All posts tagged deepwater

By Moses Aremu

West Africa remains the top deepwater exploration and production destination on the planet. In the sixteen years since the contest for deepwater spoils was established, this corner of the south Atlantic has led the two other contestants: Brazil and the US Gulf Of Mexico, in attracting investment dollars.

In spite of the recent boost in activity of the US Gulf of Mexico and the discoveries of huge reservoirs below the salt cover in deepwater Brazil, the early lead that West Africa had taken in the mid nineties has turned its waters into a vast, busy parking yard for FPSOs, with such decade old fields as Zafiro, Girassol and Dalia each doing in excess of 150KBOPD on average, even as reservoir maintenance work sets in; relatively newer fields are gushing oil at world class rates and a queue of field development projects are lined up from Equatorial Guinea to Angola.

1. Take a look at fields that coming on stream in the next two to four years:

ANGOLA

Pazflor.  TOTAL’s Pazlor project in Block 17, will develop production from the Perpetua, Acacia, Zinia and Hortensia discoveries.  First oil is expected in 2011 at the initial rate of 220,000 BOPD. The four fields are scattered over an area of 600 square kilometers, six times the size of Paris, at a water depth of about 1,200metres. Acacia contains light oil, whereas the other three are Miocene characterized by heavy, viscous oil. TOTAL plans to use subsea oil-water separators for the Heavy Oil reservoir. The separated oil and water will be pumped to the FPSO using Electrical Submersible Pumps(ESPs). TOTAL has built an FPSO capable of processing 220,000 BPD of oil and with storage capacity of 1.9 million barrels, The produced water will be re-injected into the reservoirs. The two subsea production systems encompass 49 wells (25 producers, 22 water injectors and two gas injectors) and three subsea separation units connected to six ESPs. The topsides control system is designed to accommodate 21 additional wells and a fourth Subsea separation unit.

CLOV, also in Block 17, will involve gathering hydrocarbon fluids from tour fields: Cravo, Lirio, Orchidea and Violet (CLOV). TOTAL has received approval from its partners to begin drilling in 2012 so as to achieve first oil in 2014. The subsea development will consist of 34 wells tied back to an FPSO with a processing capacity of 160,000 BPD at plateau and storage capacity of 1.78 million Bbls. The FPSO will be able to process two types of crude oil, light oil from Oligocene reservoirs and heavier oil from Miocene reservoirs. Both oil streams would be combined aboard the FPSO in a single train prior to storage.

EQUATORIAL GUINEA:

Aseng: First production from the Aseng field is estimated to commence by mid-year 2012 at 50,000 barrels of oil per day gross (16,500 barrels per day net). Equatorial Guinea’s authorities approved the field development plan for this Noble Energy operated field in July 2009. Located in Block I, it represents the first oil development in the country’s part of the Douala Basin. Initial development of the field will include five subsea wells flowing to a floating production, storage, and off loading 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 injected back into the reservoir to maintain pressure and maximize oil recoveries. The FPSO, to be located in approximately 945metres(3,100feet) of water, will be designed with capacity to handle 120,000 barrels of liquids per day, including 80,000 barrels of oil per day. In addition, the vessel will be capable of re-injecting 170 million cubic feet per day of natural gas. Storage on the vessel will be approximately 1.5 million barrels of oil and condensate. Total cost of development, excluding the cost of the FPSO, which will be leased, is estimated at $1.3 billion ($530 million net). The majority of this capital is to be invested in 2010 and 2011. Over the life of the project, the company expects to recover gross hydrocarbon liquids of approximately 100 to 120 million barrels, with initial reserve bookings beginning in 2009. 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.

