid-e-Sulayman and Kupal.

The recovery factor (RF = EURR/IOIP) for the Asmari reservoir varies from 64% in Ahwaz field to 8% in Kilur field (Table 4). Very high recovery factors are also noted in Agha Jari (58% including the Bangestan reservoir), Marun and Mansouri (47%) fields. High recovery factors (30–40%) characterize the Cheshmeh-Kosh, Gachsaran, Lab-e-Safid, Parsi and Ramshir. Recovery factors of less than 30% are found in the Abu Zar, Ghalehnar, Haft Kel, Masjid-e-Sulayman and Pazanan fields.

According to Alsharhan and Nairn (1997), the Asmari Formation in the Khuzestan Province (Figure 2) consists of wackestone and packstone, ranging in thickness from 320–488 m (1,050–1,600 ft), of which 10–280 m (33–918 ft) comprise effective reservoirs. Evaporites of the Gachsaran Formation provide an overlying seal (Figures 3 and 4). The reservoir generally has a low primary porosity of less than 5%; but as much as 25% secondary porosity due to fracturing. The average permeability is about 10 mD but can reach 100 mD in fractured zones.

To the north of the Gulf, the Ahwaz Formation contains sandstone layers that significantly improve the porosity, permeability and recovery factor. The improvement is well illustrated by the very high recovery factor of 64% for the Asmari sandy reservoir in Ahwaz field (Table 4), which is made up of eight sandstone and six carbonate layers (Schlumberger, 2003). The production (700–800 Kb/d, Table 1) comes mainly from 200 wells producing from the Asmari sandstone layers, which have a high porosity and permeability and act as conduits for fluid flow. The Asmari carbonates, by contrast, have low porosity and permeability and act as barriers. The Asmari reservoir in Marun field also contains sandstone layers (Beydoun, 1988) and has a high recovery factor of 47%.

The second most prolific and productive zone is the Cretaceous Bangestan Reservoir (Table 2). It is found in two formations that sometimes contain separate reservoirs. The older Sarvak reservoir is found in the Albian-Turonian Sarvak Formation (= Arabian Wasia Group, Figure 4). The younger Ilam reservoir is found in the Santonian-Campanian Ilam Formation (= lower part of the Arabian Aruma Formation or sometimes Aruma Group, Figure 4).

A number of confusing issues of nomenclature are to be noted. The Bangestan Reservoir should not be confused with the Albian-Campanian Bangestan Group consisting of the Kazhdumi, Sarvak, Surgah and Ilam formations (Figure 3). In some fields, the Kazhdumi Formation consists of sandstones and is separately reported as a reservoir by this name although it is part of the Bangestan Group. In other fields, the Kazhdumi is replaced by the correlative Burgan reservoir of Iraq and Kuwait, the Khafji and Safaniya reservoirs of Saudi Arabia and the Nahr Umr (Nahr-e-Umr) reservoir of Oman (Figure 4).

The Bangestan reservoir contains large amounts of initial-oil-in-place in several of the fields listed in Table 2. In general, the recovery factors range between 20% and 30%. The Ahwaz field has the largest amount of initial-oil-in-place at about 37.6 Gb, with a recovery factor of 20%, being followed by Azadegan (22.3 Bb, 18.4%), Mansouri (18.5 Bb, 17.6%) and Ab-Teymour (9.0 Gb, 29%). But the Bangestan reservoir is not as prolific as the Asmari reservoir in the supergiant Agha Jari and Marun fields, containing about 2.3 Gb and 3.0 Gb, respectively.

According to Alsharhan and Nairn (1997), the Bangestan reservoir consists of massive, shallow-marine limestones. The gross and net thickness range of the reservoir are 220–980 m (722–3,214 ft) and 70–630 m (230–2,066 ft). The Bangestan reservoir has a porosity range of 4–15%. The older Sarvak Formation consists of a lower argillaceous limestone, grading upwards into massive microporous limestone and nodular chert. The porosity of between 7–14% is due to fissuring, and the gross and net thickness range from 24–790 m (79–2,591 ft) and 5–285 m (16–935 ft). The Ilam Formation consists of argillaceous limestone and shale with porosity of 9–20%, also due to fissuring, while gross and net thicknesses range from 25–170 m (82–558 ft) and about 110 m (361 ft), respectively.

Numerous other less prolific reservoirs are listed in Tables 2 and 3, and are described by Alsharhan and Nairn (1997). Only a few additional comments are called for.

The Ghar Formation is a lateral equivalent of the Asmari Formation (Alsharhan and Nairn, 1997) and contains oil in, for example, Abuzar and Bahrengansar fields. The Guri and Razak formations also partly correlate with the Asmari Formation. The underlying Paleocene-Eocene Jahrum and Pabdeh formations also locally contain reservoirs (Figure 3, Tables 2 and 3).

The youngest Cretaceous reservoir in Iran is found in the Maastrichtian Gurpi Formation, and it is developed as a separate reservoir in, for example, Azadegan field. Below the Gurpi Formation, the undifferentitated Khami reservoir takes its name after the Jurassic-Lower Cretaceous Khami Group (Figures 3 and 4). In most fields however the individual reservoirs of this age are cited separately (in alphabetical order: Arab, Dariyan or Darivan, Fahliyan, Gadvan, Hith, Manifa, Ratawi, Shu’aiba, Surmeh, Thamama and Yamama). The so-called “Dictioconous” reservoir of the Nowruz field has not been described in the literature but is probably of Early Cretaceous age. The Khalij reservoir, which contains condensate reserves in the Agha Jari and Milaton fields, has also not been described in the literature but is probably of middle Cretaceous age.

Most of the gas and condensate reserves (Table 3) are found in the Permian-Triassic Deh Ram (Dehram) Group. In ascending order, it comprises the Faraghan clastics and Dalan carbonates/evaporites of the Permian, and the Kangan carbonates of the Lower Triassic. The Upper Dalan Member (above the middle Nar Anhydrite Member) and Kangan Formation represent the most significant reservoirs for non-associated gas and condensate, being correlative with the Khuff A, B and C reservoirs of Saudi Arabia (Alsharhan, 2006; Insalaco et al., 2006). In some fields, the Triassic Dashtak Formation is shown to contain gas and condensates.

