Independents, IOCs lead exploration of frontier regions

Tullow also says there might be more to come from the Greater Jubilee area. The Sapele and Dahoma satellite exploration projects are to the southeast of Phase I and the first steps in exploratory drilling are in progress.

With all the Phase I drilling complete at Jubilee, downhole equipment for production and water/gas injection is being installed by theEirik Raude, and an FPSO for the field is under construction at Singapore.

Earlier this year, work on installation of the process modules, external turret, and commissioning were proceeding on schedule. The subsea equipment is ready for installation, says Tullow, and work on installation of flowlines, seabed piles, manifolds, and control umbilicals is in progress.

At the end of 2009, Tullow awarded Technip contracts covering the engineering and fabrication of seven 10-in. (25-cm) diameter and two 8-in. (20-cm) diameter risers with a combined length of 27 km (17 mi). The second was for engineering, fabrication, and installation of 48 km (30 mi) of production and gas/water injection flowlines; installation of 26 km (16 mi) of umbilicals, nine flex-risers, plus the subsea manifold and riser base. Technip also will connect the flowlines to the wellheads and subsea manifolds, then test the complete system.

Tullow has ordered 19 subsea trees from FMC Technology for Phase I, and FMC also supplies the manifolds.

The overall development plan for Jubilee Phase I was approved by the government of Ghana last year. Those plans call for the FPSO scheme to deliver 120,000 b/d of oil at full flow. The FPSO also will inject up to 230,000 b/d of water and have a gas export and re-injection capacity of 160 MMcf/d.

Tullow says the Jubilee Unit Area has a gross resource base of 500 MMbbl of oil through a most likely 700 MMbbl to an upside of 1,000 MMbbl.

Tullow’s initial equity in Jubilee, which it will operate, is 34.7%. Other partner interests are Kosmos Energy (23.49%), Anadarko Petroleum (23.49%), Sabre Oil & Gas (2.81%), EO Group (1.75%), and the Ghana National Petroleum Corp. (GNPC) (13.75%, of which 10% is carried interest).

Meanwhile, Tullow recently confirmed the existence of a second large offshore oil field with its Owo oil discovery about 30 mi (50 km) off Ghana’s coast.

In July, the Owo-1 exploration well encountered 53 m of light oil pay. This is being followed by a sidetrack well after which new resource guidance will be provided for the separate Owo and Tweneboa fields. Additional appraisal drilling is now scheduled for both fields in the coming months. The Owo field is estimated at 70-550 MMbbl. “Owo is a major new oil field,” Tullow said in a statement.

In March 2009, the Tweneboa-1 exploration well, in the Deep Water Tano licence 25 km (15 mi) from Jubilee, discovered a highly pressured light hydrocarbon accumulation of up to 1.4 Bbbl of oil equivalent, according to Tullow.

The well encountered 21 m (69 ft) of net pay on the edge of a giant 200-sq-km (77-sq-mi) fan system related to the Jubilee play. Intriguingly, the well also encountered a four-meter over-pressured oil-bearing sand and an over-pressured zone at total depth.

Tullow planned to carry out appraisal drilling to test core areas of the structure where thicker reservoir sections are mapped. The second well, Tweneboa-2, began drilling toward the end of 2009. In January of this year, Tullow announced that the well had encountered two separate hydrocarbon columns containing oil and gas-condensate legs. In total, 32 m (105 ft) of net pay were encountered.

According to energy analysts Raymond James, the Tullow-operated Tweneboa field has resource estimates ranging from 200 MMbbl to 1.4 Bbbl. Meanwhile, operator Hess plans to begin drilling at its 3,000-sq-km (1,158-sq-mi) Tano/Cape Three Points block by the end of 2010.

Greenland

Despite the fact that there have been no confirmed discoveries so far, Greenland remains an attractive frontier offshore arena. It provides an enormous exploration area; has recorded natural hydrocarbon seeps that are enticing to explorers; and has generated seismic data that indicates huge potential.

Cairn Energy, the most active operator off Greenland at this time, reports that its Alpha-1S1 offshore well offshore Greenland has reached an intermediate depth of 4,358 m (14,298 ft) in volcanic sections. Following extensive logging operations, the well is being deepened, having encountered gas shows in silty and volcanic sections over several hundred meters.

Oil also has been observed intermittently over a 400-m (1,312-ft) section in the well’s volcanic and volcano-clastic intervals. According to Cairn, this warrants further evaluation.

Geochemical analysis of recovered hydrocarbon samples, conducted by independent UK laboratories, has confirmed the presence of two oil types with different origins and levels of maturity. Further analysis continues.

The T8-1 well, which encountered gas in thin sands in August, reached a TD of 3,250 m (10,663 ft), but was not commercial. The well has since been plugged and abandoned, with the majority of the well costs of $84.2 million (excluding demobilization costs) written off, in accordance with Cairn’s accounting policies.

