Description of the company
Aker BP is a fully-fledged E&P company with exploration, development and production activities on the NCS. Aker BP holds no oil or gas assets outside Norway. All activities are thus within the Norwegian offshore tax regime, and to the extent the company has overseas activities, these are related to construction and engineering of field developments.
Aker BP is active in all three main petroleum provinces on the NCS. The company remains convinced that the NCS offers attractive opportunities for oil and gas exploration and this is also supported by the NPD’s latest undiscovered resources estimates. Correspondingly, the company plans to be an active industry player in the coming years.
The company’s registered address is at Lysaker in Bærum municipality. The company also has offices in Harstad, Sandnessjøen, Stavanger and Trondheim. Karl Johnny Hersvik is Chief Executive Officer.
At the end of 2016, the company had 1,371 (534) employees. As operator for 53 (34) licences and partner in an additional 45 (50) licences, the company is a major licence holder on the NCS.
Aker BP’s ambition is to be the leading exploration player on the Norwegian continental shelf and to discover 250 mmboe net to Aker BP in the period from 2016 to 2020. This follows the ambition of long-term reserve replacement and value creation by establishing new core areas with operated production. The company can exceed this goal by continuously seeking additional prospect opportunities and improving the available data and technology to create a competitive edge.
In 2016, Aker BP participated in a total of 14 wells, including six sidetracks. This is a significant increase from four wells in 2015. Net resource additions from exploration were estimated to be 83 mmboe in 2016, or about one quarter of the total volumes discovered on the NCS during the year. The company achieved an after-tax finding cost of 0.7 USD/boe in 2016 and discovered volumes that equate to about 1.9 times its 2016 production.
The Exploration activity is grouped in three categories; exploration near own producing fields (ILX), exploration for growth, and exploration in frontier areas. Over the years there will be a balance between ILX, growth and frontier exploration targets. In 2016, Aker BP focused on exploring in growth areas, aiming at discovering volumes for future developments.
Exploration drilling was concentrated in the North of Alvheim area, the Askja/Krafla area and the Loppa High south area. The results were encouraging for further progress towards development decisions.
The 2016 drilling campaign in the Askja/Krafla area in PL272/PL035 comprised four main wells and three sidetracks, resulting in a number of discoveries that combined amounted to approximately 77 mmboe (gross). Gross mean contingent resources for the Askja/Krafla area is estimated at approximately 256 mmboe.
Drilling of the Langfjellet prospect in PL442 comprised of one main well and three sidetracks to collect data. The main well encountered a gross oil column of 109 meters in the Vestland Group and preliminary gross volume estimates for the discovery are in the range of 24 to 74 mmboe. The licensees will evaluate the discovery with regards to a potential development together with other discoveries in the area. Following the success at Langfjellet, the licensees have identified further prospectivity within the license and are planning further drilling activity in 2017.
On the Loppa High south in the Barents Sea, the Filicudi prospect in PL 533 north of the Gohta discovery was drilled in late 2016 to early 2017. The well encountered a gross 129 meters hydrocarbon column in high quality sandstone reservoir. Evaluation of the discovery is ongoing, and other prospects in the vicinity are considered for drilling. The preliminary gross resource estimate for the Filicudi discovery is between 35 and 100 million barrels of oil equivalents (mmboe).
The Uptonia prospect in PL554B&C and the Rovarkula prospect in PL626 were dry.
Aker BP was awarded 13 operated licenses and 8 new partner licenses through Awards in Pre-defined Areas (APA) 2016 in January 2017. The majority of these licenses are located close to the company’s existing core areas.
In 2016, total investments in exploration amounted to USD 258 (97) million.
In 2016, Aker BP participated in five field development projects: Ivar Aasen (34.8 per cent and operator), Gina Krog (3.3 per cent and partner), Johan Sverdrup (11.6 per cent and partner), Viper-Kobra (65.0 per cent and operator) and Oda (15.0 per cent and partner).
The Ivar Aasen field (34.7862 per cent interest and operator) is Aker BP’s first major development project as operator. The PDO was approved by the Norwegian Parliament in May 2013, and the production from the field commenced December 24, 2016. The Ivar Aasen field is situated west of Johan Sverdrup in the Utsira High area, and is estimated to contain gross reserves (P50/2P) of 199 million barrels of oil equivalent. The Ivar Aasen development comprises production of the resources in three discoveries; Ivar Aasen (PL 001B) Hanz (PL 028B) and West Cable (PL 001B and PL 242). Ivar Aasen was developed with a fixed manned production platform. The topside includes living quarters and a processing facility for first stage separation.
