Iraqi Oil Fields Development: Profiles Of Production, Depletion And Revenue

Published on Wednesday, 22 Dec 16:34 pm

By Ahmed Mousa Jiyad

 

Mr Jiyad is an independent development consultant and scholar and Associate with the Centre for Global Energy Studies (CGES), London. He was formerly a senior economist with the Iraq National Oil Company and Iraq’s Ministry of Oil, Chief Expert for the Council of Ministers, Director at the Ministry of Trade, and International Specialist with UN organizations in Uganda, Sudan and Jordan. He is now based in Norway (Email: mou-jiya@online.no).

 

Introduction

Between November 2008 and May 2010 the Iraqi Ministry of Oil signed 12 long term technical service contracts covering 14 oil fields. The oil field projects fall in two categories: brown-field and green-fields developments. The brown-field projects are Rumaila, West Qurna Phase 1 (WQ1), Zubair and the Misan group (the Buzorgan, Abu Ghirab and Fawqa oil fields). These oil fields are already producing and have relatively a long history of production with good deal of related information. The green-fields are generally discovered, but they are not producing commercially. These are West Qurna-2 (WQ2), Majnoun, Halfaya, Gharaf, Badra, Qayara, Najma, and al-Ahdab. Total proven reserves of these oil fields amounts to 67.929bn barrels, representing 59.1% of Iraq’s currently proven reserves of 115bn barrels. And when they are fully developed according to the contracted timelines and production targets, their total production capacity would reach a peck of 11.815mn b/d, sustained for the six consecutive years 2017-22.

 

For each oil field, annual production over the 20 years of the contract period was calculated according to the plateau production period (PPP) and their relative production plateau target (PPT) as specified in the field’s contract. As for the post-PPP period, annual production was estimated with the officially adopted 5% decline per annum. For the pre-PPP period, annual production was assumed to increase progressively from the 2009 level to PPT.

 

Contracts governing the development of these oil fields are structurally similar but with some major differences, which effectively split them into three types. One type is related to the brown-fields, the second is related to the green-fields, while the third is specific to the Ahdab oil field.

 

Brown-Fields: Rehabilitation, Re/Development And Production Phases

Annual production capacity for all these oil fields progresses through four distinct common phases. The first is rehabilitation phase (ReP), which should not exceed three years from the effective date of the contract. This phase intends to achieve basic objectives: to recapture the decline in the production of the fields; to replace the agreed upon decline in the baseline production of 5% annually; and to attain the 10% increase over the baseline production to ensure the early recovery of invested capital and to receive the remuneration fee (RF) according to the related provisions of the contract. This would be followed by the development/redevelopment phase (D/ReD P), which takes another three years, and is aimed at attaining progressively significant production capacity, leading to the contracted PPT during the PPP phase of seven years. The last phase, the declining production phase (DPP), covers the remaining seven years of the contract period.

 

The following chart illustrates the progression of the annual production for the brown-field projects.

Chart 1: Brown-Field Projects – Rehabilitation, Development Phases And Production Levels, 2010-29

 

Total production of these brown-field projects at end-2009 was 1.593mn b/d and estimated to increase gradually to reach 3.433mn b/d at the end of the rehabilitation period (end-2012), then to accelerate to 6.324mn b/d at the end of 2015 – the end development/redevelopment phase. Plateau production of 6.85mn b/d would last for seven years starting from 2016 to the end of 2022. And according to the officially adopted annual decline of 5% in the post plateau period, annual production declines gradually to 4.784mn b/d in the last year of the contract in 2029, assuming the proven reserves of each individual oil field allow these production rates during the contract period. This later matter will be discussed further below.

 

Green-Field Projects: Development And Production

Unlike the brown-field projects, the green-fields have their own development phases and plateau periods. As the following chart shows, each of the brown-fields have seven years of development phase (DP). The DP starts at 2010, except for Ahdab, which started effectively at end-2008. Plateau periods for the green-fields do not have unified durations as was the case in the brown-fields. The PPP is seven years for Badra, nine years for Qayara and Najma, 10 years for Majnoun and 13 years for each of West Qurna-2, Halfaya and Gharaf. The Ahdab PPP is not available.

 

Chart 2: Green-Field Projects – Development Phases And Production Levels, 2010-29

 

 

As chart 2 shows, total and plateau production from these green-field projects would be obviously affected by the magnitude of West Qurna-2, Majnoun and Halfaya. The plateau production from all the green-fields is 4.965mn b/d, which remains at this level during the PPP of 2017-23, before declining slightly to 4.421mn b/d at the end of 2029.

 

Profile Of Oil Production

Combining oil production from both groups of brown-field (BFTP in charts below) and green-field (GFTP) projects, total production (TP) would increase from approximately 2.168mn b/d in 2010 to reach a plateau level of 11.815mn b/d. According to the contracts, this level of plateau production would be maintained for the period 2017-22 before the declining trend begins, reaching a level of 9.367mn b/d at the end of the contracts period in 2029.