Currently, the T4-1 exploration well is drilling ahead at a subsurface depth of 1,900 m (6,233 ft), at a location over 100 km (62 mi) north of Alpha and T8.

“The T8, Alpha and T4 wells are the first wells in Cairn’s exploration program in Greenland and are also the first wells ever drilled in the Baffin Bay basin, which is similar in size to the North Sea,” said Cairn CEO Sir Bill Gammell. “The presence of both oil and gas confirms an active, working petroleum system in the basin and is extremely encouraging at this very early stage of our exploration campaign for the Sigguk block and the entire area.”

TheStena Don, a fifth-generation semisubmersible and the Stena Forth, a sixth-generation drillship, are carrying out the drilling program targeting prospects 300 to 500 m of water. Cairn (77.5%) is the operator of the Sigguk block, with joint venture partners, Nunaoil and Petronas (10%). Nunaoil is carried through the exploration phase but has a 12.5% stake in any development. The Sigguk Block is approximately 175 km (108 mi) offshore Disko Island, west Greenland.

The government of Greenland has said that the next hydrocarbon licensing round will be carried out in Baffin Bay before the end of 2010, followed by licensing rounds in the Greenland Sea in 2012 and 2013. The Baffin Bay application closed in May, but no awards have been announced to date. The area was divided into four predefined blocks in size from about 8,000 sq km (3,089 sq mi) to 15,000 sq km (5,792 sq mi). The total licensing area in Baffin Bay covers approximately 151,000 sq km (58,301 sq mi).

Cambodia

Cambodia has officially announced that it will begin oil production for the first time beginning in December 2012 from an offshore field in the Gulf of Thailand being developed by Chevron. Cambodian Deputy Prime Minister Sok An, who is also chairman of the Cambodian National Petroleum Authority, said recently that oil production would start in two years.

Cambodia was anticipated to become the next Southeast Asia offshore province after oil was discovered there in 2005, but production stalled amid disputes between the government and Chevron over revenue sharing. Ultimately, Prime Minister Hun Sen warned the oil company earlier this year that he would terminate its contract if the offshore fields had not begun production by the end of 2012.

In January 2005, Chevron announced positive results in four out of five test wells 145 km (90 mi) off the coast of Sihanoukville. The Cambodian National Petroleum Authority (CNPA) has estimated the field at 400-500 MMbbl of oil and 3-5 Tcf of natural gas. These numbers are for Block A alone, and may indicate that much more potential exists for the Gulf of Thailand. An independent study in 2006 estimated production capacity of 200,000 b/d. If so, income to the country could reach US $6 billion in an economy of just US $9.5 billion and a national budget of only $2 billion.

Chevron is not the only operator with exploration rights off Cambodia. Block B belongs to PTT Exploration and Production (33.34%), Singapore Petroleum (33.33%), and Resourceful Petroleum (33.33%). The first exploration well drilled in this block found no recoverable oil.

Block C belongs to Polytec Petroleum, while Block D belongs to China Petrotech (Cambodia). Analysts estimate that Block D could contain either 226.9 MMbbl of recoverable oil or 496.2 billion cu ft of gas.

Block E belongs to Medco Energi (60%), Kuwait Energy (30%), and JHL Petroleum (10%), and Block F belongs to the Chinese National Offshore Oil Corp.

Exploration rights are granted for a period of four years, after which they may be extended twice for a period of two years each.

Tanzania

Ophir Energy Plc. recently encountered a thick section of gas-bearing sands with its Pweza-1 exploration well in the Mafia Basin offshore Tanzania. The Pweza-1 well was drilled by Odfjell’s semisubmersible Deepsea Stavanger.

The Pweza-1 well is located in block 4, operated by one of Ophir’s wholly owned subsidiaries on behalf of a joint venture that consists of itself (40%) and BG International (60%). The well is approximately 85 km from the coastline in a water depth of 1,400 m (4,593 ft). The Ophir/BG group joint venture has interests in blocks 1, 3, and 4 offshore Tanzania, a total of more than 27,000 sq km (10,424 sq mi) of the Mafia Offshore Basin and northern portion of the Ruvuma Basin, in water depths ranging from 100 m (328 ft) to more than 3,000 m (9,842 ft).

Pweza-1 is the first of a three-well initial work program planned for Blocks 1, 3, and 4. The program includes the acquisition of 4,000 sq km of 3D seismic data. BG Group has the option to assume operatorship of all three blocks upon completion of the initial work program.

The Ophir/BG joint venture now proposes to drill a further two wells as part of this first ever deepwater drilling campaign in Tanzania.

“The success of the Pweza-1 well is an excellent result for both the joint venture partners and for the Government of Tanzania on whose behalf we are exploring the area,” said Ophir’s Managing Director, Dr Alan Stein. “This is the first deepwater well drilled in Tanzania. It has the potential to de-risk additional prospects and leads within the basin, providing a solid platform for further investment. A further two wells will now be drilled before the end of the year and we look forward to acquiring more 3D seismic data early next year.”