In June 2014, Aker BP signed a unit agreement with the licensees in PL001B, PL242, PL457 and PL338. Aker BP is operator and holds a 34.7862 per cent interest in the unit. The unit comprises the Ivar Aasen and West Cable deposits, while the Hanz deposit remains in PL 028B, where Aker BP is operator and holds a 35 per cent working interest.
Full field development costs (including Hanz) are estimated at NOK 27.4 billion (nominal). Aker BP’s ownership interest thus represents an investment of about NOK 9.6 billion.
Ivar Aasen is a two-staged development, with Ivar Aasen and West Cable being developed in phase 1. Hanz, located further north, will be developed in phase 2 and is scheduled to start producing in 2021. The production is estimated have a plateau production of approximately 67 mboepd (gross). The development of Ivar Aasen is coordinated with the adjacent Edvard Grieg field, which will receive partially processed oil and gas from the Ivar Aasen field for further processing and export.
The pre-drilling campaign with Maersk Interceptor continued until July, when the rig was removed from the field prior to installation of the topside. In total eight wells were completed during the pre-drilling campaign, five producers and three water injectors. In November, Maersk Interceptor returned to the field and has operated as an additional accommodation unit for hook-up and commissioning personnel.
Topside construction in Singapore was completed in May. All modules, including the living quarter were transported to the Ivar Aasen field, and installed on to the jacket in July 2016. Following the successful installation of the topside, the Flotel Safe Zephyrus was mobilised with hook-up and commissioning personnel.
In October, the SURF scope, comprising of laying and commissioning of pipelines and cables between Edvard Grieg and Ivar Aasen was completed.
The offshore hook-up and commissioning work have progressed well throughout the second half 2016, with more than 500 persons working offshore at the same time to prepare for operation. Production performance since start-up has been in line with expectations.
During 2016, key activities for the Ivar Aasen project have been progressing according to plan, and first oil was achieved at December 24.
The partnership consists of Aker BP (operator), Statoil, Bayerngas, Wintershall, VNG, Lundin and OKEA.
Johan Sverdrup (11.5733 percent participating interest in unit, partner) is the largest oil discovery on the Norwegian shelf since the 1980s and is located on the Utsira High, 155 km west of Stavanger. The operator estimates that the field contains recoverable volumes between 2.0 and 3.0 billion boe, and the development of the field will be one of the largest industrial projects in modern Norwegian history. The operator estimates a break-even oil price for phase 1 below 20 USD/boe and below 25 for the full field development.
The PDO for phase 1 was approved in August 2015. The approval included plans for installation and operation for oil and gas export pipelines and for power from shore. Production is expected to commence late 2019. The plan accounts for 50 years of production, and the project will be of high socio-economic importance in Norway.
The Johan Sverdrup oil field is planned to be developed in two phases. In phase 1 a field centre is established consisting of four bridge-linked platforms (processing platform, drilling platform, riser platform and living quarter), in addition to three subsea water injection templates. The oil will be transported via a dedicated pipeline to the Mongstad terminal, whereas the gas will be transported via the Statpipe system to Kårstø for processing and export.
The capital expenditures for phase 1 were estimated in the PDO at NOK 123 billion (nominal value, based on project FX). The estimated capital expenditure also includes drilling, power from shore and export of oil and gas, as well as contingencies and allowances for market adjustments. As a consequence of the macro environment and project improvements the operator’s estimate of capital expenditures have been reduced to NOK 97 billion (nominal value, based on project FX). For phase 2, capital expenditures are now projected by the operator at between NOK 40 and 55 billion (nominal, based on project FX). Consequently, the full field CAPEX is thus estimated at between NOK 135 and 152 billion.
The ambition is a recovery rate of 70 per cent, taking into account proven technology for increased/enhanced oil recovery (IOR/EOR) in future phases. In the PDO, phase 1 had a planned production capacity of 315 to 380 mbopd, however debottlenecking measures have increased the planned phase 1 production capacity to 440 mbopd. Fully developed, the production capacity is expected to be 660 mbopd.
