Point Resources AS Annual Statements of Reserves 2017 1
Annual Statements of Reserves 2017
Point Resources AS 2 Point Resources AS Annual Statements of Reserves 2017
Content
1 Classification of Reserves and Resources 3 2 Reserves, Developed and Non-Developed 4 3 Description of Reserves 6 3.1 Producing Assets 6 3.1.1 Balder 6 3.1.2 Ringhorne 8 3.1.3 Ringhorne East 9 3.1.4 Brage 10 3.1.5 Snorre 11 3.1.6 Bøyla 12 3.1.7 Hyme 13 3.2 Development Projects 14 3.2.1 Bauge 14 3.2.2 Fenja 15 4 Contingent Resources 16 5 Management’s Discussion and Analysis 17 Point Resources AS Annual Statements of Reserves 2017 3
1 Classification of Reserves and Resources
Point Resources reserve and contingent resource volumes have been classified in accordance with the Society of Petroleum Engineer’s (SPE) Petroleum Resources Management System (PRMS). This classification system is consistent with Oslo Stock Exchange’s require- ments for the disclosure of hydrocarbon reserves and contingent resources. An overview of the classification system is illustrated in the figure below.
SPE reserves and classification system (PRMS)
Pro uction L A I REReSEsReVr EeSs C R E M
M 11P 2P 3P O C P I I P IIP ) P y ( Proved Probable Possible D li t E a i CE R E c A r L
P
- CO V L CO NoTnINtinGE eNntT N S I A I - D Y RESOURCEresourcesS L RC I Comm e E L
A f M I o T M I O
11CC 22C 33C e N I C
- B M an c U U h S E C L UNRECOVERABLE O R ng i PROPrSoPsE CTIVEecti e s PE T L PII P
A RESreOsURCESources cre a D T n I E O T
VE R LLooww BBeesstt HHiigghh EEssttiimaattee EEssttiimaattee EEssttiimaattee
UNDISC O UNRECOVERABLE
Not to scale Range of Uncertainty
4 Point Resources AS Annual Statements of Reserves 2017
2 Reserves, Developed and Non-Developed
The reserves estimates produced by Point Resources with a valuation date of 31.12.2017 have been certified by an independent reserves auditor, AGR Reservoir Services.
Point Resources has a working interest in eight assets containing reserves. Within the reserves category, there are six producing assets, one of which is shut-in awaiting an upgrade on the Njord facility, and three development projects. These assets are listed in the table below.
Overview of assets containing reserves
FIELD/PROJECT INTEREST (%) OPERATOR RESOURCE CLASS COMMENT
Developed Reserves Balder 100.00 % Point Resources Producing New – Acquisition from Exxon Ringhorne 100.00 % Point Resources Producing New – Acquisition from Exxon Ringhorne East 77.38 % Point Resources Producing New – Acquisition from Exxon Brage 12.26 % Wintershall Producing Snorre 1.11 % Statoil Producing Bøyla 20.00 % Aker BP Producing Hyme 17.50 % Statoil Non-producing Shut in awaiting Njord upgrade
Undeveloped Reserves Bauge 17.50 % Statoil Approved for development Snorre exp. project 1.11 % Statoil Approved for development Ringhorne 100.00 % Point Resources Approved for development Ringhorne East 77.38 % Point Resources Approved for development Fenja 45.00 % VNG Justified for development FID taken end of year 2017 Point Resources AS Annual Statements of Reserves 2017 5
Total net proven and probable reserves (2P/P50) for Point Resources as of 31.12.2017 is estimated at 193.5 million barrels of oil equivalents. The corresponding estimate for net proven reserves (1P/P90) is 148.4 million barrels of oil equivalents. The split between oil, gas and NGL is given in the table below.
