The test of time – GlobalData analyses the Oliva field

16 June 2016



The operations for the Oliva field in the north of the Santos Basin, 190km south-east of Rio de Janeiro, Brazil, are analysed by GlobalData.


In 2013, Queiroz Galvao Exploracao e Producao (QGEP) presented Oliva oil field as a potential tie-back to the Atlanta FPSO in the Santos Basin, offshore Brazil. The operator plans to start production from Atlanta by the end of 2016 and to tie-back Oliva in 2021. Prior to the connection of Oliva to Atlanta, a reservoir data acquisition well would be drilled and tested in 2018. The well could be connected to the floating production storage and offloading vessel Petrojarl 1 in order to perform some tests to verify the reserves and to support the production forecast.

In December 2014, Teekay Offshore was awarded a five-year charter contract for Petrojarl 1 at an annual rate of $50 million. The vessel was first upgraded by Damen Shiprepair and Conversion to fulfil the specific needs to operate the Atlanta heavy oil field and should be delivered in the second half of 2016.

Outlook

Oliva is planned to be developed as a tie-back to the nearby Atlanta field because, with the current knowledge of the field, it cannot be economically developed alone. Moreover, only one well has been drilled in the Oliva field, in 1993, and its development hinges on the outcome of the 2018 appraisal. A second well should be drilled within the next three years to verify the reserves and the productivity of the area.

"The Oliva field is one of two heavy oil accumulations under development in Block BS-4, located in the north of the Santos Basin 190km south-east of Rio de Janeiro."

Oliva is a deepwater field that contains heavy oil of 14º API in a shallow reservoir. To ensure an economic development, the reservoir needs to present good characteristics to offset the poor quality of the crude. Furthermore, the development of the field requires specific technologies such as sand control completion, a high-power artificial lift pumping system, specific flow assurance procedures and specific crude treatment similar to the system contracted for the Atlanta field.

According to the valuation, the remaining net present value of the Oliva development is negative. The development plan presented by the operator in 2013 includes the drilling of eight horizontal wells, five heavy oil producers and three water injectors in order to produce the 2P reserves of 65mmbbl. However, the development plan presented in 2013, in a different oil price context, will evolve based on additional drilling and testing.

Based on the current development plan, the Atlanta project, operated by the same consortium within the same block is assumed to benefit from the Oliva tie-back by sharing the FPSO cost. If the development is cancelled or delayed, it will impact the economics of Atlanta because the total cost of the FPSO will be allocated to Atlanta. In that scenario, the remaining net present value of Atlanta will also be negative.

Asset summary and development overview

The Oliva field is one of two heavy oil accumulations under development in Block BS-4, located in the north of the Santos Basin, 190km south-east of Rio de Janeiro, under a water depth of 1,515m. The block was first acquired by Petrobras in 1998 via a Round 0 concession contract. The same year, the Brazilian national oil company reduced its participation to 40% while Shell became the operator with a 40% working interest, with Chevron holding the remaining 20%.

In September 2011, Barra Energia do Brasil Petróleo e Gás acquired Chevron's 20% interest and 10% of Shell's holding. At the same time, QGEP purchased Shell's remaining 30% interest in the BS-4 block for $157 million. Finally, in June 2013, Oleo e Gas Participacoes SA (OGX) acquired the 40% share belonging to Petrobras for $270 million.

The Oliva field was discovered in 1993 by the vertical well 1BSS-0069-BS, drilled by the rig Discoverer Seven Seas owned by Transocean. In 2016, the discovery well is the only one drilled within the Oliva field. Between January and May 2000, the consortium acquired 3,350km2 of 3D seismic on the BS-4 block. In 2013, the operator QGEP presented the development plan for Atlanta and Oliva. Atlanta will be developed in two phases starting in 2016 while Oliva was presented as a potential tie-back to the second phase. In order to delineate and confirm the Oliva potential, a well is planned to be drilled in 2018. It might be connected to the Petrojarl 1 FPSO used for the first phase of Atlanta, which has a capacity of 30,000bpd. If this well confirms the discovery and the expected production, the field will be developed and tied back to the definitive Atlanta FPSO assumed to have a capacity of 80,000-100,000bpd and used for the second phase of Atlanta.

In its development plan, QGEP reports the drilling of five horizontal heavy oil producers and three horizontal water injectors, and an expected start date of 2021. According to the operator, the field will produce until the licence expiration date in 2033.