 

During the 20-year period 2010-29 the aggregate contribution of the brown-field and green-field production in total production from both groups of oil fields will be 58.9% and 41.1% respectively. However, during the plateau period the ratios would be slightly different at 58% and 42% respectively. But the contributions of both groups of oil fields become closer at the end of the contract period, at 51% and 49% respectively, indicating the increasing importance of oil production from the green-field developments at the expense of that produced from brown-fields. This is illustrated by chart 3.

 

Chart 3: Composition And Trend Of Total Oil Production, 2010-29

 

 

Alarming Depletion Signals

The comparative profile of total production (TP) accumulated during the contract period 2010-29 in relation to the official 2010 currently proven reserves (CPR) would indicate a full depletion of these reserves by 2029 at most. However, the proven reserves could be depleted even earlier than that date.

 

The currently proven reserves of three oil fields – West Qurna-1, Zubair1 and Gharaf – would not allow the high plateau targets, and thus would be depleted fully even before the end of the contract period. West Qurna-1 would be depleted at the end of its plateau period in 2022, while Zubair would be depleted one year earlier than the end of its plateau period in 2021, and Gharaf would be depleted five years before the end of its plateau period in 2024. Furthermore, the three Misan oilfields would be fully depleted at the end of the contract period.

 

Chart 4 provides a comparison between accumulated production during the contract period and the corresponding proven reserves for the 12 covered oilfields.2

 

Chart 4: Depletion Potential Of The Oil Fields As Of 2029

 

 

The implications are obvious. Unless the international oil companies (IOCs) use advanced methods to enhance the recovery factors from these oil fields significantly, total production would be lower than the above calculated production levels. This naturally has serious ramifications on the economics of the development for both Iraq and the IOCs. The failure to address this matter would cause total production to decline significantly (line TP1 in the chart below) due to the declines in the production levels of the brown-field projects (line BFTP1) as a result of the depletion of West Qurna-1 and Zubair first, then due to the decline of Gharaf production among the green-field projects (line GFTP1)

 

The following Chart 5 shows the effects of the depletion of these three oil fields as early as 2022. This early depletion of the three oilfields would reduce total production by 8.243bn barrels, representing 12% of total production had there been enough proven reserves up to end 2029.

 

Chart 5: Oil Production Patterns, 2010-29

 

In short, there are three viable options ought to be considered by the Ministry of Oil:

  • Use advanced methods to enhance the recovery factor significantly and thus augment the currently proven reserves for these oil fields to allow the contracted production plateau levels. This of course comes at a cost, which has to be assessed properly by sound cost-benefit analysis.

  • Reduce the contracted production plateau levels and thus have a longer plateau period at a lower plateau target.

  • Combine both the above approaches.

The first two options, and consequently the third option, entail contracts revision and amendments as soon as possible, but surely well before the adoption of the final development plans for the related oil fields.

 

Gross Oil Revenues

Gross oil revenues from the calculated production levels during the contract period were estimated according to three oil price assumptions – $50/B, $75/B and $100/B – and for two production levels: without depletion effects (TP) and with depletion effects (TP1 in chart below).

 

Chart 6: Annual Gross Oil Revenues, 2010-29 ($Bn)

 

 

Under the no-depletion case Iraq’s gross revenues from oil produced by these fields would increase gradually from a minimum of $39bn (at $50/B) to a maximum of $78bn (at $100/B) in 2010. Annual gross revenues during the plateau period 2017-22 would range between $213bn and double that amount under the two price assumptions. During the whole contract period 2010-29, gross oil revenues would be $3,397bn, $5,096bn or $6,795bn at oil prices of $50/B, $75/B and $100/B, respectively.

 

However, with the depletion effects taken into consideration, gross oil revenues would be much less from 2023 onwards (TP1 lines under the different oil prices). Hence, total gross revenues under this scenario would be $2,985bn at $50/B, $4,478bn at $75/B and $5,970bn at $100/B. This represents a reduction of 12% in gross revenues under any price assumption.

 

Final Remarks

Estimating net oil revenues from the development of the above mentioned oil fields requires the estimation of three additional variables: capital expenditures; operating expenditures; and the remuneration fees paid by Iraq to the IOCs in accordance with the provisions of the related contracts. These will be addressed in another article soon. For the time being, the early depletion possibilities identified above sending out alarming signals, which the Ministry of Oil has to address very seriously in its forthcoming conference with the IOCs involved in these development activities.

 

Notes

1. Eni has mentioned 6.5bn barrels as the proven reserves figure for Zubair oilfield (Wall Street Journal, 9 June 2010). This has to be verified by the Ministry of Oil, since the official declared proven reserve for this field is much less than that.

2. Information on Badra oil field indicates a proven reserve of 109mn barrels, while oil in place is around 1.2bn barrels. The proven reserve figure is very questionable, since it could be depleted in the early years of the contracted plateau period. Hence, the oil in place figure is used until a more accurate estimate on proven reserves becomes available.

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