1P and 2P reserves, gross and net, by asset
1P 2P GROSS GROSS GROSS GROSS GROSS GROSS OIL GAS NGL GROSS OE NET OE OIL GAS NGL GROSS OE NET OE AS OF 31.12.2017 INTEREST (%) MMBOE MMBOE MMBOE MMBOE MMBOE MMBOE MMBOE MMBOE MMBOE MMBOE
On Production Balder 100.00 % 38.5 0.5 0.0 39.1 39.1 48.2 0.7 0.0 48.8 48.8 Ringhorne 100.00 % 19.3 0.0 0.0 19.3 19.3 24.1 0.0 0.0 24.1 24.1 Ringhorne East 77.38 % 18.3 0.0 0.0 18.3 14.1 22.8 0.0 0.0 22.8 17.7 Brage 12.26 % 20.9 4.4 2.8 28.1 3.4 26.1 5.5 3.5 35.1 4.3 Snorre 1.11 % 275.9 0.0 0.0 275.9 3.1 392.0 0.0 0.0 392.0 4.3 Hyme 17.50 % 4.5 1.9 1.3 7.7 1.3 8.2 3.5 2.4 14.0 2.5 Bøyla 20.00 % 5.8 0.2 0.0 6.0 1.2 8.1 0.3 0.0 8.4 1.7 Total 383.3 7.0 4.0 394.3 81.6 529.5 9.9 5.8 545.3 103.4
Approved for Development Brage 12.26 % 34.4 8.3 8.1 50.8 8.9 49.6 11.6 11.8 73.0 12.8 Snorre Expansion 1.11 % 152.3 0.0 0.0 152.3 1.7 175.7 0.0 0.0 175.7 1.9 Ringhorne 100.00 % 18.7 0.1 0.0 18.8 18.8 26.7 0.2 0.0 26.9 26.9 Ringhorne East 77.38 % 5.2 0.0 0.0 5.2 4.0 7.4 0.0 0.0 7.4 5.7 Fenja 45.00 % 55.4 14.4 4.6 74.4 33.5 69.1 19.7 6.3 95.1 42.8 Total 266.0 22.8 12.8 301.5 66.8 328.4 31.5 18.1 378.0 90.1 Total Reserves 649.3 29.7 16.8 695.8 148.4 857.9 41.4 23.9 923.3 193.5
The table below shows the reconciliation of reserves between the current reporting and the previous year’s reporting at an aggregated level.
Reconciliations for 1P and 2P reserves
NET MILLION BARRELS OF OIL EQUIVALENTS 1P/P90 2P/P50
Balance as of 31.12.2016 9.6 14.0 Year 2017 Production -17.5 -17.5 Acquisitions/Sales of reserves 107.5 134.3 Discoveries, additions and extensions 42.5 55.7 Revisions of previous estimates 6.3 6.9 Balance as of 31.12.2017 148.4 193.5 6 Point Resources AS Annual Statements of Reserves 2017
3 Description of Reserves
3.1 Producing Assets
This section gives a short summary of the producing fields in the Point Resources portfolio.
3.1.1 Balder
Asset overview 1°40'E 2°E 2°20'E 2°40'E Balder field is an oil field located in the North Sea in blocks 25/10 59°30'N Alvheim and 25/11 within production licenses PL 001 and PL 028. The Jotun A water depth in the area is 125 m and the reservoir depth is around FPSO 1700 m TVD MSL.
Discovery Bøyla Ring- The Balder field was the first discovery in the Norwegian North Sea horne in 1967 by well 25/11-1. This was the second well drilled on the East Norwegian Continental Shelf (NCS). This field has a long explora- Ringhorne 59°15'N tion and production history and consists of a complex petroleum system with hydrocarbons in Paleocene and Eocene reservoirs Balder
Fields & Discoveries Point Licenses Reservoir 0 5 10Km The Balder field is a low-relief structural/stratigraphic trap with complex remobilized/injected Paleocene/Eocene deep water sands (mounds) with a common OWC across the field. There is strong aquifer support and a gas cap in the main part of the field. extension program has been initiated extending the lifetime of The field shows excellent reservoir quality and a relatively viscous Balder from 2025 to 2030. oil at 3 cP (23°API). Gas is reinjected if the gas export system is inoperative and gas lift is essential. Status
Development 20 wells are on production, where nine of them are cyclic produc- ers due to a high water cut. The main drilling has been performed The Balder field is produced from five subsea sites tied back to the in three phases. The last of these campaigns drilled ten wells in Balder FPSO, where the oil and gas is processed. Gas from Balder the period of 2013 to 2016, eight of which are currently active is routed to the Jotun FPSO for final processing and sales, while producers. the oil is offloaded from the Balder FPSO to shuttle tankers. The illustration on the next page shows an illustration of the Balder The Balder oil has an imposed penalty due to the salt and water infrastructure complex. content above specifications and a project with an objective to optimize and improve the processing facility is ongoing. The Jotun FPSO is assumed to be removed from site in March 2020 and from this date gas sales will be terminated, and all The Balder FPSO processes and services Ringhorne and Ringhorne gas will be used for injection, gas lift and fuel/flare. Ringhorne East through a highly integrated area comprising Balder, Ringhorne production will be rerouted to the Balder FPSO where the gas and Jotun production facilities. The further utilization of the Jotun handling/compression capacity at Balder will be a bottleneck FPSO beyond abandonment of the Jotun Field is now in the (42 MMScf/d) and therefore constrain oil production. A lifetime planning phase.
