The exploration and production (E&P) of natural gas reserves is defining advancements in Oman’s upstream segment, with the sultanate pursuing a policy of inviting major global players to develop reserves of non-associated gas. Since the successful commissioning of the Khazzan tight gas project in 2017, which added 1bn standard cu feet per day (scfd) to the country’s gas supply, a number of largescale E&P projects – including the second phase of the Khazzan field – are set to continue. With regard to oil, technological advancement is playing a key role in E&P, as innovations in 3D seismic imaging, enhanced oil recovery (EOR) and waste disposal lead to improvements in productivity and sustainability.
The Mabrouk field in the north-east of the country may overtake Khazzan as the country’s largest gas project if the total planned investment of $20bn from French multinational Total and Royal Dutch Shell comes to fruition. According to government-led E&P company Petroleum Development Oman (PDO), which announced the discovery of the site in the first quarter of 2018, the Mabrouk reserve contains 4trn standard cu feet (scf) of gas and 112m barrels of condensate.
Following the discovery, the Ministry of Oil and Gas (MOG) chose to invite international operators to carry out exploration and discovery rather than finance the investment itself. Shell and Total entered into a joint bidding agreement for respective shares of 75% and 25%. According to the proposal, which was officially accepted in May 2018, initial production would stand at around 500m scfd, with the potential to increase figures to 1bn scfd at a later stage. As part of an initial agreement signed in February 2019, Shell and Total were joined by the Oman Oil Company (OOC), with a final concession agreement expected before the end of 2019.
In line with government diversification objectives, the project will integrate upstream E&P with downstream developments – in this case a 45,000-barrel-per-day gas-to-liquids plant at Duqm operated by Shell and the OOC and an LNG bunkering facility at Sohar developed by Total (see analysis). The Mabrouk site is part of the Greater Barik area, in the northern part of Block 6, located onshore in the central-west region of the country.
Tight gas is understood to be the dominant play at Block 47, for which Italian oil and gas multinational Eni signed an E&P sharing agreement (EPSA) with the government in January 2019. The EPSA was the outcome of the MOG’s 2017 bid round and gives Eni a 90% operational stake in the 8524-sq-metre block located onshore in the Ad Dakhiliyah governorate in the north of the country; the OOC E&P hold the remaining 10% stake. Commercialisation at the site, which has been previously operated by various companies including PDO, Amoco Oman, UK-headquartered RAK Petroleum and Norway-based DNO, is facilitated by its proximity to major oil and gas pipelines running through Block 47 to the capital Muscat.
In January 2019 Eni also signed an agreement for Block 77 – another high-potential gas site. Signed with BP and the MOG, the agreement ensured all parties would work together towards an EPSA, which was subsequently signed in July 2019. Block 77 has a total area of 3100 sq km and is located in central Oman, some 30 km east of the BP-operated Khazzan field in Block 61. Under the terms of the EPSA, Eni and BP will each have a 50% interest, with Eni acting as the operator during the exploration phase. While neither BP nor Eni indicated the extent of the potential resources at the site, Mohammed Al Rumhi, the minister of oil and gas, said that Block 77 contained discovered reserves of 2trn-4trn scf, and potentially up to 10trn scf. BP suggested that its adjacent Khazzan infrastructure could assist with drilling for gas in Block 52 in the first half of 2020, after acquiring rights to the offshore block in 2017.
In August 2019 Mazoon Petrogas, a subsidiary of Oman’s Petrogas E&P, renewed its EPSA for the onshore Block 5 concession in the north-west of Oman. The interest is 50% owned by Mazoon Petrogas and 50% owned by Mazoon BVI, a subsidiary of the China National Petroleum Company (CNPC). The block continues to be operated by Daleel Petroleum, a local joint venture between Mazoon Petrogas and CNPC, and has four oil fields over an area of 992 sq km, with expected recoverable reserves of around 200m barrels of oil. In October 2019 Oman Shell signed an EPSA with the MOG for 100% working interest and operatorship of Block 55, a coastal concession measuring 7.5 sq km in the south-east of Oman. According to a statement released by Shell, the agreement includes “a work programme of regional studies and seismic acquisition as well as other potential exploration activities”. The site was formerly operated by global oil field services firm Petrofac, but no reserves were announced.
The Khazzan-Makarem gas field, which came on-line in 2017 and produces around 1bn scfd of gas, plans to increase its capacity following BP’s 2018 negotiation of a territorial amendment to the original EPSA. Under the terms of the amendment, a further 1150 sq km of territory were added to the concession to the south and west of the original area. This second phase of development – known as Ghazeer – is expected to boost capacity to 1.5bn scfd when production commences in 2021. In February 2019 Youssef Al Ojaili, president of BP Oman, told industry media that the first and second stages of the Ghazeer project will together amount to $16bn in capital expenditure.
By end-2018, 45% of the work had been completed on the project and, according to Al Ojaili, this is expected to increase to around 90% by the end of 2019, leaving the project well on track to deliver its preliminary shipment by the first quarter of 2021.
Technology is having a significant impact on the upstream segment, leading to significant E&P advancements. In terms of exploration, improvements to 3D seismic technology and the resolution of seismic imaging is allowing operators to discover new deposits in concessions across the sultanate. “Ultra-high-productivity seismic technology is allowing us to get better insights than what we were able to see in the past,” Sami Baqi Al Lawati, technical director at PDO, told OBG.
With regard to production, the evolution of EOR technology has been key in helping Oman retain high production rates in recent years. However, operators are increasingly aware of the need to balance production growth imperatives with considerations of sustainability. “Within the next five years, more than 23% of our projects will involve EOR technology,” Al Lawati told OBG. “Along with this comes the challenge of sustainability, because the more we use EOR in difficult formations, the more energy-intensive it becomes. As such, the challenge will be to increase production without increasing our carbon footprint.”
This has meant deploying renewable sources such as solar and wind as an alternative to gas in steambased EOR where possible. The pioneering example is PDO’s Miraah Solar Thermal Project, which harnesses solar energy to produce steam to extract heavy and viscous oil at the Amal field in the south of Oman. In the same vein, the solar EOR project by the US’ Occidental Petroleum at the Mukhaizna oil field is set to double capacity at the Miraah plant to 2 GW.
On the sustainability front, one of the sector’s most successful projects to date is the Nimr Water Treatment Project, which created a giant wetland system capable of processing over 110,000 cu metres per day of water. As is the case at the Nimr oil field, produced water is a by-product of the oil production process. While this water is conventionally disposed of using energy-intensive pumps that send the water under ground into deep-lying aquifers, the Nimr project has created a constructed wetland system in a previously desert area by planting more than 1.2m seedlings and supplying the 2.4m-sq-metre area with a continuous supply of water. According to the International Water Association, this project alone contributes around 4.3% to Oman’s overall intended nationally determined contributions under the UN Framework Convention on Climate Change to reduce greenhouse gas emissions by 2% between 2020 and 2030. As well as its positive environmental impact, the water treatment solution is less gas-intensive and more cost effective than conventional methods.
The first and second phases were rolled out in 2010 and 2015, and had respective water treatment capacities of 45,000 cu metres per day and 115,000 cu metres per day. A third phase – which is planned to increase capacity to 175,000 cu metres per day – was nearing completion as of the end of 2019.
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