AlenFirst production at Alen field, in deep- water Equatorial Guinea, is estimated to commence by the end of 2013 at 37,500 Bbl/d gross (18,750 barrels per day net). The country’s Ministry of Mines, Industry, and Energy approved the field development plan in December 2010. Initial field development will include three production wells and three subsea natural gas injection wells tied to a processing platform. Produced condensate will be separated and piped to the Aseng floating production, storage, and offloading vessel on Block “l’ 24km to the south, where it will be held until sold. Associated natural gas will be re-injected back into the reservoir to maintain pressure and maximize liquid recoveries. The Alen processing facility will be located in approximately 240 feet of water and is designed to handle 440 million cubic feet per day (Mmcf/d) of natural gas and 40,000 barrels per day (BCPD) of condensate. Natural gas reinjectiori is estimated to be 380 Mmcf/d during gas-recycling. The total cost of development is estimated at $1.6 billion ($735 million net).

NIGERIA

Usan Production startup is projected for this TOTAL operated oilfield, in 2012. Maximum total production of 180,000 BOPD is expected by 2013. Located in 900metres of water, Usan Field was discovered in 2002 and began development in 2008. Development drilling commenced in June 2009. There will be 23 production wells as well as 19 water and gas injection wells. Hyundai Heavy Industries will deliver the FPSO in late 2011. Cameron was awarded the contract for the 44-well subsea development.

2. And those that may come on stream in the next four to seven years…

NIGERIA

Egina: Front-end engineering design of TOTAL’s deepwater Engina development was nearing completion as of July 2010. The French major awarded the subsea FEED to Nigerian company Dover Engineering in July 2009, with Wood Group companies J P Kenny and MCS Kenny assigned to support the project’s delivery. Egina, discovered in 2003, is in 0ML130, in water depths up to 1,750 m. The Greater Egina development will take in the Egina Main, Egina South, and Preowei fields, although the current programme only covers the Egina Main field — the other two fields are probable future tiebacks. The subsea work scope of work included design studies and engineering assessments; development of specifications; and documentation and technology studies, all relating to the design of the umbilicals, flowlines, risers, and the subsea production systems.

Uge: Negotiations with government and partners for field development is moving slowly along for this 2006 discovery. Uge-1 encountered 100 meters net oil in 1,263 meters of water in OPL 214. The discovery well was drilled a total depth of 5,260metres.

Bosi: Sanction for ExxonMobil operated Bosi field development has been much slower than would have ordinarily been expected of this 1996 discovery. Since a Final Investment Decision(FID) hasn’t happened, all figures are mere estimates. One such is that production will be around 135,000 BOPD optimum, and the crude will be stored in a refurbished FPSO.

Aparo and Bonga SW.

These two fields share a common geologic structure and will be developed simultaneously. The structure is located in 1,344m water depth. The project was delayed in 2009 to secure agreement among the stakeholders on the scope and commercial terms of the project.

Nsiko: Chevron’s next Deepwater project is Nsiko Field, located 144km offshore the western Niger Delta at 1,812m water depth. Subsurface evaluations and field development planning were completed in 2008. Development activities and FEED will begin upon negotiation of the commercial terms.

3. And still in the smithy…

West Africa’s New deepwater discoveries:

GHANA

Twenoboa/Owu

This is what Tullow Oil, the UK listed independent, says: “In March 2009, the Tweneboa-1 exploration well discovered a highly pressured light hydrocarbon accumulation. This was followed up by the successful Tweneboa-2 well in January 2010, which encountered oil and gas-condensate 6km south of the original discovery. In July, the Owo-1 oil discovery continued the extraordinary success of Tullow’s West African Equatorial Atlantic campaign, intersecting 53 metres of net oil pay, establishing Owo as a major new oil field. Further appraisal of both fields will form a major part of the 2011 programme with additional prospects already identified.”

 By Fred Akanni, in Libreville

Gabon has been out in the cold since I lit onset of the contemporary phase of deepwater exploration in the Gulf Of Guinea This is what the deepwater bid round, scheduled to kick off in May 2010, is about to change.. Gabonese authorities believe that the country’s deepwater acquatory has never been properly explored.