License shares for the Balder field
Licences Point Resources
PL 001 & PL 028 100.00 % Point Resources AS Annual Statements of Reserves 2017 7
Jotun A
Jotun B
r as 12 l ort el ne el ne 2 m m Ringhorne
R as assle el ne 2 m
10 est 12 l Stat e as l ft Grane Pipeline Balder Site as l ft l ne m 12 l l nes m er o t a le 2 A as A 1 A el ne 2 m S S al er to otun A 1 A 21A 2 S S A 2 2 10
A 2 2A 2 2 A A Site D Site A m 10 R A 22A 2 S S as l ne
A A A 27A
12 A 20 1 2
17A
1 A Site
11 2 7A Site 1
l ater Su sea l ells Su sea as ells as ft Re a r
as ut of Serv e Su sea ater ells A Su sea ells
The Balder infrastructure complex. 8 Point Resources AS Annual Statements of Reserves 2017
3.1.2 Ringhorne
Asset overview 1°40'E 2°E 2°20'E 2°40'E Ringhorne is an oil field located in block 25/8 within the production 59°30'N licenses PL 001, PL 027 and PL 027 C, north of the Balder and Alvheim Jotun A Grane fields. The water depth in the area is 125 m and the reservoir FPSO depth is around 1700 mTVD MSL.
The Ringhorne Forseti was discovered in 1970 by well 25/8-1. The Ringhorne Jurassic was found in 1997 by well 25/8-11. Ringhorne West was discovered in 2003 by well 25/8-C-20. Ringhorne E5 was Bøyla Ring- horne discovered by well 25/11-23 and Hermod was discovered by well East 25/8-11. Ringhorne 59°15'N
Reservoir Balder
Fields & Discoveries The Ringhorne field contains several separate oil deposits in Point Licenses Eocene, Paleocene and Jurassic sandstone. The reservoirs show 0 5 10Km excellent reservoir quality and a lighter oil than the Balder oil (39-40 API), except for the Forseti reservoir where the oil is more viscous at 3-4 cP. Development The Ringhorne Forseti consists of Paleocene reservoirs, mainly injectites, with uniformly high porosity and high permeability The Ringhorne field is a part of the Balder complex. The Ringhorne sandstones. Ringhorne Jurassic resources are found in a horst platform has wells drilled into the Ringhorne and Ringhorne East block north of Balder. The reservoir comprises fluvial to shallow fields. The heavy oil from the Ringhorne Forseti and the light oil marine sandstones in the Statfjord formation with high porosity from Ringhorne East as well as some of the oil from Ringhorne and high permeability. Ringhorne West consists of Paleocene Ty West is transported to the Balder FPSO, whereas the oil from formation deposited as deep-water mass flow sands of high poros- Ringhorne Jurassic and some of the Ringhorne West oil is sent ity. Ty sand is onlapping the Ringhorne Jurassic horst and share to the Jotun FPSO. Gas is exported via the Jotun FPSO. For an a common OWC at 1917 m TVD MSL with Statfjord formation in overview of the Balder complex, see Figure 3. Ringhorne Jurassic. Ringhorne E5 is an Eocene Mound, located close to the main Balder field but drilled from and produced to Status the Ringhorne platform. Hermod is a well explored accumulation in Late Paleocene with high quality reservoir sands above the Production on Ringhorne started in 2003. There are currently Ringhorne Jurassic/Ringhorne West structure. 10 producers, two water injectors for pressure support and one cuttings injector active. Ringhorne Phase II drilling was completed The main drive mechanism is natural aquifer drive. There is in 2012 and the drilling rig has been warm stacked ever since. pressure support from water injection in the Ringhorne Jurassic. Ringhorne Phase III drilling is in the planning stage and is sched- uled to commence in 2019. Work associated with the preparation and upgrading of the drilling rig is ongoing.
License shares for the Ringhorne field
Licences Point Resources
PL 001, PL 027 & PL 027C 100.00 % Point Resources AS Annual Statements of Reserves 2017 9
3.1.3 Ringhorne East
Asset overview 1°40'E 2°E 2°20'E 2°40'E The Ringhorne East oilfield is located in the central North Sea block 59°30'N 25/8 within production licenses PL 027 and PL 169E. The field is Alvheim Jotun A arranged under the Ringhorne East Unit area. The water depth in FPSO the area is 125 m and the reservoir depth is around 1940 m TVD MSL.