Table 5 lists Iran’s cumulative production (CP), remaining total proved reserves (TRR) and estimated ultimate recoverable reserves (EURR) since 1974. The remaining and ultimate recoverable include condensates, which account for about 24 Gb (Table 3). To illustrate some of the confusion in the literature in regards to reporting reserves, four examples are illustrated here and shown in Table 5.

1. Hemer and Pickford (1984) reported that according to Iran’s National Energy Committee, the estimated crude oil reserves (which could be produced through primary recovery methods) were 48.0 Gb in 1983; but this quantity is 7.3 Gb less than the 55.3 Gb reported for 1983 by Iran (in OPEC, 1994).

2. Beydoun (1988) reported that Iran’s crude oil reserves were 49.0 Gb in 1987; but this quantity is substantially less than the 92.9 Gb reported for 1986 by Iran (in OPEC, 1994).

3. Alsharhan and Nairn (1997) reported Iran’s ultimate recoverable crude oil reserves (EURR) are 59.0 Gb; but this is less than half of the EURR for 1996 (133.8 Gb), and more likely to reflect the total remaining reserves in the mid-1980s.

4. In 1997, according to APRC (1999), Petroconsultants (now IHSE) reported total remaining reserves as 78.6 Gb compared to Iran’s reported 93.0 Gb.

Table 5 shows that Iran’s official EURR (cumulative production + estimated proved total remaining reserves) of crude oil and condensate have more than doubled from about 86.2 Gb to 189.4 Gb in the past 30 years. A major source of this reserves growth is due to improved (IOR) and enhanced recovery (EOR) in mature fields, and to a lesser extent exploration. For example, in 2003, Iran’s Ministry of Petroleum reported that the total reserves of oil and condensate at end-2002 stood at 130.8 Gb, and represented a growth of about 35% over the end-1999 reserves. For this 3-year period (2000–2002), Iran reported net reserves growth of 33.5 Gb and 5.1 Gb from newly discovered fields, and production as 4.3 Gb (average of 3.9 Mb/d). The reserves growth are largely due to IOR and EOR projects and approximately reflected by the secondary remaining reserves in Table 2. In some oil field practices reserves growth due to IOR and EOR are not considered as proved until a pilot project confirms the additional commercial recoveries.

In support of the 2002 reassessment of its reserves, Iran’s Ministry of Petroleum submitted a document to OPEC that estimated the remaining recoverable oil and condensate reserves in all of its oil and gas fields as of the end of 1999 (reproduced in MEES, 24 November, 2003). In the submission, the post-1999 reserves were reported for those fields that provided the additions (reproduced in MEES, 1 December, 2003; APRC, 2005). The oil and condensate fields are listed in Tables 2 and 3 in alphabetical order (column 1). The reservoirs (column 2) are listed in increasing stratigraphic age (Figures 3 and 4). Some reservoirs are sometimes reported individually (e.g. Asmari), while others correspond to several reservoirs (e.g. Bangestan reservoir consisting of the Ilam and Sarvak reservoirs; or Khami consisting of several Jurassic-Lower Cretaceous reservoirs such as the Fahliyan reservoir, Figures 3 and 4).

By combining the information from the Iranian Government’s report (MEES, 24 November and 1 December 2003; APRC 2005), Table 2 shows for crude oil:

• Column 3: Initial-oil-in-place (IOIP) at the end of 1999;

• Column 4: Initial-oil-in-place (IOIP) at the end of 2002;

• Column 5: Estimated ultimate recoverable reserves (EURR) at the end of 1999;

• Column 6: Estimated ultimate recoverable reserves (EURR) at the end of 2002;

• Column 7: Primary remaining reserves (PRR) at the end of 1999;

• Column 8: Secondary remaining reserves (SRR) at the end of 1999 (SRR-99);

• Column 9: Total remaining reserves (TRR) at the end of 1999.

Table 3 provides similar data for condensates. In MEES (24 November 2003) no reserves are reported by individual field for:

• (1) Onshore developed fields that had less than 50 Mb (shown as 5 Mb in MEES) of crude oil (TRR = 522.3 Mb);

• (2) Onshore undeveloped fields that had less than 50 Mb of crude oil (TRR = 525.8 Mb);

• (3) Offshore developed fields that had less than 50 Mb of crude oil (TRR = 320.8 Mb);

• (4) Offshore undeveloped fields that had less than 50 Mb of crude oil (TRR = 129.7 Mb);

• (5) Onshore developed gas fields with less than 50 Mb of condensate (TRR = 92.9 Mb).

Tables 2 and 3 also show, where the reported information permits computation:

• Column 10: Cumulative production (CP) at the end of 1999 (subtracting the TRR from the EURR);

• Column 11: Recovery factor (RF) computed at the end-2002 (100xEURR/IOIP);

• Column 12: Percentage of EURR produced at the end of 1999 (100xCP/EURR of 2002);

• Column 13: Percentage of IOIP produced at the end of 1999 (100xCP/IOIP of 2002).

The year 2008 will mark the Centenary since the first discovery of oil in the Asmari Formation in the Masjid-e-Sulayman field in Iran (Figure 2). This field was not only the first discovery of oil in the Middle East, but also turned the attention of worldwide exploration from sandstone to carbonate reservoirs (Schlumberger, 2003). Masjid-e-Sulayman started producing oil in 1913 at a rate of 5 Kb/d. By 1927 its production had reached 100 Kb/d, and probably continued to account for most of Iran’s production until about 1930. It was still in production in 2005 at the rate 4.5 Kb/d, and by end-2006 will have produced a total of 1.11 Gb from an estimated initial-oil-in-place of 6.63 Gb. With an enhanced oil recovery (EOR) development project underway, production is scheduled to rise to 20 Kb/d in the near future.

