There is plenty of heavy oil to get out of the ground in Mexico, Brazil and Indonesia. Karen Boman surveys the work underway.
The Peregrino FPSO at the Peregrino Field offshore Brazil. Photo from Statoil.
With oil prices still trading around the US$50/bbl mark, finding efficient technologies that allow heavy oil to be extracted with fewer wells, or at a lower drilling cost in less time, may become a gamechanger for developing offshore heavy oil fields, says Adrian Lara, analyst with GlobalData. Quite often, recovery is defined by the number of wells drilled, as oil with higher viscosity flows much slower than a conventional one and may not respond easily to the primary recovery methods.
New technologies will have to address the challenges of offshore heavy oil fields, including flow assurance, which is one of the main challenges of offshore heavy oil fields, Lara says. Appropriate measures should be taken to prevent formation of hydrates, and emulsions when in contact with water as it may worsen electric submersible pumps’ (ESP) efficiency. All of this will affect the well’s productivity and lower the recovery.
Another challenge associated with heavy oil production is the water breakthrough. Oil with higher viscosity has lower mobility compared to the water, so the latter just channels through towards the producers. Once the breakthrough occurs, it is very difficult to recover the unswept oil in the near well area, unless enhanced oil recovery techniques, like polymers, are used.
“One important thing to consider is how to keep the oil flowing as soon as it reaches the seabed of deepwater fields as temperature there is usually lower,” Lara says.
He cites the Atlanta heavy oil deepwater field in the offshore Brazil as an example. Operator QGEP decided to properly insulate all the production lines. In the wellbore, ESPs with gas lift are usually used to allow the oil to reach the wellhead. Another option here is to add a diluent/condensate/light oil to increase the mobility of the fluid in the well, Lara says.
Many wells in the offshore Brazil are equipped with inflow control devices to distribute the water production more evenly along the wellbore. This allows can prolong the production with lower water cut, Lara adds.
“Normally these schemes include any actions to keep the oil flowing towards the producing wells. Due to higher viscosity of oil, such fields require either stronger aquifer support or water injection strategy to create needed draw-down pressures, or injection of gas/solvent to bring the oil viscosity down,” Lara says. “Other technologies that involve heating of the reservoir in-situ, could be used onshore, but may not be applicable to the offshore fields due to difficulties associated with constructing the facilities.”
Statoil’s Peregrino heavy oil field, discovered in Brazil’s offshore Campos Basin in 1994, has been producing via the Peregrino FPSO and two wellhead platforms since 2011. A third wellhead platform is currently being constructed (see panel). To reach Peregrino’s API 14° heavy oil deposits approximately 2300m below the seabed, Statoil used the horizontal drilling techniques it applied to its Grane heavy oil field in the North Sea. Some 30 long horizontal multilateral wells with open hole gravel pack and screens made it possible to reach and produce from a wider area of the reservoir, Lara says.
Additional production from increased sweep efficiency allowed them to reduce overall development costs and bring down the breakeven oil price for the project.
“Fortunately, many offshore heavy oil fields in Brazil have good permeability that offset bad quality of oil and make the development of such reservoirs more attractive from the economical perspective,” he says.
Statoil also used ESPs, inflow control devices and autonomous inflow control devices to enhance recovery from the Peregrino field. Using ESPs allowed Statoil to heat the oil to 130–150°C in the wellhead platform.
Outlook for heavy oil
The 2014 oil price downturn has stalled development of a number of oil fields, including Atlanta (API 14°) and Siri (API 12.5° according to news agency Estado), offshore Brazil, Lara says.
First oil from Atlanta is now expected by the end of 2017, according to QGEP, just four years after the project’s development plan was approved by Brazilian regulators ANP in 2013. The Siri field, an extra-heavy oil in the deepwater of Brazil, has also seen delays, Lara said.
Indonesia’s Ande Ande Lumt (API 15.5°) heavy oil field is in pre-final investment decision evaluation and has been somewhat stalled over the last few years due not only to lower crude prices, but due to cost overruns, Lara says. Located offshore Indonesia in the West Natuna Sea, Ande Ande Lumut was expected to be sanctioned in 2013, but cost and price changes have hindered development. The project is still under planning and evaluation, with the addition of deeper reserves having helped raise expectations for possible investment sanction in 2018.