Ring- Discovery Bøyla horne East The Ringhorne East field was discovered in 2003 by well 25/8-14S. Oil was found in Statfjord sandstones from 1935 m TVD MSL Ringhorne 59°15'N to the OWC at 1948 m TVD MSL. Ringhorne East consists of a flat lying Statfjord reservoir of a limited thickness with a thin oil Balder column. Fields & Discoveries Point Licenses 0 5 10Km Reservoir The Ringhorne East field is a downthrown closure to the Ringhorne horst with a deeper OWC. It comprises shallow marine Jurassic Statfjord reservoirs with excellent reservoir quality and a strong Status aquifer drive from the north/east. The oil is light (39°API). The production started from Ringhorne East in 2006. Four pro- duction wells have been drilled, where three of them are currently There is good pressure communication within the field and a producing. The Ringhorne drilling rig is being upgraded to drill strong aquifer support. two additional infill wells in the Ringhorne East in addition to four producers and four workovers in the Ringhorne field. This project Development was sanctioned in 2017. The Ringhorne East field is part of the Balder infrastructure complex. All the wells in the Ringhorne East field are drilled from the Ringhorne platform. The oil is routed to the Balder FPSO and the gas is exported via the Jotun A FPSO. The Balder complex is illustrated in Figure 3.
License shares for the Ringhorne East field
License POINT RESOURCES STATOIL PETROLEUM AS FAROE PETROLEUM AS
Interest in Unit 77.38 % 14.82 % 7.80 % PL 027 100.00 % - - PL 169E 13.00 % 57.00 % 30.00 % 10 Point Resources AS Annual Statements of Reserves 2017
3.1.4 Brage
Asset overview 2°40'E 3°E 3°20'E 3°40'E Brage is an oil field located east of the Oseberg field and to the west of the Troll field in the northern part of the North Sea, in PL 053B, PL 055 and PL 185. The water depth is 140 meters and the 60°45'N reservoir is at 2000 m TVD MSL – 2300 m TVD MSL. Troll Discovery Brage was discovered in 1980 by well 31/4-3. Two separate hydro- Brage carbon-bearing sandstone intervals were encountered in the Late Jurassic Heather Formation. The Oxfordian to Kimmeridgian “Intra 60°30'N Heather Sand I” proved oil and gas with a water oil contact (WOC) between 2048 m TVD MSL and 2054 m TVD MSL. The Callovian Brasse “Intra Heather Sand II” (Fensfjord Formation) was oil bearing with a possible WOC at 2172 m TVD MSL. Oseberg Fields & Discoveries Point Licenses 0 5 10Km Reservoir The reservoir contains oil in sandstones of the Statfjord Formation of Early Jurassic age, and in the Brent Group and the Fensfjord Status Formation of Middle Jurassic age. There is also oil and gas in the The recovery strategy in the Statfjord and Fensfjord Formations Sognefjord Formation of Late Jurassic age. The reservoirs lie at is water injection. Gas injection started in 2009 in the Sognefjord a depth of 2000 – 2300 m TVD MSL. The reservoir quality varies Formation. The first oil producers in the Brent Group came on from poor to excellent. stream in 2008, supported by a water injector. This water injector was converted to a WAG injector in 2013. The gas blowdown Development phase of the Sognefjord Formation started in February 2015 when the gas injector A-35 A was converted to a gas producer. There is Brage has been developed with a fixed integrated production, no gas export until Q3 2018. drilling and accommodation facility on a steel jacket. The oil is transported by pipeline to Oseberg and through the Oseberg Transport System (OTS) pipeline to the Sture terminal in Norway. A gas pipeline is tied back to Statpipe.