The PDO for phase 2 is scheduled to be submitted during the second half of 2018, and start-up of production from the second phase is expected in 2022.
At the end of 2016, Aker BP has booked 300 mmboe as net P50 reserves for the Johan Sverdrup full field development, representing about 42 percent of Aker BP’s total P50 reserves.
The partnership consists of Statoil (operator), Lundin Norway, Petoro, Aker BP and Maersk Oil.
Viper-Kobra (65 per cent, operator) is located within the Alvheim field approximately three kilometres south of the Kneler structure at a water depth of 120 to 130 metres. The development comprised the two discoveries Viper and Kobra, developed by one well each. A new subsea four-slot manifold was installed and tied back to the Volund field. The two reservoirs contain approximately 10 mmboe of gross recoverable reserves combined.
First oil was achieved in November 2016 as per plan.
Gina Krog (3.3 per cent, partner) is being developed with a steel jacket platform and a floating storage and offloading vessel, gas will be exported via the Sleipner platform. The oil will be shipped by shuttle tankers. In the PDO, gross investments were estimated at NOK 31 billion (nominal) and the field holds gross proven and probable reserves (P50/2P) of about 219 mmboe. Production start-up is expected in the second quarter of 2017.
During 2016, pre-drilling of production and injection wells continued, the topside was finalised in Korea and transported to the North Sea, where it was installed at the field in August.
Oda (15 per cent, partner) will be developed with a subsea template tied back to the Ula field center via the Oselvar infrastructure. Recoverable reserves are estimated at 48 mmboe (gross) and the project is planned to be developed with two production wells and one water injector well, with first oil planned for 2019.
The PDO was submitted to the Ministry of Petroleum and Energy on November 30, 2016. Total investments for Oda are estimated at NOK 5.4 billion.
Over the course of 2017, the company plans to mature several projects and to submit three PDOs to the Ministry of Petroleum and Energy (MPE). This relates to Snadd (subsea-tie-in to Skarv FPSO) with expected production start in 2020, Valhall Flank West with expected production start-up in 2021 and Storklakken (Subsea-tie-in to Alvheim FPSO), which is expected to start producing in 2020.
As of 31 December 2016, Aker BP had production from 13 fields: Alvheim (65 per cent and operator), Atla (10 per cent and partner), Bøyla (65 per cent and operator), Enoch (2 per cent and partner), Hod (37.5 per cent and operator), Ivar Aasen (34.786 per cent and operator), Skarv (23.834 per cent and operator), Tambar (55 per cent and operator), Tambar East (46.2 per cent and operator), Ula (80 per cent and operator), Valhall (35.953 per cent and operator), Vilje (46.9 per cent and operator) and Volund (65 per cent and operator).
Production in 2016 averaged 118.2 mboepd, including full-year production from BP Norge legacy assets. 77 per cent was liquids and 23 per cent was gas. This represents a substantial increase compared to 60.0 mboepd in 2015, mostly due to the inclusion of additional producing assets through the merger with BP Norge. For Det norske legacy assets, the production increased to 63.5 mboepd in 2016.
Alvheim (65 per cent, operator) is an oil and gas field operated by Aker BP and is located in the Northern North Sea at a water depth between 120 and 130 metres. The field is located in Blocks 24/6, 24/9, 25/4 and 25/7 and is comprised of the producing Alvheim field (Boa, Kneler, and the Kameleon/East Kameleon structures), the Viper-Kobra and Gekko discoveries. The productive reservoir of the Alvheim field is the middle to late Palaeocene Heimdal Formation sandstone, which exists at a depth of approximately 2,100 metres. Alvheim was developed using a floating production, storage and offloading (FPSO) vessel. The development provides for the transport of oil by shuttle tanker and transportation of gas to the SAGE system.
First production for the Alvheim field was in June 2008. The fields in the Alvheim area have seen significant year-on-year increases in the estimated recoverable volumes of oil and gas since the initial development of the Alvheim field. The amount of recoverable oil has increased due to greater in-place volumes than previously estimated, development of satellite fields, additional horizontal and multi-lateral wells, and better than anticipated flow rates. Furthermore, improved reliability combined with optimization work has increased the production capacity of the Alvheim FPSO to about 150 mboepd, up from the original design of 120 mboepd.