Another five fields were discovered in the years from 1928 to 1939, when World War II started, comprising Neft-e-Shar in 1927, Gachsaran and Haft Kel in 1928, Agha Jari in 1936 and Lali in 1938. Production continued to climb steadily until just before World War II when it reached about 214 Kb/d (Figure 1), but then declined during the war to a low of about 139 Kb/d in 1941. It recovered after the war to 664 Kb/d in 1950, but then declined between 1951 and 1955 as a result of the 1952 Revolution and embargo, falling to a low of 27 Kb/d in 1952. No new giant fields were discovered in the period 1946 to 1952. In summary, Iran’s production between 1913 and 1952 can be characterized by two peaks (1938 and 1950) and two valleys (1941 and 1952).

Crude oil production increased systematically from the low of 27 Kb/d in 1952 to the peak of 6.02 Mb/d in 1974 (Figure 1). Production increased 6-fold from 1959 to 1974, rising by about 1.0 Mb/d every 2–3 years, and remained at a high rate until the revolution of December 1979 and the nationalization of the industry, when it fell to 3.17 Mb/d (Figure 1). The start of the Iran-Iraq War in September 1980, less than a year after the 1979 Revolution, had a further impact with production dropping to 1.57 Mb/d (Figure 1). The war damaged refineries, terminals, petrochemical complexes and, in particular, the main shipping facility at Kharj Island (Figure 2). Exports came to a near standstill by September 1980 and by the end of the year had recovered to no more than 350 Kb/d, compared to nearly 4.0 Mb/d in 1974. But production rose in 1981 to 1.33 Mb/d with exports ranging between 600 Kb/d to 1.3 Mb/d.

The history of production from 1974 to 1978 shows that the decline commenced after 1974 and was not entirely due to the events of 1979 and 1980 (Figure 1 and Table 6). In 1975 it fell by 672 Kb/d to 5.35 Mb/d. It reached a second peak of 5.88 Mb/d in 1976, before declining to 5.24 Mb/d in 1978. This decline occurred despite a sharp rise in oil price from $2.50 to $10.0 per barrel in 1974 and $40 per barrel in 1979, and despite the Government’s desire to increase production.

Iran’s production between 1959 and 1978 is reported by field in the literature. It shows that production from the Bangestan reservoir in the Lali field (Figure 2, IOIP = 737 Mb), which went on stream in 1948 and was producing 15 Kb/d in 1959, had ceased production by 1973. Production from another three giant fields systematically declined between 1959 and 1978 (Table 6): Haft Kel (150 to 4 Kb/d; IOIP = 8.6 Gb), Masjid-e-Sulayman (45 to 8 Kb/d; IOIP = 6.6 Gb) and Neft-e-Safid (54 to 30 Kb/d; IOIP = 3.0 Gb) (Figure 2).

Another ten giant fields attained peak production between 1971 and 1976 followed by declines (Figure 2 and Table 6). In alphabetical order these are:

1. Agha Jari (IOIP = 30.2 Gb) production attained a peak of just over 1.0 Mb/d in 1973 when it represented 20% of Iran’s annual production. By 1978 production had declined by 46% to 638 Kb/d.

2. Bibi Hakimeh (IOIP = 17 Gb) production attained a peak of 446 Kb/d in 1971 when it represented 10% of Iran’s annual production. The production maximum occurred 8 years after it went on stream and then declined by 45% to 245 Kb/d in 1978.

3. Binak (IOIP = 3.3 Gb) production attained a peak of 55 Kb/d in 1974, 8 years after it went on stream. Production then declined to between 32–45 Kb/d in 1975–1977 but went back up to 54 Kb/d in 1978.

4. Doroud (also Kharj; IOIP = 14 Gb) production attained a peak of 73 Kb/d in 1973 – 10 years after it went on stream, and then declined by 38% to 48 Kb/d in 1978.

5. Gachsaran (IOIP = 53.4 Gb) production attained a peak of about 922 Kb/d in 1974 when it represented 18% of Iran’s annual production. By 1978 production had declined by 17% to 767 Kb/d.

6. Karanj (IOIP = 10.4 Gb) production attained a peak of 297 Kb/d in 1974 – 11 years after it went on stream, and then declined by 12% to 260 Kb/d in 1978.

7. Marun (IOIP = 49.7 Gb) production attained a peak of 1.341 Mb/d in 1976, 12 years after it went on stream. In 1976 it accounted for 23% of Iran’s annual production. By 1978 production had declined by 5% to 1.278 Mb/d in 1978.

8. Parsi (also Faris or Paris; IOIP = 12.3 Gb) production attained a peak of 451 Kb/d in 1973 – 8 years after it went on stream, and then declined by 40% to 267 Kb/d in 1978.

9. Pazanan (IOIP = 7.6 Gb) production attained an early maximum in 1966 at 76 Kb/d just four years after start-up, then declined throughout 1968–1976 before returning to 81 Kb/d in 1978.

10. Rag-e-Safid (IOIP = 18.7 Gb) attained a peak of 289 Kb/d in 1974 – 9 years after it went on stream, and then declined by 43% to 164 Kb/d in 1978.

Of the ten fields for which the start-up year is known (Table 6), peak production occurred between eight and sixteen years after the field went into production. The production declines ranged between 38–46% in five of the fields between peak year and 1978. The decline in the Binak Field from 1974 to 1975 was anomalously steep (from 55 to 32 Kb/d) but it recovered to a near-maximum rate of 54 Kb/d in 1978. For the two supergiants, Marun and Gachsaran, the combined production drop was 224 Kb/d representing relatively shallow declines of 5% and 17%, respectively.