License shares for the Brage field
License WINTERSHALL REPSOL FAROE PETROLEUM POINT RESOURCES VNG
Brage Unit 35.20 % 33.84 % 14.26 % 12.26 % 4.44 % Point Resources AS Annual Statements of Reserves 2017 11
3.1.5 Snorre
Asset overview 2°E 2°20'E 2°40'E 61°45'N Snorre is an oil field located in blocks 34/4 and 34/7 in the Tampen area in the northern part of the North Sea. The field extends over Beta the two production licenses 057 and 089. The water depth in the area is 300 – 350 m and the reservoir depth is 2000 m TVD MSL –
2700 m TVD MSL. Garantiana
Discovery Snorre was discovered in 1979 by well 34/4-1 which penetrated the rotated fault block systems on the Tampen Spur area of the 61°30'N northern North Sea. Triassic sandstones (Lunde Formation) were Snorre encountered at 2508 m TVD MSL and contained oil over a column of more than 100 m. Fields & Discoveries Point Licenses 0 5 10Km Reservoir Visund The field consists of seismically well-defined rotated fault blocks and the reservoir is mainly highly permeable fluvial sandstones in the Statfjord and Lunde Formations of Lower Jurassic/Triassic There is currently no net gas export from Snorre. Snorre and Vigdis age. The internal reservoir facies are characterized as heterogene- gas is re-injected into the Snorre reservoir. Sporadically, some gas ous and complex. has historically been exported to Statfjord A. This is redeemed from the gas balances with Vigdis and Statfjord. The possibility of The drainage strategy is pressure maintenance through gas and physical gas export via Statfjord A will terminate in 2019. water injection. Lack of injectors and injection capacity has over time led to a pressure that is lower than desired in parts of the The PDO for the Snorre Expansion Project (SEP) was submitted to field. the authorities 21 December 2017. The development concept is mainly a subsea development and will consist of the following: ·· 6 multi-purpose 4-slot templates tied back to Snorre A Development ·· 24 new wells (12 oil producers and 12 injectors) Snorre is developed with three main installations. A Tension Leg ·· An upgrade of the Snorre A installation Platform (Snorre A) in the south has accommodation, drilling and ·· Increased gas injection with additional gas import from Gullfaks processing facilities. A separate process module for production from the Vigdis field is also placed on Snorre A. Snorre Subsea Snorre expansion is one of the largest improved oil recovery Production System (SPS) is a subsea template with ten well- projects (IOR) on the NCS. Start-up is planned for 2021 and will slots located centrally on the field and connected to Snorre A. A extend the production on Snorre until 2040. The increased oil semi-submersible integrated drilling, processing and accommoda- volumes from the IOR project will increase the recovery factor from tion platform (Snorre B) is located in the northern part of the field. 46% to 51%. Snorre is the producing field in the Norwegian shelf with the potentially highest remaining recoverable oil volumes after Ekofisk. Status PL 057 has a license expiry of 1 July 2018. Further extension has The Snorre field came on stream in 1992 and is currently produc- been conditioned upon a sanction of the Snorre Expansion Project. ing some 95 000 bbl/d of oil. The average rate for 2017 was 83 000 After the SEP PDO submission, a new application for license bbl/d, which was 12% below the forecasted production for 2017. extension has been filed with the authorities for production until The main reasons for this were the following: 31.12.2040. ·· Prolonged revision stop for Snorre A ·· Lower production from the SPS wells due to loss of integrity in three water injectors ·· Unexpectedly steeper decline in some Snorre B wells
License shares for the Snorre field
License STATOIL PETORO EXXONMOBIL IDEMITSU DEA POINT RESOURCES
Snorre Unit 33.28 % 30.00 % 17.45 % 9.60 % 8.57 % 1.11 % (PL 057 and PL 089) 12 Point Resources AS Annual Statements of Reserves 2017
3.1.6 Bøyla
Asset overview 1°40'E 2°E 2°20'E 2°40'E
Bøyla is an oil field located in PL 340 in the central part of the North 59°30'N Sea, 15 km south-west of the Volund field. The water depth is 120 Alvheim Jotun A m and the reservoir is at 2000 m TVD MSL. FPSO
Discovery
The Bøyla field was discovered in 2009 by well 24/9-9 S. The Bøyla initial discovery name was “Marihøne A”. The well proved under- Ring- horne saturated oil at normal pressure with a OWC at 2071 m TVD East MSL. Subsequent pilot and development wells have confirmed Ringhorne the OWC across the field. Small corrections of top reservoir from 59°15'N production well penetrations have not had a significant effect on the overall gross rock volumes, which have increased on the crest Balder and decreased in the flanks. The reservoir parameters have been Fields & Discoveries Point Licenses confirmed by the same wells. 0 5 10Km
Reservoir The Bøyla structure is a flat low-relief Eocene fan deposit. The Status reservoir of the field is within the Paleocene/Eocene Hermod The western producer (M1) was put on stream mid-January 2015. sandstone Member, completely encased within Sele Formation The water injector (M3) started up mid-March 2015, and the shales. The Hermod Sandstone Member is interpreted as sediment eastern producer (M2) came on stream early-August 2015. gravity flows sourced from the East Shetland Platform, deposited in a basin floor setting. Hermod sandstones are assumed to have The water cut in well M1 has increased from 20% to 45% in 2017, filled bathymetric lows created by underlying Heimdal Member. but the well is still performing reasonably with a stable oil rate of about 4500 bbl/d. Well M2 has a higher water cut at 55% and the Two major depocenters have been recognized in the field, one in oil production is low but stable at 1600 bbl/d. M2 was shut in for the west and one in the east. The pre-drilled wells have confirmed a period due to gas injection, to increase pressure and stabilize a common OWC. Injection testing of the single water injector has production. proved enough injectivity and interference between the injector (M3) and the western producer (M1). Production experience shows that communication between the injector and the eastern producer (M2) is not likely.
