Oman Relies On Independents To Boost Crude Output By 40,000+ B/D
Independents aim to lift Oman’s crude production by at least 40,000 b/d. Shell-led PDO’s output will stay at 550,000 b/d. Oman’s increasingly heavy crude output will impact export blend quality. BP will take FID on a $15bn gas project in February 2013, as the government prepares to lift gas subsidies to end users, Nick Wilson writes from Muscat. Meanwhile, Melanie Lovatt reports that Oman’s refinery expansion plans face delays due to lack of project finance.
Omani independent Petrogas wants to increase production at Daleel Petroleum – a 50:50 joint venture with China’s state-owned CNPC – from the current 34,000 b/d to 50,000 b/d “in the next few years.” Petrogas CEO Jean-Denis Bouvier tells MEES: “Block 5 assets have overall performed extremely well and we are very confident that Daleel can deliver this production from its three main assets, namely Daleel Shuaiba waterflood, Daleel Natih waterflood and the primary and secondary development of the Bushra cluster of fields.”
Petrogas, which also took over the Rima cluster of fields from Petroleum Development Oman (PDO) in 2006, started work on it in 2008, and production has been increased from 2,200 b/d to almost 15,000 b/d. The results so far have indicated a production potential to reach and possibly exceed 20,000 b/d in the near future. Unconnected fields have been brought to production and deeper reservoirs being targeted. Enhanced oil recovery (EOR) studies are ongoing with an initial pilot planned for end 2012/early 2013.
In Block 3 a CC Energy Development (CCED) led consortium (50% CCED, 30% Sweden’s Tethys Oil, 20% Japan’s Mitsui) is producing 11,000 b/d from three reservoirs – Barik and al-Bashir (above 40° API), and Khufai (30° API, 0.6% sulfur). It currently trucks crude 168km to a delivery station. By 3Q12 it will have built pipelines and permanent production facilities with a capacity of 25,000 b/d, and by year-end will have drilled 27 more wells, allowing initial production of 14,000-15,000 b/d. CCED Managing Director Shah Etebar tells MEES: “In three years we hope to reach 20,000 b/d-plus and recoverable reserves of 100mn barrels.” The company will have invested $500mn in the project by then. It also found ultra-heavy oil. Mr Etebar says: “There is a lot of heavy oil in place, but we prioritize the light crude. First we cream off the top, then the middle then the bottom of the barrel.”
Occidental (Oxy) has reached its plateau output of 80,000 b/d in Blocks 9 and 27, and will plateau its heavy oil Mukhaizna field at 140,000 b/d – 10,000 b/d below target, MEES learns, by year-end. It is producing 125,000 b/d. Oxy has added a seventh train to the processing plant to speed up what was a slow start to production. Scaling has been a problem and the extra train allows six to work while one is cleaned. The cost of the project has soared from the planned $2bn to $9bn partly due to having to double the number of wells in the EOR project – the steam wasn’t entering the reservoirs to the originally planned-for distances.
Indonesia’s Medco has failed to significantly increase production at the Karim cluster of small fields from 18,000 b/d when it took it over from PDO in 2006. PDO (Shell, Oman’s government, Total and Partex) also lost the Mukhaizna field development to Oxy. It issued tenders for the development of the Karim and Rima clusters, recognizing that it could not justify undivided attention to its portfolio of small fields. Yet no more small fields contracts have been offered since 2008. This is despite the success of the independents – with the exception of Medco – and the Ministry of Oil and Gas as late as 2010 still being dismayed with PDO’s failure to deliver on large projects such as Harweel and its failure to develop its smaller fields. The merit of issuing more tenders for fields taken from PDO is the subject of intense debate.
PDO announced on 20 February its crude output dropped slightly to 549,280 b/din 2011
from 553,000 b/d in 2010 because of strikes triggered by political unrest and flooding caused by heavy rain. PDO Managing Director Raoul Restucci said to replace output lost to depletion, PDO is relying on the delayed Harweel field to start up in April, bringing on stream 15,000-20,000 b/d by year end and ramping up to 38,000 b/d in two-four years.
Oman’s total oil output, including condensate, will increase to 900,000 b/d by the end of 2012, Oil and Gas Ministry Undersecretary Nasir al-Jashmi said – up from 2011’s average of 884,900 b/d. However, PDO’s condensate – 93,600 b/d last year – will soon start to decline as the gas becomes increasingly dry.
Oman is spiking much of the condensate into its increasingly heavy crude to maintain the export blend API at 31°. PDO expects its condensate output to fall. As its crude gets heavier, forcing it to use EOR, and Oxy’s Mukhaizna 15,000 b/d output – whose gravity has dropped to 10-12° API (almost tar) – comes on stream this year, Oman will struggle to maintain its export quality. Crudes from 10-18° API give naphtha 2.3%–12%, kerosene 4.1-6.7%, gasoil 12% and residue of 70%, which can be a problem for refiners. The export blend gravity has dropped from 38° API to 31° API over the past two decades. Furthermore, increased volumes of condensate have changed the refining yield.
Mr Jashmi said the ministry expects to sign concession agreements on three or four blocks this year. Oman has had difficulty in attracting investors to previous exploration concessions for blocks that had been relinquished. However, Irish independant Circle Oil says its seismic survey in deepwater offshore Block 52 indicates prospects with the potential to hold 7bn barrels of oil in place, the firm announced recently. If drilling confirms this, interest in offshore blocks may increase. Circle is looking for a partner.