The country was producing it around 350,000Barrels of Oil Per Day (BOPD), about the highest in its production history, in the mid I 990s, when countries like Nigeria nod Angola started witnessing a series of spectacular discoveries in water depths outboard of 750 metres. As Gabon shares the prolific Congo basin with Angola, and was the third largest oil producer in sub-Saharan Africa, it was expected to be part of the game. But the wildcats that were later drilled in deepwater Gabon in the first few years of the 21st century failed in a big way.

• In 2001, a consortium led by TOTAL drilled Judy 1, Genny 1 and Renee 1 to 4806metres, 4793metres and 4047metres respectively, all very deep wells, in the Astrid Marin acreage. They were all located in excess of 2000metre Water Depth. They were all disappointingly dry holes.
• Inshore, in the Anton Marin acreage, Jeane-1 was drilled to 2882mTD in water depth of I ,500m. It was also a dry hole.

As these wells were all located in the lower Congo Basin, where operators in Angola had been having a field day harvesting giant oil fields, it was beginning to look like Gabon might not be part of the West African deepwater party.

But Agip wasn’t so sure. The Italian major picked up a lease northwards in deep offshore Ogooue Delta, part of the Gsbon Coastal Basin. This was even a riskier spot; unlike the broad, gentle slope from shallow water to deepwater in the Lower Congo basin, the descent to deep offshore is rather abrupt. In 2002, Agip came up dry at a TD of 2,882m in Powe Marin 1, drilled in 1,000m Water Depth on the Awoure lease.

In 2005 Amerada Hess, running on adrenalin from its successful foray in deepwater Equatorial Guinea, drilled two equally disappointing wells in deep offshore Ogooue Delta.

So what happened?

There have been explanations for the poor results in the Gabonese deepwater segment of the Oogue and the Lower Congo Basins.

• The Ogooue Delta is not formed by the kind of large sized rivers like the Congo River which birthed the Congo Basin, or the Niger and Benue rivers which created the Niger Delta.

• The part of the lower Congo Basin that is in deepwater Gabon contains the obligatory hydrocarbon source, but it is buried too deep and the apparent lack of structuration disallows the source to adequately charge the reservoirs. Seismic data doesn’t suggest the presence of large scale canyons that could help deliver products of turbiditic flows into the deeper waters. There have been questions about of whether the direction of flow of the Benguela currents, which impact sediment movement on the Nigerian coast for example, could have anything to do with the possible lack of commercial hydrocarbon reservoirs in deepwater Gabon. The jury is still out on that.

Gabonese authorities, aided by IHS energy, a firm of industry scouts, say that there is enough information in hand for the bid round to aid operating companies in determining the best locations for sizeable reserves of oil. A survey by CGG Veritas, launched in March 2009, includes more than 9600km of 2D seismic in Gabon’s southern and northern offshore zones, as well as a proposed 4,500 sqkm of 3D and 2D data in the southern zone.

Gabon desperately needs to shore up production, which has declined from 365,000BOPD in 1995, to 234,000BOPD in 2008.

By Toyin Akinosho

Nigerian deepwater oilfield activity is back in exploratory phase, in the main.

 With eight billion barrels of proven reserves, a daily output of 520,000barrels per day of crude oil and a long queue of oil field development projects waiting for approval, the Nigerian deepwater province is far from reaching the fullness of the potential that operators thought it had when the first set of 3D seismic data were acquired 1994.

Some companies hit the mother lode thick and fast (ExxonMobil and Shell are producing Erha and Bonga  respectively at around 180,000 BOPD respectively, down from an excess of 200,000 BOPD each and both are working on field extensions). Others (like Conoco Phillips, Statoil),quietly folded their arms when the expected elephants didn’t show up on their telescopes, and yet a company like Agip ignored the rules of deepwater field size versus threshold financial profitability and put the 100 million barrel Abo field, located in 500 metres of water, in production, ramping quickly up to 30,000BOPD. (The production had fallen to 19,000BOPD by early 2008 and was to have been boosted by two new wells drilled later in that year). Devon Energy walked out and Petrobras has gone very quiet. Other operators are caught in the less emotional corridor between the spectacular and the disappointing. Chevron brought Agbami on stream at 65,000BOPD in July 2008 and it has ramped up to 135,000BOPD by December 2008. It’s not just the slowest of the big three producing fields in deepwater Nigeria, the production is far below the expected 180,000BOPD anticipated in the first six months of production for the 800MMBO field, TOTAL’s Akpo is on course for first oil before the end of 2009 and the company’s Usan-Ukot and Egina fields are expected on stream between 2011 and 2012. The last really big deepwater fish on queue for first oil in Nigeria is Bonga SW/Aparo, expected on stream about 2013.