Development The field is a subsea development with two long horizontal produc- ers (about 2300 m) and one water injector tied back to the Alvheim FPSO, 28 km to the north. Gas lift is required in the producers.
License shares for the Bøyla field
License AKER BP POINT RESOURCES LUNDIN NORWAY
PL 340 65.00 % 20.00 % 15.00 % Point Resources AS Annual Statements of Reserves 2017 13
3.1.7 Hyme
Asset overview 6°40'E 7°E 7°20'E 7°40'E
Hyme is an oil field located in production license 348 on 64°30'N Haltenbanken, west of the Draugen field, offshore central Norway. The water depth is 250 m and the reservoir is at 2150 m TVD MSL.
Bauge Discovery Njord Hyme The Hyme field was discovered in 2009 by well 6407/8-5 S and the sidetrack 6407/8-5 A. The well penetrated a 47 m thick oil-filled Ile 64°15'N Formation and a 15 m thick oil column in the Tilje Formation. In Draugen addition, a thin gas zone was encountered in the Garn Formation.
Reservoir Fenja Fields & Discoveries The structural trap is located on a rotated hanging wall block in Point Licenses 0 5 10Km the NNE trending Bremstein Fault Complex. The field comprises 64°N two segments divided by a fault. The main reservoir is the Lower Jurassic Tilje Formation, which contains oil and associated gas. The stratigraphy and reservoir properties are similar to the neighboring Njord field and the primary reservoir interval in Tilje injection well. The production well is completed with ICD/swell Formation, (Tilje 3), consists of sandstones deposited in a shallow packers with gravel packed screens. marine to tidal environment. The best sandstones have high net to gross, porosity and permeability, but other levels in Tilje are characterized by thin layers and heterogeneities. Status Njord, and thus Hyme, stopped production in June 2016 as the Development Njord A platform was towed to shore for reinforcement work August the same year. The plan is to re-commence production in Hyme commenced production in March 2013 and is developed October 2020. with a standard subsea template with four well slots. The field is tied back to the Njord facility with a production pipeline, a water Hyme showed good production performance in both 2015 and injection pipeline and a pipeline for gas-lift. The development 2016. The water cut was at 50% and the production rate at 12 000 includes one dual lateral production well and one deviated water boe/d prior to shut-in.
License shares for the Hyme field
License STATOIL DEA POINT RESOURCES ENGIE FAROE PETROLEUM VNG
PL 348 35.00 % 27.50 % 17.50 % 10.00 % 7.50 % 2.50 % 14 Point Resources AS Annual Statements of Reserves 2017
3.2 Development Projects
3.2.1 Bauge
Asset overview 6°40'E 7°E 7°20'E 7°40'E Bauge is an oil field located on Haltenbanken in the Norwegian 64°30'N Sea in block 6407/8 in production licenses 348 and 348B. Bauge is planned to commence production in 2020 through the host platform Njord A. Bauge
Hyme Discovery Njord
The Bauge oil discovery was made in 2013 by a two-branched 64°15'N well; 6407/8-6 (main bore – western segment) and 6407/8-6 Draugen A (sidetrack – eastern segment) on a down-thrown fault block adjacent to the Hyme field. It is located in the Haltenbanken area in the Norwegian Sea, about 15 km north-east of the Njord field and about 15 km west of the Draugen field. Oil was found in Upper, Fenja Fields & Discoveries Lower and Middle Jurassic sandstones from 2683 m TVD MSL to Point Licenses 0 5 10Km 2763 m TVD MSL. The water depth is 282 m. The initial discovery 64°N name was Snilehorn.