The Alvheim fields consist of the Kneler, Boa, Kameleon and East Kameleon structures. The Boa reservoir straddles the Norway-UK median line. The Boa reservoir is unitized with Maersk Oil and Verus Petroleum, who are the owners on the UK side.
Net production from Alvheim, including Boa, averaged 43.3 mboepd in 2016. Production from the Alvheim field is estimated to end in 2033, with subsequent abandonment between 2033 and 2034. Year-end 2016 P50 reserves for Alvheim, Boa and Viper-Kobra are estimated at 83.6 mmboe net to Aker BP.
The Volund field (65 per cent, operator) is located approximately eight km south of Alvheim, and was the second field developed as a subsea tieback to Alvheim. The field, comprising four production wells and one water injection well, started producing in 2009 and was utilized as a swing producer when the capacity of the Alvheim FPSO allowed it. The field was opened for regular production in 2010. The Volund reservoir is a large-scale injective feature, formed by sands of the Palaeocene Hermod Formation.
Net production at Volund averaged 5.0 mboepd in 2016. Production from the Volund field is expected to last until 2033, with subsequent abandonment between 2033 and 2034. Year-end 2016 P50 reserves are estimated at 18.5 mmboe net to Aker BP. These reserves include two additional infill wells that are planned to start production in second half of 2017.
The Vilje field (46.9 per cent, operator) is located northeast of Alvheim at a water depth of 120 metres. The productive reservoir of the Vilje field is the middle to late Palaeocene Heimdal Formation sandstone at a depth of approximately 2,100 metres. The field is tied back to the Alvheim FPSO. Production commenced in 2008.
Net production from Vilje averaged 6.6 mboepd in 2016. Production from the Vilje field is expected to cease in 2031, with subsequent abandonment scheduled to take place between 2031 to 2034, which coincides with the expected cessation of production from the Alvheim area. Year-end 2016 P50 reserves are estimated at 8.9 mmboe net to Aker BP.
The Bøyla field (65 per cent, operator) is located about 28 km south of Alvheim at a water depth of 120 metres. The productive reservoir of the Bøyla field is within the Hermod sandstone member, which is a deep marine, channelized submarine fan system at a depth of approximately 2 100 metres. The field is tied back to the Alvheim FPSO. Production commenced in January 2015. The field is developed with two horizontal production wells and one water injection well.
Net production from Bøyla averaged 7.4 mboepd in 2016. Production from the Bøyla field is expected to cease in 2033, with subsequent abandonment scheduled to take place between 2033 to 2034, which coincides with the expected cessation of production from the Alvheim area. Year-end 2016 P50 reserves are estimated at 8.7 mmboe net to Aker BP.
The Valhall field (36.0 per cent, operator) is located in the southern part of the Norwegian North Sea at water depth of about 70 meters. The reservoir consists of chalk in the Upper Cretaceous Tor and Hod Formations. Reservoir depth is approximately 2,400 metres.
The field was originally developed with three facilities for accommodation, drilling and processing, and started production in 1982. The Valhall complex consists today of six separate steel platforms for living quarters, drilling, wellheads, production, water injection, combined process- and hotel platform respectively. These platforms are bridge-connected. In addition the field has two unmanned flank platforms, one in the south and one in the north. Liquids are routed via pipeline to Ekofisk and further to Teesside in the UK. Gas is sent via Norpipe to Emden in Germany.
Net production from Valhall averaged 15.3 mboepd in 2016. The Valhall concession period currently expires in 2028. The resource potential extends beyond the concession period, and it is common in the industry to achieve extensions to concessions, and the cessation of production will be subject to the technical life of the facilities and the economic cut-off. The current design life for the new PH is 2049, 2033 for IP and the Flank North and South, and WP was recently granted life extension until 2028. Year-end 2016 P50 reserves are estimated at 84.8 mmboe net to Aker BP.
The Hod field (37.5 per cent, operator) is located in the southern part of the North Sea. The field was discovered in 1974 and is located 13 kilometres south of Valhall. The water depth in the area is approximately 72 meters. The reservoir lies in chalk in the lower Paleocene Ekofisk Formation, and the Upper Cretaceous Tor and Hod Formations. The reservoir depth is approximately 2,700 metres. The field is developed with a normally unmanned platform, tied back to and remotely operated form Valhall. Hod started producing in 1990.