Only the supergiant Ahwaz field shows a systematic increase in production, climbing from about 6 Kb/d in 1960 to more than 1.1 Mb/d in 1978 when it represented 20% of the country’s total production (Table 6). The fields in Table 6 are grouped to show their relative contributions in terms of three production ranges: (1–6) 45–160 Kb/d; (7-10) 160–450 Kb/d; (11–14) the four supergiants (Agha Jari, Ahwaz, Gachsaran and Marun). The 14 fields together, consistently produced more than 88% of the country’s total production in the 1960s and 1970s, with the four supergiants accounting for 64–85%. The next rank of fields (Bibi Hakimeh, Karanj, Parsi, Rag-e-Safid) accounted for another 17–23% of total production during the 1970s.

In summary, about 90% of the country’s production during the 1953–1978 period came from only fourteen fields (Table 6). The peak of 6.0 Mb/d in 1974 was achieved largely by the start-up of three supergiant fields in the 1960s (Ahwaz, Gachsaran and Marun), which together with Agha Jari accounted for about two-thirds of the total production in the 1970s. Production from all but three of the fourteen fields (Ahwaz, Binak and Pazanan), however, had decreased by 1978, prior to the 1979 Revolution and 1980–88 Iran-Iraq War. It seems evident that the decline was mainly imposed by natural decline and the physics of the reservoirs.

Since 1982, Iran has built-up its crude production capacity steadily, passing 3.0 Mb/d in 1990. As of the start of 2006, MEES (13 February 2006) estimated Iran’s installed crude production capacity was just less than 4.2 Mb/d (Table 1). In 2005 Iran’s daily production was about 4.1 Mb/d, with exports of about 2.5 Mb/d. The four supergiant fields provided about half of total production (Table 6).

Table 6 shows the 2005 production capacity of the main fields developed in the 1970s, as well as current capacity as a percentage of peak rate. Only the offshore Doroud field shows an increase from 48 Kb/d in 1978 to 130 Kb/d in 2005, and a further expansion to 220 Kb/d is planned (Table 1). Fields that are producing at rates that are comparable to their peak 1970s levels are Binak (91%), Pazanan (86%) and to a lesser extent Ahwaz (77%) and Rag-e-Safid (66%).

Gachsaran field is apparently producing at about 61% of its peak level, but as discussed below may infact be producing less. Apart from the six fields noted above, the remaining fields that were contributing significantly to 1970s production are producing at between 20–50% of their peak levels. Of the fields noted in Table 6, six are planned for increased production (Table 1; Ahwaz-Bangestan, Doroud, Masjid-e-Sulayman, Parsi, Pazanan and Rag-e-Safid).

Production profiles of the four supergiant fields are evaluated below on the basis of physical parameters, based on published sources, including reports by the Ministry of Petroleum (in APRC, 2005 and MEES, 24 November and 1 December 2003), which have been compared with previous published estimates (e.g. Burke and Gardner 1969, inKamen-Kaye, 1970; AAPG, 1960–1979; Beydoun, 1988; IEA, 1995; Petroleum Economist, 1996; Christian, 1997; IHSE inMann et al., 2003). The approximate production profile and end-2006 status for each field is estimated by using several independent sets of data, including production rates when available (e.g. for 1959–1978 from AAPG; for 1994-2005 from OPEC in APRC; for 2005 from MEES, 13 February 2006) giving a good review of production over an extended period of time. A second data set is cumulative production (e.g. for mid-1978 from Beydoun; for 1997 from NIOC), which gives average production rate for the period 1978–1997. The third independent data set is the cumulative production for end-1999 as calculated from Iran’s reported estimated ultimate recoverable reserves (EURR) and total remaining reserves for 1999.

According to Beydoun (1988) the Asmari and Sarvak reservoirs in Agha Jari field were discovered in 1936 and 1956, respectively (Figures 2-4). The trap is an elongated NW-trending anticline that is about 56 x 6 km in area (NIOC, 1998) and has a strong surface expression that is 22 x 5 km in area (Beydoun, 1988). The primary Asmari reservoir is at a depth of about 760 m (2,500 ft) (Alsharhan and Nairn, 1997). The formation is more than 457 m (1,500 ft) thick and the average porosity is 7.6%. (Alsharhan and Nairn, 1997). The secondary Sarvak reservoir is at a depth of about 2,000 m (6,560 ft) and has a thickness of 915 m (3,000 ft) (Beydoun, 1988) and a porosity of 5.0–9.5% (NIOC, 1998).

Although they are separated by 670 m (2,197 ft) of tight strata, Alsharhan and Nairn (1997) reported that the Asmari and Sarvak reservoirs appear to be in communication. As an example for the evidence for communication, they cite the equal pressure drops measured in two wells that are 12 km apart. The communication is also supported by the common specific gravity of the Asmari and Sarvak oils (34.6° API) and similar H₂S content of 1.42% and 1.38% (Beydoun, 1988; Alsharhan and Nairn, 1997).

The Asmari reservoir in Agha Jari field went on stream in 1945 with individual wells producing as much as 40 Kb/d (Beydoun, 1988). In 1956, production started from the Sarvak reservoir. By 1959 production was about 600 Kb/d and accounted for nearly 65% of Iran’s total production (Table 6). Production climbed rapidly after 1960 reaching a peak of 1.023 Mb/d in 1973 after which it decreased to about 640 Kb/d in 1978 (Tables 6 and 7). NIOC (1998) reported that due to the thinning oil column, production was decreased to 120 Kb/d (unspecified year but probably in 1979; Table 7) resulting in the oil column increasing from 400 to 700 ft.

Some reported production rates are as follows:

• 340 Kb/d for 1993 (APRC, 1994);

• 250 Kb/d for 1994–1995 (APRC, 1995, 1996; IEA, 1995);

• 190 Kb/d for 1997–2004 (APRC, 1999–2005; NIOC, 1998);

• 200 Kb/d at the start of 2006 (MEES, 13 February 2006).

• M. Lynch (2006) quoted recent reports that estimate production at 180 Kb/d in February 2006 from 165 wells, and down from 195 Kb/d in 2001.