Reservoir A platform. The production wells target the eastern and western Undersaturated oil is proved in Garn, Ile/Tofte 3.2, Tilje/Åre 2 and segments separately. The drainage strategy is phased water Åre Formations, however the main oil bearing reservoirs targeted injection, with depletion for the first 3-5 years followed by water for production, consists of Ile and Tilje Formations, separated injection. Based on production experience the water injector may by Ror Formation shales acting as a barrier. The field is divided also be optimized for better pressure support. The water injector into an eastern and western segment which may or may not be will be drilled from the Hyme template and will share water injection in pressure communication during the production phase. The capacity with Hyme. Both production wells will have gas lift. reservoir quality is poor to medium with porosities of 18-20% and permeabilities of 10-300 mD. Status
Development The Operator submitted the PDO to the authorities in March 2017 and it was approved in summer of 2017. Production is planned to Bauge will be developed as a subsea field with two slanted produc- commence in 2020. ers from a two-slot template, called CAP-X, tied back to the Njord
License shares for the Bauge field
License STATOIL DEA POINT RESOURCES ENGIE FAROE PETROLEUM VNG
Bauge Unit 35.00 % 27.50 % 17.50 % 10.00 % 7.50 % 2.50 % Point Resources AS Annual Statements of Reserves 2017 15
3.2.2 Fenja
Asset overview 6°40'E 7°E 7°20'E 7°40'E
Fenja is an oil field located in license PL 586 in block 6406/12 64°30'N about 35 km south-west of the Njord field. The Fenja development consists of the Pil reservoir. The license has two additional discoveries, 6406/12-3 A (Bue) and 6406/12-4 S (Boomerang). The Bauge water depth is 325 m and the reservoir is at 3300 m TVD MSL.
Njord Hyme Discovery 64°15'N The Pil reservoir was discovered by well 6406/12-3 S in April 2014 Draugen and is a 146 m thick saturated oil accumulation with an 88 m thick free gas-cap occurring in intra-Melke Formation sandstones. Bue was discovered in the sidetrack 6406/12-3 A and contains undersaturated oil in the Rogn Member of the Spekk Formation. Fenja Fields & Discoveries The discoveries are of Upper Jurassic age at depths of 3200 – Point Licenses 3400 m TVD MSL. Only the Pil reservoir is included in reserves. 0 5 10Km 64°N Further appraisal is needed for the Bue reservoir. Depending on the appraisal result, Bue may be developed at a later stage. The Boomerang discovery will also be appraised, both discoveries will require their own decision processes for development. and upgrade (Njord Future Project). Necessary modifications related to Fenja are included in the project. Reservoir The PDO development concept includes two four-slot templated, The reservoir rocks at the Pil reservoir are part of a submarine three horizontal oil producers, two down flank water injectors and fan system, originated by erosion of older Jurassic and Triassic one well for injecting gas into the gas-cap. Bue appraisal is part sediments and granitic basement of the adjacent Frøya High of the Fenja development and depending on the outcome, Bue south-east of Fenja. The Pil reservoir consists mainly of well- development may follow as a future phase utilizing the two spare sorted, medium-grained turbidite toesets, overlain by delta foreset slots. The control system has flexibility to handle a total of 12 wells. deposits consisting of thick-bedded, conglomeratic density-flows Hence, a new four-slot template may be installed at a later stage. and debrites. At least two major fan systems are observed in the Pil reservoir interval. The lower fan system is referred to as M4, Production start is assumed to be 1 January 2021. and the upper one as M5. This north-east prograding system has later been structurally tilted and are now dipping towards east to south-east. The net to gross in the hydrocarbon zone is high (~85% Status in M5) with an average porosity of 14% and permeabilities around The PDO was submitted to the authorities in December 2017 and 600 mD. is expected to be approved by end of Q1 2018. Pre-drilling of all wells on the Pil reservoir is planned to start in 2020 and continue The Rogn Formation, being the reservoir zone in the Bue reservoir, for approximately one year. Three wells will be completed prior to is a younger shallow marine system. production start and the remaining three wells will be on stream in 2021. Development Installation of the subsea templates and injection pipelines are The Fenja development includes the Pil reservoir as a tie-back to planned for the summer of 2019, and the production pipeline is the Njord A platform which currently is at shore for modifications planned to be installed in 2020.