With mixed results all over, oilfield activity in this segment of the Niger Delta basin has come full circle and back to where it all started; the exploratory phase. The mood is: “let’s go and check out what else is there”.

Newcomers and grizzly old hands are completing new seismic acquisition and drilling both rank wildcats and first appraisals, largely in areas that have proven to be prospective.

BG, the British gas company, commenced its drilling programme in the Oil Prospecting Lease OPL 286-DO, which was carved out from what used to be Chevron operated OPL 218. The company plans two wells on this lease before moving to OPL 284, which, DPR officials think “is far more prospective”. Its Ogide 1, located in the general, high pressured Boi -1 area(See story on page 13), is being drilled with the semi submersible rig Sedco 702.

After a sustained period of production and development work, Agip is drilling an appraisal well outside the Abo field licence area. The semi submersible rig MG Hulme Jr has reached a depth of 4,000metres subsea in Oberan 2, the first appraisal of the 2003 discovery in what was then OPL 211(now Oil Mining Lease OML 134). The logging programme is fairly comprehensive, including coring and-if there is oil as expected- testing the well. Agip is hoping that the well confirms or even increases, the 200MMBBO it hopes the Oberan structure holds. Swiss operator Addax, who has largely operated on the shelf, commenced its first major activity in deepwater in December 2008 and is currently completing a 1,000sq km of 3D survey in the Oil Prospecting Lease (OPL 291), lying between 500 and 2,500metres of water. The block was carved out of Chevron’s OML-127 (after production permit was granted) where the giant Agbami is seated. The acquisition will cover the northern part of the block extending into north OML- 127. If this G&G exercise in this block comes out successful, then Agbami might have a good tie-back customer in

Addax.

Petrobras is on queue to acquire 3D seismic with the PGS vessel that is doing the acquisition for Addax.

America’s largest major in Nigeria does not have exploratory wells on the drilling queue in 2009. ExxonMobil will acquire fourth dimensional 4D seismic data on the Erha field, but it doesn’t plan any drilling, exploratory or development, on any of its operated deepwater acreages in 2009.

Chevron may drill one well in OPL 247, now that it has evaluated the carpet 3D it acquired on the lease The company plans exploration drilling elsewhere in its operated deepwater acreages, but no candidate has been firmed up due to rig scheduling and ranking issues.

There are, for example, three candidates, “but the reserves figures are not giving the operator any comfort”, according to a source at the state owned NNPC, which is the concessionaire for all operated leases in deepwater Nigeria. Chevron is still drilling in Agbami for development and production purposes. Shell and TOTAL, on the other hand, have better defined, active drilling schedule, outside of ongoing development activity. Shell plans to drill four exploratory and appraisal wells, apart from the development work on extending Bonga production farther north. The company completed a 4D seismic acquisition on the Bonga structure in early 2008, but the 2009 exploration and appraisal campaign excludes the general Bonga area. Discussions are ongoing to resolve the dispute around OPL 245, where Shell discovered Etan and Zabazaba, its most recent finds and its not clear if any of the four wells is planned for this lease but some of the appraisal work will certainly be in OML 135, where Shell has the undeveloped  discoveries Ngolo, Bolia and the Nnwa-Doro gas field.