At the end of 1997, NIOC (1998) reported that a total of 161 wells were drilled in the field: 137 in the Asmari, 7 in the Sarvak and one in the deeper Khami reservoir. Only four of the eight deeper wells produced oil. At the end of 1997, 73 wells were on stream and each produced about 2 Kb/d (total 189.8 Kb/d as consistent with cited production rate of 190 Kb/d for 1997). The average productivity index is 600 barrels/day/psi and the gas/oil ratio is 650 cubic feet/barrel. In 1997, the main drive mechanism was the gas-cap expansion, which provided 70% of the pressure support, with the balance coming from natural water drive (> 20%) and rock and fluid expansion.

Beydoun (1988) reported that by mid-1978 the field had produced 6.86 Gb. NIOC (1998) reported that cumulative production as of end-1997 was 8.4 Gb from the Asmari and 340 Mb from the Sarvak, for a total of 8.74 Gb. Thus, a total of 1.88 Gb was produced for the period from mid-1978 to 1997 (total 19.5 years) giving an average 265 Kb/d for the interval. In Table 7 the production history is constructed from the cumulative production reported for end-1997 (NIOC, 1998) and mid-1978 (Beydoun, 1988), respecting the maximum of 250 Kb/d as reported for 1994 (APRC, 1995; IEA, 1995).

The IOIP in Agha Jari field is reported variously as 31 Gb (IEA, 1995) or 28 Gb (Petroleum Economist, 1996). In 2002, Iran (in MEES, 24 November 2003; APRC, 2005) estimated IOIP as 30.2 Gb (Table 8).

The ultimate recovery from Agha Jari field is variously reported at 9.5 Gb (Burke and Gardner, 1969, inKamen-Kaye, 1970; Christian, 1997), or 8.7 Gb (Beydoun, 1988), or 5.76 Gb (Mann et al. 2003, based on IHSE data base).

The National Iranian Oil Company is planning a secondary recovery program for Agha Jari field that involves injecting gas at a rate of 1.8 BCF/day from the North and South Pars fields (NIOC, 1998; APRC, 2004). Simulation studies by NIOC estimate that the injection of 20 TCF could result in the recovery of an additional 5.0 Gb of crude oil. According to official reports in 2002, the estimated recovery from the undifferentiated Asmari and Bangestan reservoirs has increased from 15.6 to 17.4 Gb (MEES, 1 December 2003; APRC, 2005).

According to NIOC (1998) cumulative production through 1997 was 8.74 Gb. Assuming that production from end-1997 to end-1999 (2 years) averaged 190 Kb/d, that would add 139 Mb, giving cumulative production through 1999 at 8.88 Gb. This estimate is confirmed by subtracting reported reserves of 6.7 Gb from ultimate recovery of 15.6 Gb, which amounts to 8.9 Gb. Additionally, APRC (2005) reported that some 8.9 Gb has been produced without specifying the reference year. Assuming the production for 2000–2006 (7 years) also averaged 190 Kb/d (Table 7), then about another 485 Mb of production would bring cumulative production in 2006 to about 9.4 Gb. It means that 54% of the ultimate recovery has been produced, and about one-third of the oil-in-place has been extracted.

The Agha Jari field has about 30.2 Gb of initial-oil-in-place, of which more than 90% is in the Asmari reservoir, and it is about 54% depleted. Production peaked in 1973 at about 1.0 Mb/d and the field has been producing at about 20–25% of the peak rate for the past thirty years. Annual production since the 1980s relative to the IOIP and EURR is 0.25% and 0.40%, respectively. The recovery factor at 57.6% is relatively high compared to other fields. The primary reserve-to-production ratio is approximately 14 years, but production will last much longer at a declining rate.

The Ahwaz field, which was discovered in 1958 (Beydoun, 1988), lies on an elongated NW-trending anticline about 80 x 10.5 km in extent (Schlumberger, 2003). The Asmari reservoir lies at a depth of 2,485 m (8,150 ft) (Petroleum Economist, 1996; APRC, 2005) and contains 32.6° API oil with 1.5% H₂S (Beydoun, 1988). As noted earlier, it consists of eight sandstone and six carbonate layers (Schlumberger, 2003). The Asmari sandstone layers have high porosity and permeability and provide most of the production.

The Bangestan reservoir (Sarvak + Ilam reservoirs) has an average porosity of 11%. It’s depth is uncertain being variously reported at about 10,000 ft (NIOC, 1998) or 12,000 ft (Petroleum Economist, 1996; APRC, 2005). The specific gravity and sulfur content are also variably reported in the literature. Tables 1 and 10 show the quantities reported by Beydoun (1988): 26° API and 1.3% H₂S for the Sarvak and 29° API and high H₂S for the Ilam, and as reported by NIOC (1998) for the Bangestan: 25.5° API and 3.5% H₂S.

The Bangestan reservoir is divided into the upper Cretaceous (Coniacian-Campanian) Zones A to C in the Ilam Formation, and middle Cretaceous (Cenomanian-Turonian) Zones D to J in the Sarvak Formation. The most productive zones are Zone C (406–560 ft thick), Zone E (1,056 ft thick) and Zone I (490 ft thick). The field also contains oil in the Jurassic-Lower Cretaceous Khami Group.

The field went into production in 1959, and was producing 1.109 Mb/d in 1978 (Hemer et al., 1979). Based on the reported and estimated cumulative production for end-1978 and end-1999 it is estimated that the field produced on average about 1.0 Mb/d between 1979 and end-1999 (Table 9). This estimate is consistent with the IEA (1995) and APRC (1994–1999) reports for the late 1990s of 155–160 Kb/d from the Sarvak (Bangestan) and 800–830 Kb/d from the Asmari. MEES (13 February 2006) estimated the production capacity of Ahwaz field was 700 Kb/d from the Asmari and 155 Kb/d from the Bangestan by early 2006. M. Lynch (2006) quoted recent reports that estimated production from the Asmari and Bangestan as 725 and 125 Kb/d in early 2005, respectively.