Australia-based AWE, which holds 50% interest in Ande Ande Lumut, said work continues to optimize plans for the field in light of positive results from the AAL-4XST1 appraisal well, with a focus on assessing G sand resources. Laboratory work to assess feasibility of co-mingled production of K sand and G sand oil was looking positive, and no significant changes to the FPSO processing infrastructure were anticipated, AWE said in its March 2017 quarterly report. AWE said the operator has temporarily delayed starting Stage 2 commercial tenders to allow time to quantify the size of the G sand resource and integrate these potential positive changes to the plan of development.
The development of offshore heavy oil fields has not halted altogether, however. Offshore eastern Canada, ExxonMobil expects its Hebron heavy oil project to come online by year-end. Hebron is in the Jeanne d’Arc Basin, 350km southeast of St. John’s, in 93m of water. Discovered in 1980, it is expected to contain 700MMbbl of recoverable resources, and is the province’s fourth offshore oil project. The complete Hebron platform was towed to field and positioned on the seabed on the Hebron field at Grand Banks in mid-June 2017, according to Norwegian engineering services company Kvaerner, who through its joint venture Kiewit-Kvaerner Contractors, built the gravity-based structure and led the installation process.
Teekay’s Petrojarl I FPSO will be used on the Atlanta field offshore Brazil. Photo from Teekay.
Mexican heavy oil awaits
With Pemex’s announcement of its new farm-out strategy earlier this summer, the oil and gas industry might start to see heavy oil projects there receive their financial investment decisions. Pemex announced that it would include the heavy oil Ayin-Batsil complex, comprising four fields – Ayin, Alux, Batsil, and Makech – in its upcoming farm-out calendar.
Last month (August), OE detailed the fields available for farm-out. The Ayin-Batsil area offers more than 359 MMboe of undeveloped 3P reserves, mostly heavy oil, in shallow water, with multiple fields to develop, said Pemex E&P Director General Gustavo Hernandez in Houston this July. Hernandez added that Alux and Makech could potentially be developed at subsea tiebacks to Ayin and Batsil. The area already has infrastructure in place – the Litoral-A central processing platform, which is 24km from Ayin-Batsil and 50km from shore.
“A new operator will benefit from the proximity to shore (less than 50km), making the transportation of the produced crude relatively economical,” Lara says. “Also, the existence of some infrastructure built by Pemex could create a new dynamic in the Campeche Basin.”
Peregrino II set for 2020
Peregrino Phase 2 concept model.
The Peregrino field is Statoil’s largest project in Brazil. The field sits in the southwest portion of the Campos Basin, in the BM-C-7 block, 85km offshore Rio de Janeiro. Statoil operates Peregrino with 60% interest alongside partner Sinochem (40%).
Peregrino, according to Statoil, contains estimated reserves of 300-600 MMbbl of recoverable oil and an API gravity of 14°. Statoil says this is the second heaviest oil to be produced in Brazil.
Production began on the field in April 2011, and reached a plateau of 100,000 b/d in 2013. The field is connected to an FPSO via outflow lines and electrical umbilicals. There are 40 production wells and 8 water injection wells currently planned.
Statoil submitted its development plans for phase two of the field in 2015. At the time, the Norwegian major said that the project will comprise a new wellhead platform and drilling rig (Platform C) and adds approximately 250 MMbbl in recoverable resources to Peregrino field. Statoil expected, in 2015, that investment will be around US$3.5 billion. Phase II first production is expected by end of 2020.
Phase II will enhance Peregrino production by increasing the number of production wells by 21, consisting of 15 oil producers and six water injectors, to be drilled from the new well head platform C, which will sit in 120m water depth. The well will tap a new area called Peregrino Southwest, which Statoil says is not currently reachable by the existent platforms A and B.
In November this year, construction is due to start Heerema Fabrication Group’s yard in Vlissingen, the Netherlands, on the jacket for the Peregrino II development.
The eight-legged Peregrino jacket, which will be about 135m tall, have a footprint of 66m x 53m and will weigh 9300-tonne (excluding 12 piles), will serve as foundation for the topside, including drilling and process facilities, utilities, power generation, living quarters and a helideck, with a design operational weight of 25,000-tonne facility. The jacket is also designed for storage of fresh drill water with caissons for submerged pumps connected to such storage tanks, Heerema said in May.
Statoil awarded Apply Leirvik a $48 million (NOK 400 million) contract for the delivery of the five-story living quarters module, with delivery due in Q3 2019.
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