TOTAL plans to drill a well in the Continental Oil and Gas held OPL 257, which adjoins SAPETRO’s OML 130. TOTAL is the technical operator of both OPL 257 and OML 130 and -if it works-the proposed well in OPL 257 is meant to be part of the overall development of the Egina field, which is expected to come on stream in 2012.

What’s clear in the overall Niger Delta deepwater 2009 drilling activity, no company is venturing into the outer toe thrust belt. The great story of Nigerian deepwater, in the last five years, is the spate of disappointing wells that were drilled by Agip (Dou 1 and Emein 1, OPL 244), Chevron (Iroko 1, OPL 250), Phillips (Onigun 1, OPL 318), Petrobras (Erimi 1, OPL 324) and Ocean Energy 9Pina 1 and Tari 1, OPL 256). What’s happening may be a lot of exploratory work, but it’s taking place in areas already deemed safe bets.

 By Stewart Williams and Alison Dines, Wood Macenzie

THE GENERAL PERCEPTION ACROSS West Africa’s oil industry is that the high cost inflation seen over the last few years is slowing, particularly with respect to rig rates. Absolute costs, however, are still increasing and 2008/9 will see deepwater drilling rates surpass the $500,000 per day mark for the first time. The specific rig in question is the West Capelle, a new-build driliship, which is due to begin drilling for TOTAL in Nigeria in the third quarter of 2008. Its sister ship, the West Polaris, is also due to start operations in the Gulf of Mexico. After completing its programme with ExxonMobil, the West Polaris will move to West Africa to drill exploration wells in the Nigeria, Sao Tome et Principe (NSTP) JDZ, Equatorial Guinea and Gabon.

With exploration in the region set to increase again and prospects being located in ever- increasing water depths, Wood Mackenzie has examined the effect of cost escalation in the deepwater Niger Delta. While the US Gulf of Mexico, with its very attractive fiscal terms, can support such day rates and subsequent development costs, West Africa has tougher fiscal terms and Nigeria is an increasingly expensive development area. This insight examines the reserves threshold for commercial oil development in Nigeria and the Nigeria-Sao Tome and Principe JDZ under the existing range of fiscal terms in this deepwater region using typical development cost scenarios.

Methodology

We have created four model fields containing between 100 and 600 million barrels to analyse commercial reserves thresholds in the deepwater Niger Delta. Cost estimates for the model fields are based on our knowledge of current exploration costs and future development cost expectations of the major oil companies.  The table shows the range of capex for the individual model fields.

High day rates for drilling have accompanied increases in costs for facilities and subsea equipment too. In fact, it is subsea that is the strongest growth area in terms of costs. At the start of the decade, unit capital costs for West African deepwater projects sanctioned for development were around $4 per barrel (nominal). For projects awaiting sanction today, these costs have tripled to at least $12 per barrel, but in many cases more than this.

We assume that these model fields are in water depths greater than 1,000 metres -water depth affects royalty rates -and also has a bearing on exploration and development

costs. We have used Wood Mackenzie’s latest price assumption that assumes a flat long-term real oil price of $50 per barrel (2008 terms).

We have modeled full-cycle returns. The model fields have a 2008 discovery date and first produce in 2015, following first development expenditure in 2011. Although 2015 may seem pessimistic, seven-to eight-year lead times are typical of Nigerian deepwater projects. Satellite developments have been performed much more quickly than this, but our scenarios assume a standalone new field development. All cases assume subsea wells tied back to a new-build floating, production, storage and offloading (FPSO) vessel.

Results and Discussion

The following chart shows the range of full cycle IRRs under four PSC systems that currently apply in deepwater Nigeria and the NSTP JDZ.

The chart demonstrates the evolution and general toughening of fiscal terms in Nigeria from the first deepwater round in 1993, when lenient terms were offered to encourage high risk drilling, to the tougher terms in the latest bid rounds, which have also been accompanied by high bonuses.