MEES (13 February 2006) also shows production from “Ahwaz-Mansouri” of 50 Kb/d (27.5° API) as well as production of 50 Kb/d (27.5° API) from “Mansouri field” with both entries noted for expansion by another 100 Kb/d. APRC (2005, p. 137) shows “Ahwaz-Mansouri” with a production capacity of 60 Kb/d (27.5° API) but does not include “Mansouri field” in their table. In Iran there is no “Mansouri reservoir” (e.g. Figures 3 and 4; Alsharhan and Nairn, 1997). It appears that reference to the “Ahwaz-Mansuri” is confused: it is a duplicate entry in MEES (13 February 2006) and incorrectly named as “Ahwaz-Mansouri” in APRC (2005). A separate field, known as Mansouri (also spelled Mansuri) field, was discovered in 1962 producing primarily from the Asmari reservoir.

In 1998, NIOC reported that 89 wells penetrated the Bangestan reservoir (Ilam and Sarvak formations) and of these 67 were on stream. The Ilam reservoir had about 10 wells, each producing about 1.0 Kb/d on average. The Sarvak wells each produce about 3.0 Kb/d. This would amount to about 181 Kb/d (3,000 x 57 + 1,000 x 10 = 181 Kb/d). But APRC (2005) reported that in 2004 the Bangestan reservoir was producing about 150 Kb/d from 60 wells and that production was expected to drop to 60 Kb/d if no additional enhanced recovery facilities were installed. Plans involve injecting 360 MCF of gas/day from Kabir Kuh field (APRC, 2004).

According to M. Naqavipur, Director of Planning and Integration at NIOC’s Karun Oil and Gas Company subsidiary (MEES, 5 June 2006), NIOC plans to increase the number of production wells in the field to 500 from the current 400. The infield drilling program will be undertaken in addition to a gas reinjection project in the Bangestan reservoir, which is intended to add 65 Kb/d of oil production to the current 155 Kb/d from this reservoir. This project involves drilling 36 production and injection wells, and conducting work-overs on 63 existing wells.

The IEA (1995) reported the initial-oil-in-place for the Bangestan reservoir as 47.2 Gb but this quantity must have included the Asmari reservoir because the Petroleum Economist (1996) reported IOIP as 47.25 Gb for both reservoirs. The official estimate at the end of 2002 was 65.9 Gb (MEES, 24 November 2003, see Table 10).

Burke and Gardner (1969, inKamen-Kaye, 1970) reported an ultimate recovery of 6.0 Gb, whereas Beydoun (1988) reported them as 10.1 Gb of which 75% are in the Asmari reservoir, and the ultimate recoverable gas is about 13 TCF. Mann et al. (2003 based on IHSE data base) reported 13.35 Gb, whereas the official estimate in 2002 revised the estimate up from 19.7 to 25.7 Gb (Table 10).

The field went on-stream in 1959 and had produced nearly 3.0 Gb by end-1978 according to the annual quantities reported in Table 9. This estimate is consistent with the reported 2.78 Gb for mid-1978 by Beydoun (1988). Cumulative production through 1999 is computed at 8.17 Gb and 2.45 Gb for the Asmari and Bangestan (Ilam and Sarvak) reservoirs, respectively, totaling 10.62 Gb. Assuming average production for 2000 to end-2006 (7 years) was 700 Kb/d for the Asmari and 155 Kb/d for the Bangestan, the cumulative production for end-2006 would 9.96 Gb and 2.85 Gb, respectively, and total 12.81 Gb (Table 10).

The Ahwaz field relies mainly on the Asmari Reservoir, which has about 28 Gb of initial-oil-in-place. The sandstone layers account for the high recovery factor of 64%. The Asmari cumulative production as of end-2006 of about 10 Gb represents about 36% of oil-in-place and 46% of ultimate recovery. The primary reserve-to-production ratio is about 17 years. Over the past three decades annual production

relative to the IOIP and EURR was about 1.15% and 1.8%.

There is some confusion in the published literature about this field, which lies on a strongly asymmetrical anticline measuring 25 x 7 km (Beydoun, 1988) at a depth of 3,400 ft (1,036 m) (APRC (2005). The alternative reports concerning the Asmari Reservoir are compared below:

• Discovery: 1928 (Beydoun, 1988; APRC, 2005) or 1937 (Alsharhan and Nairn, 1997; Petroleum Economist, 1996).

• Oil Column: 2,165 m (7,101 ft) (Beydoun, 1988); Thickness: 457 m (1,500 ft) (Alsharhan and Nairn, 1997).

• Oil quality: 31.1° API and 1.7% H₂S (Beydoun, 1988); 32° API and 1.6% H₂S (Alsharhan and Nairn, 1997); 32° API (Petroleum Economist, 1996; APRC, 2005); 31° API (IEA, 1995; MEES 13 February, 2006).

Alsharhan and Nairn (1997) reported that the Asmari average porosity is 9% and that wells in the northwest zone produce higher rates (80 Kb/d) relative to wells in the southwest flank (40 Kb/d). Oil in the deeper Sarvak reservoir (Bangestan Group) and gas in the Khami Group were discovered in 1962 according to Beydoun (1988), or in 1956 according to Alsharhan and Nairn (1997). According to Beydoun (1988), the Asmari and Sarvak reservoirs are in pressure communication, and the Sarvak oil has a gravity of 31.1° API and 1.7% H₂S (Tables 1 and 12).

The production history of Gachsaran field since start-up in 1959 and up to 1978 is shown in Table 11. Beydoun (1988) reported that Gachsaran in 1978 produced on average 743 Kb/d, and had produced 4.45 Gb by mid-1978. Production in the late 1990s and early 2000s ranged between 585–600 Kb/d (IEA, 1995; APRC 1994-1995). In early 2006, production capacity stood at 560 Kb/d according to MEES (13 February 2006). M. Lynch (2006) quoted recent reports that estimate the late 2005 production as just 220 Kb/d, from 300 wells and down from 600 Kb/d in 2002.