License shares for the Fenja field
License VNG NORGE POINT RESOURCES FAROE PETROLEUM
PL 586 30.00 % 45.00 % 25.00 % 16 Point Resources AS Annual Statements of Reserves 2017
4 Contingent Resources
Point Resources’ contingent resources are primarily associated A host feasibility and cost study will be undertaken in early 2018. with incremental IOR and EOR projects on Balder, Ringhorne, Based on a positive outcome the project may be matured to DG2 Ringhorne East, Brage, Bøyla, Hyme and Snorre. These are projects in Q1 2019. that are in the planning phase or they are incremental projects where recovery is probable, but a project development plan has not been decided on. In addition, the Garantiana development in PL107D Noatun PL554, the Brasse discovery in PL740 and the Beta discovery in The gas-condensate volumes in Noatun awaits a gas evacuation PL375 contribute considerably to the contingent resource volume. solution. The current assumption is that Noatun will be tied in to The PL107D Noatun gas-condensate discovery is on hold with an Njord around year 2025. The resource estimates are taken from expected start-up beyond 2025. Point Resources has 176 mmboe the Noatun RNB 2018. classified as contingent resources as of 31 December 2017, up 32 mmboe from the previous year’s reporting. PL586 Fenja, Bue Balder, Ringhorne and Ringhorne East PL586 contingent resources are related to the Bue discovery and are based on the RNB 2018. The Balder, Ringhorne and Ringhorne East Fields contingent resources are risked resource estimates of future infill well targets in resource class 4 and 5. PL554 Garantiana The volumes in the Garantiana contingent resources are based Brage on the Operator’s reported RNB 2018. The development concept is a subsea tieback to Gullfaks and Visund with injection water The Brage Field contingent resources are unrisked resource from Visund. A total of six wells is assumed with three injectors estimates of future infill well targets in resource class 4 and 5. and three producers. An injectivity study is ongoing to evaluate the Additional EOR potential for WAG and PASF is also included. possibility of having only one injector. The geological and simula- tion models will be updated with a new seismic interpretation, new Snorre fault interpretation and an updated interpretation of the DST tests prior to a scheduled DG2 decision in 2018. Contingent resources in the Snorre license are associated with future development projects that have not been evaluated due to timing considerations. The following are examples of this type of PL740 Brasse development: Brasse is an oil and gas discovery in the Sognefjord Formation, ·· Extended field life to 2050, DG0 in 2025 discovered in June 2016. An additional appraisal well was drilled ·· Extended drilling (2035-2045), DG0 in 2025 during 2017 and the project passed DG1 in December 2017. Concept selection and DG2 is schedule for H2 2018. Volumes PL 348 Hyme and Bauge included in contingent resources are based Operators RNB 2018. The PL348 contingent resources include the Hyme in-fill drilling which is based on RNB 2018. Other discoveries There are some discoveries in the Point portfolio where a viable PL340/340B Caterpillar development concept is not in place at this point in time. These discoveries are the following: The volumes associated with the Caterpillar discovery are based ·· PL375 the 34/4-10 Beta Brent discovery on Operators RNB 2018. The Operator has scheduled a DG1 in Q1 ·· PL554 Akkar discovery 2018 where the development concept is a single oil producer with ·· PL586 Boomerang and 6406/11-1 discoveries an in-situ water injector between Heimdal and Hermod. Production ·· PL746S Hernar – Point Operator, appraisal planning ongoing is planned to be tied back to the Bøyla manifold. ·· PL796 Cortina ·· PL833 Tau ·· PL834 Galtvort PL375 Beta The estimated PL375 contingent resources are based on an in-house geological model and uncertainty studies. The develop- ment concept assumes one injector and one horizontal producer. 5 Management’s Discussion and Analysis
Point Resource’s reserves estimates are based on standard Point expects, projects, believes or anticipates will or may occur in industry practices and methodologies such as decline analysis, the future. These statements are based on various assumptions 3D reservoir modeling, geological and geophysical analysis. The made by Point, which are beyond its control and are subject to evaluations and assessments have been performed by engineers certain additional risks and uncertainties. As a result of these with extensive industry experience, and the methodology and factors, actual events may differ materially from those indicated in results have been quality controlled as part of the company’s or implied by such forward-looking statements. internal reserves estimation procedures. The 2P reserves estimate for the Point portfolio is 193.5 mmboe, A third party independent assessment has been performed by which represents a substantial increase compared to the previous AGR on all of Point’s fields that have remaining hydrocarbon annual reserves report, which was 14 mmboe. The increase volumes categorized as reserves. The assessment is based on is mainly due to the acquisition of the Balder, Ringhorne and input data provided by Point, as well as full access to subsurface Ringhorne East Fields and the development decisions of Bauge data and license documentation. AGR forms an independent and Fenja Fields. The assessment of the 2P reserves represents view on reserves on this basis. The independent review endorses the expected outcome for the fields based on the performance the production forecasts and reserves in this report and hence observed to date, and the planned activities in the licenses. With serves as a verification of the Point Resources reserves estimates an additional 176 mmboe in contingent resources for the Point presented in this report. portfolio, the total 2P and 2C resource estimate adds up to 369 mmboe for Point Resources. The information included herein may contain certain forward-look- ing statements that address activities, events or developments that
Point Resources AS Annual Statements of Reserves 2017 19 artbox.no
pointresources.no