Geology

Oliva is a post-salt field located in the north of the Santos Basin, offshore Brazil. The reservoir rock is Eocene turbiditic sandstone similar to the one encountered at Atlanta. The reservoir sand is non-consolidated with an average porosity of 36% and a permeability of 5D associated with a high net-to-gross of 90%. The excellent properties of the reservoir are offset with the poor quality of the crude, which is heavy (14° API), viscous (228cP) and highly acidic. However, the heavy oil is non-paraffinic and non-asphaltenic, so will avoid wax deposition during production. Due to the highly unconsolidated nature of the sandstone reservoir, wells might be completed with an open-hole gravel pack for sand control, similar to the technology used for the Atlanta development.

Based on the current development plan, water injection will be necessary to produce the heavy crude and maintain the reservoir pressure. In order to increase the recovery factor, the operator might consider the injection of hot water to decrease the oil gravity and make it flow easily to the FPSO.

Challenges

The Oliva field was discovered in 1993, but due to the poor quality of the oil, no development plan was submitted until 2006 when the Atlanta field was discovered and tested. Despite the 2P reserves of 65mmbbl of heavy oil, Oliva cannot be developed economically as a stand-alone project. Moreover, only one vertical well has been drilled in the Oliva area, in 1993, and the development remains uncertain.

Even if the field will benefit from the nearby FPSO, which will be installed to produce from Atlanta, additional drilling and testing is needed to ensure the economics of the development. Assuming a fixed oil price of $41.06 a barrel, the project has a remaining net present value (NPV) if one third of the FPSO cost is allocated to Oliva. With a break-even price of $54.00 a barrel, a change in the oil price environment will be necessary to develop these heavy crude reserves.

Based on the heavy crude quality, the main challenge associated with the Oliva development will be flow assurance. The recovery mechanism is water injection and the production of water is assumed to increase, which will create emulsions with potentially very high viscosity. Similar to the Atlanta development, to avoid flowing issues, emulsions will have to be treated before reaching the electrical submersible pump (ESP) by injecting an emulsion breaker at the wellhead. After emulsion inversion, the ESP, which will be installed at the wellhead, will be used with the injection of an emulsion breaker before the ESP. To prevent hydrates formation, the operator will also need continuous injection of inhibitors.

In 2015, operator QGEP had been investigated as part on the ongoing corruption scandal in Brazil. As of April 2016, it is not clear whether the company is still under investigation or not; however, it is allowed to keep working in Brazil with Petrobras.

"Based on the heavy crude quality, the main challenge associated with the Oliva development will be flow assurance."

In 2013, OGX failed to contribute to its share in the block and was threatened by the National Petroleum Agency with a termination of its participation within the project. Those two companies are not in a strong financial position to invest heavily in the Atlanta and Oliva development. While the development of Atlanta is a priority based on its reserves size, this context can lead to further delays in the Oliva development.

Reserves and production

In 2015, QGEP reported 2P reserves of 65mmbbl. This reserve number is subject to change with additional drilling and testing. In the same year, the company planned to connect the Oliva field to the Atlanta FPSO in 2021. However, based on the delays for Atlanta's first phase, the valuation assumed a start of production for 2022. The same rig is assumed to be used for Atlanta and Oliva. In order to complete the drilling and completion for the Atlanta's wells, the drilling in Oliva would start in 2022. The development plan reports the drilling of eight horizontal wells, five heavy oil producers and three water injectors.

The production profile of Oliva was generated from individual well profiles using a peak production of 5,000bpd based on the drill stem tests (DSTs) performed in Atlanta minus 20%. The operator does not report any productivity for the Oliva wells. However, the productivity is assumed to be lower than Atlanta because of the presence of the active aquifer in Atlanta and the size of the reservoir. The production decline has been estimated at 8% for three years and then 15% based on the decline observed on the analogue Papa Terra field. The initial gas-oil ratio of 258 cubic feet per a barrel is assumed to be constant throughout the field life due to the water injection. The water cut is assumed to increase throughout the field life from 20 to 80%

Based on the development assumptions, the peak production from Oliva will be reached in 2024, with a production of 22,500bpd and 6mmcfd of natural gas. The field will recover 62mmbbl of reserves of heavy oil and 15bcf of natural gas until the end of the production licence in 2033.



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