The IEA (1995) and Petroleum Economist (1996) reported the IOIP in Gachsaran as 53 Gb. Iran (in MEES, 24 November 2003 and 1 December 2003; APRC, 2005) reported that the IOIP for the Asmari and Bangestan reservoirs is 49.4 and 3.6 Gb.

The ultimate recovery has been estimated at 8.0 Gb (Burke and Gardner, 1969, inKamen-Kaye, 1970), or 8.5 Gb (Beydoun, 1988), or 11.0 Gb (Christian, 1997). According to Beydoun (1988) the ultimate gas reserves are 21 TCF (including the Khami Group). Mann et al. (2003, based on IHSE data base) reported ultimate oil recovery is 11.8 Gb. Official Government reports (MEES, 1 December 2003; APRC (2005) indicated that the ultimate recovery from the two reservoirs increased from 14.6 to 16.2 Gb due to EOR.

Cumulative production through 1999 is calculated to be 8.2 Gb, to which subsequent production at an assumed 560 Kb/d would bring the total for end-2006 to 9.6 Gb in 2006.

The Gachsaran Field has about 53 Gb of initial-oil-in-place of which 93% is in the Asmari reservoir. The recovery factor is 31%. Cumulative production for end-2006 is about 9.6 Gb and accounts for 17.9% of oil-in-place and 59.3% of the ultimate recovery. The primary reserve-to-production ratio is 14 years. Over the past three decades annual production relative to oil-in-place and ultimate recovery was 0.38% and 1.22%.

The Marun field was discovered in 1964 (Beydoun, 1988) reaching the Asmari reservoir at a depth of 2,865 m (9,397 ft) (Petroleum Economist, 1996; APRC, 2005). The lithology of the reservoir is intermediate between the sandy facies of Ahwaz field and the carbonate facies of other fields (Beydoun, 1988). The specific gravity of the Asmari oil is variously reported as follows:

• 33.0° API oil and a high-pressure gas dome (Beydoun, 1988);

• 32.6° API (IEA, 1995);

• 34.0° API (Petroleum Economist, 1996; APRC, 2005);

• 32.0° API (MEES, 13 February 2006).

The Sarvak reservoir contains oil with a gravity of 32° API and a deeper Lower Cretaceous reservoir contains gas (Beydoun, 1988).

The Marun Field went on-stream in 1965 and reached a maximum production level of 1.34 Mb/d in 1974 before declining to 1.28 Mb/d in 1978 (Tables 6 and 13). Reported production rates for the late 1990s and early 2000s range between 500–570 Kb/d (IEA, 1995; APRC 1994-1995). In early 2006 the field had a production capacity of 520 Kb/d according to MEES (13 February 2006) or 500 Kb/d according to M. Lynch (2006).

The IEA (1995) and Petroleum Economist (1996) reported initial-oil-in-place of 52.1 Gb, whereas the official estimates (in MEES, 1 December 2003; APRC, 2005) for the Asmari and Bangestan reservoirs are 46.7 and 3.1 Gb, respectively, giving a total of 49.8 Gb.

The ultimate recovery has been variously reported as 6.0 Gb (Burke and Gardner, 1969, inKamen-Kaye, 1970), or 12.0 Gb (Christian, 1997), or 12.6 Gb (Mann et al. (2003, based on IHSE data base). The official estimate for the Asmari reservoir has increased from 16.0 to 22.0 Gb (in MEES, 1 December 2003) (Table 14). The ultimate recovery from the Bangestan reservoir has not been reported and the total remaining reserves are comparatively small at 231 Mb.

Cumulative production may be calculated at 8.0 Gb by end 1999 from the above figures, implying that production was running at about 520 Kb/d from 1979 to 1999. This latter quantity is similar to the current production capacity of the field (Table 13). If production has continued at this rate since 1999, the end-2006 cumulative production would be 9.3 Gb, amounting to 20% of oil-in-place (Table 14).

Marun field has about 50 Gb of initial-oil-in-place, of which 94% lies in the Asmari reservoir. The recovery factor of the Asmari is 47%. Cumulative production as of end-2006 was about 9.3 Gb, or about 20% of the initial-oil-in-place and 42% of ultimate recovery. The primary reserve-to-production ratio is 21 years. Over the past three decades annual production relative to the initial-oil-in-place and ultimate recovery was 0.38% and 1.23%, respectively.

The apparent reserves growth in the four supergiant fields of Iran is very significant as listed in Table 15. The earliest 1969 estimates of ultimate recovery are from Burke and Gardner (1969, as quoted inKamen-Kaye, 1970) and probably reflect estimates made by the operating international oil companies. The 1988 and 1997 estimates are from Beydoun (1988) and Christian (1997), and are probably from scouting reports by Petroconsultants (now IHSE). The source for 2003 are from Mann et al. (2003) published in AAPG’s Memoire 78 on giant fields. The official Iranian estimates are shown for 1999 and after the 2002 review. Table 15 shows that the 1969 estimates of ultimate recoverable reserves have been significantly exceeded by the cumulative production in the Ahwaz and Marun fields, and matched in Agha Jari and Gachsaran fields. The official estimates of ultimate recoverable reserves for all four fields, reported in 2002, are nearly double those of Burke and Gardner (1969).

Klett and Schmoker (2003) have reported on reserves growth for the world’s giant fields (using Petroconsultants/IHSE data bases) by comparing reported reserves between 1981 and 1996. The quantities they cited for reserves growth in the four fields are shown in Table 16. Also shown are the estimates of reserves growth for the longer period of 1969–1997 (13 years longer) by comparing the quantities reported by Burke and Gardner in 1969 and Christian in 1997. The comparison shows that the total reserve growth for the four fields between 1981 and 1996 (21.5 Gb) is greater by about 25% than that of the longer interval of 1969–1997 (15.5 Gb). The discrepancy between the official estimates and other sources is 30.4–36.4 Gb.

