The Ceiba Field was discovered in October 1999 and first production was achieved in November 2000, less than 13 months from discovery. Initial production during 2001 was from 5 wells into the Sendje Berge FPSO (Floating Production, Storage, and Offloading vessel). In January 2002, this vessel was replaced by the Sendje Ceiba which has a total liquids processing capacity of 160,000 bpd and facilities to inject up to 135,000 bwpd into the Ceiba reservoir to maintain field pressure and optimise oil recovery. Field development now comprises 16 producing wells and 12 water injector wells. Peak production of 72,000bopd was achieved in 2001 with average daily production in 2011 of 19,400 bopd. The EUR from the Ceiba Field is 229 MMBO.
The Zafiro Field Complex
In 2012 the Zafiro Field complex produced an average of 109,000 bopd and 120 mmcfd of gas via the Zafiro Producer FPU, the Jade Platform, and the Serpentina FPSO facilities. Zafiro was discovered in 1995 and was brought onstream within eighteen months of discovery. Facilities have been expanded each year since production commenced. In 2000, the Zafiro Producer FPSO was converted to an FPU (Floating Production Unit) with crude oil being stored in the MT Magnolia FSO (Floating Storage and Offloading vessel), which has a storage capacity of 1.8 million bbls. Gas is separated from the oil on board the FPU and the oil is sent to the FSO where it is stored until it can be exported to tankers via a Single Point Mooring (SPM) system. In December 1999 a 60,000 bopd fixed platform facility (Jade) was installed. By May 2001 production from Jade had reached capacity at 50,000 bopd. Gas is separated from the crude on the platform and the oil exported via pipeline to the Zafiro FPU. In 2002, the Serpentina FPSO was added to the southern part of the field, leading to peak rates of over 300,000 bopd. Oil from Zafiro and Jade is now transported via pipeline to the Serpentina Producer for storage and offloading. The field is being produced via a total of 117 wells (73 subsea and 44 platform) comprising 92 producers, 24 water injectors and 1 gas injector. The Estimated Ultimate Recovery (EUR) from the Zafiro Field is 1.199 billion barrels.
Alba is a gas condensate field with total reserves expected to exceed 5 Tcf. The Alba Field was discovered in 1983 but was not placed on production until 1991 when it was developed solely for its condensate production by Walter International Inc.. By 1995, when Nomeco acquired Walter, Alba was producing at a rate of around 65mmcfd to yield over 6000 bpd of condensate with all the gas being flared. During 2000 CMS (who had acquired Nomeco) drilled the Alba -6, -7 and -8 development wells and by mid 2001 Alba was producing over 195 mmcfd, to generate 14,000 bcpd and 2,000 bbls LPG/day. The processed gas supplies a new methanol plant which is designed to produce at a rate of 19,000 bpd from with minimal gas flaring. In January 2002, Marathon Oil acquired the CMS interests in Equatorial Guinea and embarked on a significant expansion of the producing and gas handling facilities in the field.
Following the commissioning of the LNG plant in 2007, the gas offtake from the field has risen to 900 mmcfd. This gas provides feedgas to the LNG and Methanol plants, is used in local power generation, and yields some 70,000 bpd of LPG and Condensate.
Average daily gas sales in 2011 were 850 mmcfd with liquids production of 44,000 bpd condensate, 13,000 bpd Propane and 7,500 bpd Butane. . The Alba Field has reserves of 5 TCF wet gas with an estimated 330 MMBbl of recoverable condensate.
The Okume Complex was discovered in 2001 and celebrated first production in December 2006, less than 3 years after approval of the Plan of Development. The Okume Complex is comprised of the Okume, Oveng, Ebano and Elon fields which have been developed using a combination of two tension leg platforms and four fixed platforms. Production from the fields is gathered at a central processing facility (CPF) located at the shallow water Elon field. From there, a fifteen mile subsea pipeline connects the CPF to the Sendje Ceiba floating production, storage and offloading vessel (FPSO) for storage and offloading of crude production. The field is currently being produced via 27 producing wells and 13 water injector wells. Peak production of 86,000 bopd was achieved in 2010 with average daily production in 2012 of 59,000 bopd. The EUR from the Okume Field is 297 MMBO.
The Aseng Field was discovered in Block I in 2007 and was initially thought to be a gas condensate field. Subsequently, two appraisal wells were drilled in the structure, with the first identifying oil resources beneath the gas condensate and the second determining downdip reservoir limits. The Aseng Plan of Development was approved in July 2009 with the initial development of the field consisting of five subsea wells flowing to a floating production, storage, and offloading vessel (FPSO) where the production stream will be separated. The oil will be stored on the vessel until sold, while the natural gas and water will be re-injected back into the reservoir to maintain pressure and maximize oil recovery. First production from the field was estimated to commence by mid 2012, however, the Aseng FPSO arrived on location on October 16th, 2011 and first oil was achieved on November 6th, 2011, some seven months ahead of schedule. The first tanker of oil from the Aseng field was offloaded in December 2011. Average daily production in 2012 was 60,000 bopd.
The Aseng FPSO has an oil production capacity of 80,000 barrels of oil per day, a gas handling capacity of 174 million cubic feet per day, a produced water handling and disposal capacity of 100,000 barrels of water per day and a water injection capacity of 150,000 barrels of water per day. The Aseng FPSO has a total cargo storage capacity of 1.5 million barrels.
Estimated recoverable reserves are approximately 100 to 120 million barrels, In addition, there is an estimated 450 to 550 billion cubic feet of gas resources at Aseng that will be produced as part of an integrated gas monetization project once the pressure maintenance phase is completed.
The Alen Field was discovered in 2005 by the O-1 exploration well and was appraised by the O-3 and I-4 wells in 2007. Alen is a gas-condensate field located substantially in Block "O" and extending into the northern part of Block "I”. The Alen Plan of Development was approved in January 2011 and field development will comprise of an initial phase of gas recycling and condensate stripping followed by gas production which will go to Equatorial Guinea's Integrated Gas Project.
First production at Alen is estimated to commence by the end of 2013 at 37,500 Bbl/d of condensate. Natural gas production is planned for up to 440MMcfd and stripped gas will be reinjected to the field for at least three years.
The Alen processing facility will be a fixed platform located in approximately 85m of water which has purposely been sized to act as a gas gathering hub within the State's Integrated Gas Project. The fully developed processing capacity of the platform can be up to 750MMcfd. A 24inch riser will be installed on the platform at commissioning to allow an easy link to the future sales gas line and ample space has been allowed to accommodate flowlines from additional fields plus full compression and processing requirements for the expanded gas volume.
Estimated recoverable reserves are approximately 88 million barrels of condensate and an estimated 930 billion cubic feet of gross natural gas resources that will ultimately be produced as part of Equatorial Guinea's integrated gas monetization project.