BP is drilling its ninth well – and its second horizontal well – in the Khazzan-Makaram gas fields, which contain an estimated 100 tcf of gas in place. It will reach total depth by April. Two more wells will be drilled this year. The engineering, procurement and construction (EPC) contracts will be tendered in July, analyzed in the fourth quarter and awarded in February 2013 when a final investment decision (FID) and declaration of commerciality are expected. The 30-year production period will start from this date. First commercial gas production will start up in the third quarter of 2016, ramping up to 1bn cfd of annual average sales gas. BP will close talks with the government for the scope, production profile and number of wells before it agrees a price formula and closes the production sharing agreement (PSA) at the end of the year. BP will get Oman blend price for its expected 20,000 b/d of condensate. It is not planning LPG extraction. BP country manager Jonathan Evans tells MEES: “We’re renegotiating the gas price. Costs have increased and things have changed – based on the results of our appraisal wells.” The original planned project cost was $10bn but the need for horizontal wells has driven the cost up to $15bn. Oil ministry sources say the government is in talks with gas customers to raise the price paid for existing contracts – ending the subsidies and resulting low prices offered to producers.
Oman desperately needs gas to keep pace with rising power demand. It plans to invest $2.9bn in 13 new water and power projects that are commencing in 2012. According to the seven-year (2011-2017) plan of Oman Power and Water Procurement Company, power demand will rise at an annual average of 9%.
ORPIC Refinancing Option Could Take Refinery and Petchem Expansion Cost To $3Bn
Oman plans to expand its working refinery capacity by 305,000 b/d. In Sohar it is expanding a 116,000 b/d nameplate capacity refinery, which only works at 100,000 b/d, to 175,000 b/d, MEES learns, and is building a 30,000 b/d bitumen plant. In Duqm it is doing the front end engineering design (FEED) for a 200,000 b/d new refinery – Oman is studying closing down the old Mina al-Fahal refinery in Muscat when it comes on stream, MEES understands. The closure of the Muscat refinery would mean residue – 50% of Sohar’s feedstock – from Duqm would have to be shipped to Sohar, or Sohar refinery would have to be upgraded again to process more Omani crude. It is also adding an aromatics plant. However, there is a lack of integration in state-owned Oman Oil Refineries and Petroleum Industries Company (ORPIC), which owns refineries and petrochemical plants, and the plans face difficulties in getting project finance.
Furthermore, Muscat is debating whether to import Gulf crude. If it uses Omani crude as feedstock it will slash its crude exports – a strategic decision that Muscat might not want to take. A lot of its revenue would become dependent on refining margins, and it would reduce liquidity on the Dubai Mercantile Exchange (DME).The government has a stake in the DME, which trades futures in Omani crude. Oman wanted a more transparent and accurate prices for its crude exports and intended DME Oman to become the benchmark for Gulf crudes. But ORPIC is looking for foreign investment in its projects, and private sector firms’ interest will be in the economics of imported Gulf crude or Omani crude, not in Muscat’s strategic needs.
ORPIC is seeking a financial adviser to help it consolidate debt at its operations and implement an expansion. While the expansion is expected to cost around $1.2bn, MEES understands that if a refinancing of the existing debt is included, this could balloon to around $3bn. The company has been in talks with international banks regarding the advisory mandate and is expected to reach a decision sometime soon (MEES, 26 December 2011).
The company may decide to implement the expansion and then refinance the debt at a later stage, given that there is concern about lender appetite, said one project expert. Banks are currently suffering from difficult conditions that result from the Eurozone debt crisis, and if ORPIC does not get positive feedback on the refinancing, it will probably “just go for the expansion,” he said. He suggests that the financing will probably combine export credit agency (ECA) contributions with bank funding. Most project financings implemented after the global credit crunch have needed to include ECAs, and some have even featured bonds. Meanwhile, there may be changes to aspects of the project risk. The company may need to change its guarantees. At present the existing financing for the two refineries is guaranteed by the Omani government, but that may be replaced by a guarantee for repayment only, commented the project expert.
The ORPIC complex includes four industrial plants operating at two locations, in Muscat and Sohar. The two plants are joined by a 266km pipeline, delivering feedstock from Mina al-Fahal refinery to the Sohar refinery and its petrochemical plants. Omani crude is processed at Mina al-Fahal and residue from this refinery is transferred via the pipeline to Sohar refinery where, mixed with more Omani crude, it is refined to create fuels, naphtha and propylene. The naphtha goes to an aromatics plant to produce benzene and paraxylene. The propylene is used as feedstock to produce polypropylene.
The four plants have a production capacity of 222,000 b/d of naphtha, liquid petroleum gas (LPG), gasoil, gasoline, fuel oil and jet fuel; 818,000 tons/year of paraxylene; 198,000 t/y of benzene; and 350,000 t/y of polypropylene. However, the Sohar refinery has rarely worked at its design capacity of 116,000 b/d since its construction, due to technical issues caused by cost cutting and problems in securing sufficient quantities of feedstock – the Mina al-Fahal refinery only provides about 50% of its residue needs.
In 2007 Sohar Refinery Company and Oman Refinery Company were merged into one company and received $1.37bn in refinancing from 12 banks. The fallout from the subprime mortgage crisis at the time curbed international appetite for the company’s debt and HSBC (the financial adviser on the transaction) and Standard Chartered were the only Western banks to participate. The rest of the lenders were Omani and regional banks (MEES, 15 October 2007).
Furthermore, Oman has yet to select a feedstock. One school of thought wants Omani crude, but another does not want to take more than one-third of its export crude off the market, and is reportedly looking at using Saudi crude. The bitumen plant would face difficulties in finding an appropriate feedstock. Bitumen plants require naphthenic heavy crude – naphthenes provide a hard quality bitumen, while heavy crude increases the output of fuel oil, a key consideration in bitumen manufacture. Most Gulf crudes are not of the right quality.
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