The crude oil production capacity of Iran, assuming the current and planned increases are completed by 2010 and 2015 without accounting for production decline (Table 1), is repeated in Table 17. The following four rows show the impact of subtracting 200, 300, 400 and 500 Kb/d per year, and the final three rows reduce production at a rate of 4%, 5% and 10% per year. Decline rates of 300–400 Kb/d and 500 Kb/d per year were reported by former Iranian Petroleum Minister B. Zanganeh (in MEES, 1 August 2005) and current Iranian Petroleum Minister Vaziri-Hameneh (in MEES, 18 September 2006), respectively.

The resulting production shows that Iran could achieve the country’s targeted 4.6 Mb/d capacity in 2009 if the net production decline rate is in the range of 5%/year or about 200 Kb/d/year. This decline rate would have to be achieved by a combination of infill drilling, recompletions, improved and enhanced recovery in developed fields, and from new production from undeveloped fields and reservoirs.

Considering Iran’s large reserves and the country’s peak production of 6.0 Mb/d in 1974, a 500 Kb/d net increment over three years would appear to be feasible (i.e. 4.1 to 4.6 Mb/d or 167 Kb/d/year in 2007–2009). However, using Hubbert’s Curve, C. Campbell (2006, written communication) predicted that Iran’s future production would be about 3.95 Mb/d between 2010–2030. He based this forecast on an estimate of the ultimate recoverable reserves for crude oil of 140 Gb, of which yet-to-find is 12.2 Gb and remaining reserves were 69.2 Gb for the end of 2005.

It is not clear, however, whether this type of analysis is applicable to Iran’s production because it does not resemble Hubbert’s bell-shaped curve (see review in Al-Husseini, 2006). Instead as seen in Figure 1, it consists of numerous peaks and valleys that were caused by events related to World War II (1939-1945), the early 1950s revolution and embargo, the 1979 Revolution, the Iran-Iraq War of 1980–88 and OPEC quota restrictions. It seems clear, however, that Iran’s oil production peaked in 1974 at 6.0 Mb/d when nearly all of the giant fields ramped-up to very high rates that were not sustainable a few years later (Table 6).

The 1974 peak production level of 6.0 Mb/d could therefore provide an important calibration for Iran’s ultimate recoverable reserves. This is because peak production rate (Mb/d) is approximately equal to .035 multiplied by the ultimate recoverable reserves (Gb). For EURRs of 140 and 168 Gb, the peak production rates are 4.90 and 5.88 Mb/d. The latter quantity is close to the two peaks attained in 1974 at 6.0 Mb/d and in 1978 at 5.88 Mb/d, and suggests that the ultimate recoverable reserves of Iran are in the range of 168 Gb. It is also interesting to note that production rates of 3.8 and 4.6 Mb/d correspond to one percent depletion rates for EURRs of 140 and 168 Gb.

A different approach to forecast Iran’s crude oil capacity was suggested by S.I. Al-Husseini (Oil and Money Conference, September 20-21, 2006, International Herald Tribune, London). He considered several key factors including reported ultimate recoverable and remaining reserves, production history, best-case scenario for enhanced recovery, and the investments required to overcome average decline rates in mature fields. Taking these factors together, he predicted that with sufficient financial investments Iran’s production would range between 3.8–3.9 Mb/d in the next decade but drop to 3.5 Mb/d by 2020.

This article reviewed numerous reports on Iran’s crude oil and condensate volumes (e.g. initial-oil-in-place, estimated ultimate recoverable reserves, etc.) including the most recent official reports (Tables 2 and 3). With reported remaining recoverable crude oil reserves of about 108 Gb in 2004, Iran holds about 10% of the world’s reserves. The main Asmari and Bangestan reservoirs contain about 43% and 25%, respectively, of the total crude oil-in-place of about 600 Gb. Expected recovery factors for the Oligocene-Miocene Asmari reservoir range between about 10–60%, and for the Cretaceous Bangestan reservoir between 20–30%, and reflect fractured reservoirs that are stratigraphically heterogeneous.

About half of Iran’s production comes from four mature supergiant fields that have depleted about half of their ultimate recoverable reserves (Tables 2, 6–14). They contain 25% of Iran’s initial-oil-in-place (Tables 2 and 4) and collectively peaked in 1974 when they were producing 3.9 Mb/d (versus about 2.1 Mb/d in 2005). The decline from 3.9 to to 2.1 Mb/d corresponds to a rate of about 2.0% per year on average.

Iran’s production peaked at 6.0 Mb/d in 1974, and in 2005 averaged about 4.1 Mb/d. The planned increase to 4.6 Mb/d by 2009 has to offset a total annual production decline rate of about 300–500 Kb/d from the maturing giant fields. To achieve this target, Iran has to add about 680 Kb/d/year in 2007–2009 from the developed and undeveloped fields and reservoirs (Tables 1 and 17).

The author would like to thank Hassan Al-Husseini, Colin Campbell and other colleagues for their useful comments.

Moujahed I. Al-Husseini founded Gulf PetroLink in 1993 in Manama, Bahrain. Gulf PetroLink is a consultancy aimed at transferring technology to the Middle East petroleum industry. Moujahed received his BSc in Engineering Science from King Fahd University of Petroleum and Minerals in Dhahran (1971), MSc in Operations Research from Stanford University, California (1972), PhD in Earth Sciences from Brown University, Rhode Island (1975) and Program for Management Development from Harvard University, Boston (1987). Moujahed joined Saudi Aramco in 1976 and was the Exploration Manager from 1989 to 1992. In 1996, Gulf PetroLink launched the journal of Middle East Petroleum Geosciences, GeoArabia, for which Moujahed is Editor-in-Chief. Moujahed also represented the GEO Conference Secretariat, Gulf PetroLink-GeoArabia in Bahrain from 1999-2004. He has published about 30 papers covering seismology, exploration and the regional geology of the Middle East, and is a member of the AAPG, AGU, SEG, EAGE and the Geological Society of London.

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