Under the latest Nigerian fiscal terms and cost estimates, around 400 million barrels has to be discovered to achieve a 15% full-cycle return. Discoveries over the last five years, however, have been getting smaller, typically less than 300 million barrels. Most major operators agree that the largest fields have already been found and that it will be difficult to develop new discoveries, even in a high oil price environment. In the early 2000s, the reserve thresholds were much lower, mainly because costs were substantially below the levels seen today.

We have not included signature bonuses in this chart but with a bonus of $50 million (the minimum set for the 2005, 2006 and 2007 bid round deepwater blocks) a 15% will be difficult to achieve, even with a 600 million-barrel discovery.

Why are costs particularly high in Nigeria?

Nigerian projects do attract a risk premium but it is difficult to put a figure on this — the contracts here are more expensive for a number of reasons. Security concerns in Nigeria mean that oil companies have to increase pay to encourage both their own staff and contractors to work there. A history of contract award delays, project design changes and significant re-tendering for contracts also add a premium when contractors are bidding for work in the country.

Another key issue facing operators is the local content requirement. Although Nigeria has been producing oil for over 50 years, it is only in the last few years that local participation has been pushed by the government. The haste in which this has been introduced means that there has been little time for Nigeria to build capacity in the local service and construction sectors that is required if all new deepwater projects are to meet the 70% built-in-country requirements. While the regulation is still not passed into law yet, the Nigerian National Petroleum Corporation’s (NNPC) Nigerian Content Division is trying to enforce it and this is becoming a barrier to project sanction.

Further costs are incurred in Nigeria through the addition of indirect taxes, which include VAT, import and custom duties, the Niger Delta Development Commission levy and education tax.

Company Outlook

The high cost issue is impacting the corporate view of the region. Already in 2007, we have seen several mid-sized to large lOCs either pull out or farm down their Niger Delta deepwater positions. Devon Energy and Pioneer have left the region completely, Chevron is farming down its share of the Nsiko deepwater discovery and ExxonMobil sold its share of the NSTP JDZ Block 1 (Obo discovery) to Addax in September 2007. Press reports suggest that Occidental, who only returned to Nigeria in 2005, has sold its deepwater position, which includes a stake in the Uge oil discovery.

Although many players are diluting their deepwater positions, others are still building theirs despite the high cost environment. Addax, a very successful Nigerian-shelf player, now has a significant deepwater portfolio in Nigeria and the JDZ. The company’s acreage in Nigeria, OPL 291, is one of the more prospective blocks and has the potential for a large discovery. In the NSTP JDZ, Addax now has an interest in four adjacent blocks, which could lead to cluster developments. This would probably lower each field’s individual reserves threshold required for commerciality. This is not the case with other, smaller Nigerian finds which are generally far apart from each other. BG too is developing a deepwater position and acquired a stake in OPL 323 in August 2007. This was, by far, the most sought-after block in the 2005 round due to its perceived prospectivity.

Conclusions

With commercial reserves thresholds increasing and discovery sizes falling, we expect to see a general slowdown in Nigerian deepwater development. Although the terms have become tougher (through a combination of legislation changes and competitive bidding), it is increasing development costs that are driving the increase in reserves needed for commerciality. Even existing fields with good terms and large volumes, such as Usan, Bosi and Bonga SW, have seen development schedules slip due to rising costs.

Satellite developments will become more attractive, as will infill drilling on the existing large developments that have attractive fiscal terms. However, if deepwater momentum is to continue in the region, then new development concepts have to be considered and NNPC may be able to help by considering some flexibility on the local content directives.

For new discoveries, reducing the time between discovery and first oil would improve the economics. Short lead times have been difficult to achieve for a number of reasons. OPEC constraints exist in Nigeria and the government has staggered deepwater development approvals to balance supply with the output from higher tax areas on the onshore and shelf. This problem should not be a concern in the Nigeria-Sao Tome Principe JDZ as production from this area is understood to be outside of Nigeria’s OPEC quota. The recently announced NNPC restructuring, however, does not bode well for the short-to mid-term as it may be difficult to get NNPC’s approval for project sanction.