Net production from Hod averaged 0.5 mboepd in 2016. At year end 2016, Hod produces from wells drilled from the Valhall Flank South platform. All wells on the Hod platform are currently shut -in and awaiting plug and abandon operations. The license period expires in 2020. Year-end 2016 P50 reserves are estimated at 1.8 mmboe net to Aker BP.
The Ula field (80 per cent, operator) is located in the southern part of the North Sea. The water depth in the area is about 70 metres. The main reservoir is at a depth of 3 345 metres in the Upper Jurassic Ula Formation.
The development consists of three conventional steel facilities for production, drilling and accommodation, connected by bridges. The field started producing in 1986. The gas capacity at the field was updated in 2008 with a new gas processing and injection module. The oil is exported via Ekofisk to Teeside and all gas is reinjected into the reservoir to enhance recovery. Ula acts as a third-party host for the Oselvar and Blane fields via subsea tie-back’s.
Net production from Ula averaged 6.5 mboepd in 2016. The Ula concession period expires in 2028. The resource potential extends beyond the concession period, and it is common in the industry to achieve extensions to concessions, and the cessation of production will be subject to the technical life of the facilities and the economic cut-off Year-end 2016 P50 reserves are estimated at 48.6 mmboe net to Aker BP.
The Tambar and Tambar East field (55.0/46.2 per cent, operator) is located about 16 kilometres southeast of the Ula field in the southern part of the North Sea. The water depth in the area is 68 metres. The reservoir consists of Upper Jurassic sandstones in the Ula Formation, deposited in a shallow marine environment. The reservoir lies at a depth of 4,100-4,200 metres.
The field has been developed with a remotely controlled wellhead facility without processing equipment, and started production in 2001.
Net production from Tambar averaged 2.2 mboepd in 2016. The Tambar concession period currently expires in 2021 and Tambar facilities were recently granted life extension until 2021. Year-end 2016 P50 reserves are estimated at 8.1 mmboe net to Aker BP.
The Skarv field (23.8 per cent, operator) is located about 35 kilometres southwest of the Norne field in the northern part of the Norwegian Sea. The water depth in the area is 350-450 metres. The reservoirs in Skarv contain gas and condensate in Middle and Lower Jurassic sandstones in the Garn, Ile and Tilje Formations. There is also an underlying oil zone in the Skarv deposit in the Garn and Tilje Formations. The reservoirs lie at a depth of 3,300-3,700 metres.
The Skarv field is developed with a production ship with storage and offloading capacity (FPSO) anchored to the seabed. The FPSO has a life expectancy of 25 years. Skarv initiated production in 2012.
Net production from Skarv averaged 30.0 mboepd in 2016. The Skarv concession period currently expires in 2033 and the original Skarv FPSO design life is 2035. Year-end 2016 P50 reserves are estimated at 66.8 mmboe net to Aker BP.
The Jette field (70 per cent, operator) is located in the central part of the North Sea at a water depth of 127 metres. The reservoir consists of a submarine fan system in the Heimdal Formation of Late Palaeocene age and lies at a depth of approximately 2,200 metres. The field was developed with a subsea installation tied back to the Jotun B platform and started producing in 2013. Jette continued to decline in 2016 and net production averaged 0.6 mboepd in 2016. The field ceased production in December 2016.
The Ivar Aasen field (34.8 per cent, operator) started production at December 24, 2016. Average daily production net to Aker BP amounted of 0.2 mboepd, as the field only produced for one week in 2016 and net reserves are estimated at 69.3 mmboe.
The field was developed as a stand-alone platform for partial processing and water conditioning and injection, with transfer of the multiphase hydrocarbon mixture through two pipelines to the neighbouring Edvard Grieg field for final processing and export.
The partner operated fields Alta (10 per cent), Jotun (7 per cent), Varg (5 per cent) and Enoch (2 per cent) produced an average of 0.4 mboepd net to Aker BP in 2016. Varg and Jotun ceased production in 2016, as planned. Year-end 2016 P50 reserves net to Aker BP for the Atla and Enoch are estimated at 0.1 mmboe.