The company says that evidence of an active petroleum system is provided by the presence of oil and gas discoveries in the vicinity of Mnazi Bay, immediately to the west of Block 1, and a gas discovery on Mafia Island, immediately to the northwest of Block 4. The recent discovery of gas in the Windjammer-1 well by Anadarko, in the area immediately adjacent to Block 1 across the Mozambique border, provides further support for the presence of an active petroleum system in the region.

In May, Ophir farmed out a 60% interest in the Block 1, 3, and 4 to BG Group. The blocks are in the Mafia Deep Offshore Basin/Ruvuma Basin and comprise a total area of 27,371 sq km (10,568 sq mi) in water depths of 100 to 3,000 m (328 to 9,842 ft) .

Back in 2006, Ophir completed a considerable amount of work to establish a stratigraphic framework for the whole of the southern Tanzanian offshore area. Infill 2D seismic surveys were acquired in block 1 in 2005 and blocks 3 and 4 in 2006. Further 2D and 3,500 sq km of 3D seismic data across all three blocks were acquired in 2008 to mature a number of prospects to a drillable status.

Based on these data, Ophir built a portfolio of large prospects, many of which have multiple targets. According to the Ophir, the probability for success for many of these prospects is enhanced because of the interpreted presence of seismic Direct Hydrocarbon Indicators (DHIs).

DHIs are the observed response from the hydrocarbon-water contact or the change in response between hydrocarbon saturated and water saturated reservoir rocks. Both types of DHIs are observed in Blocks 1, 3, and 4.

According to Ophir, there is a considerable body of evidence to suggest that the petroleum system in the deepwater areas can generate oil, but nearby discoveries at Mnazi Bay, Songo Songo, Mafia Island, Windjammer suggest that gas will also be present. Given the size of the prospects, it is likely that gas discoveries would be commercially attractive and able to support a significant LNG development. The Ophir/BG joint venture has entered into a series of mid-stream gas commercialization agreements with the Government of Tanzania that provide the basis under which significant gas discoveries can be developed.

Meanwhile, a total of 14 companies are now exploring in the country, with Ophir and Australia’s Beach Energy having made the most recent headlines. In March, Exxon acquired a portion of block 2 (offshore in the Indian Ocean) from Statoil.

Philippines

Philippine offshore activity centers on Nido Petroleum development in its SC 54 block. For strategic purposes, Nido has divided the block into two areas: SC 54A (less than120 m water depths), and SC 54B (deepwater). SC 54A is focused on the rapid commercialization of the recently discovered Tindalo and Yakal oil fields and the exploitation of numerous similar Nido reef plays via a broader area development strategy. SC 54B is focused on high impact exploration activity.

In block 54A, the development concept is a low capital cost solution, comprising a single well completion linked to production facilities located on theAquamarine Driller jackup. Oil production will be through a dynamically positioned floating storage and offloading vessel (FSO). The benefit that Nido sees for this solution is its mobility and re-usability, which allows the joint venture to relocate the facility over subsequent exploration discoveries following the end of the Tindalo field life. This flexibility is a key element of the company’s area development strategy.

First oil began in the first half of this year, with an initial plateau rate expected at between 7,000 and 15,000 b/d. Most likely recoverable oil volumes are estimated at 5.1 MMbbl.

The block contains in excess of 20 undrilled Nido pinnacle reef plays, which Nido says offer further, low risk exploration drilling targets in the near term. The block also contains undeveloped oil in the Nido 1X-1 well, which straddles the SC 54A and SC 14B license boundary. Nido has a participating interest in both blocks.

Nido is currently in the process of maturing its area development strategy and has begun this activity by reprocessing a swath of 3D seismic data over the greater Tindalo/Yakal/Nido 1X-1 trend.

Nido has one of the largest acreage positions in the Philippine oil and gas sector. All exploration assets are located in the offshore Northwest Palawan basin, considered the Philippines’ premier producing basin.

Much of the NW Palawan basin remains lightly explored despite the numerous oil and gas discoveries made in the shallow-water areas of the basin and the single giant Malampaya gas field in Service Contract (SC) 38, operated by Shell Philippines Exploration. The deeper areas provide Nido with superb leverage to large, high impact exploration targets with multi-hundred million barrel potential. If successful, any one of these would have a transformational impact upon the company.

Since 2007, Nido has invested heavily in the acquisition of modern 2D and 3D seismic data which has delivered an extensive prospect and lead inventory of over 90 defined opportunities. The year 2008 was a watershed for Nido, with the drilling of two successful exploration wells at Yakal-1 and Tindalo-1 (SC 54A) in the company’s first foray as an offshore operator. The final investment decision for Tindalo-1 oil field development was approved in December 2009.

Following completion of the SC 58 deepwater sea-bed coring project and interpretation of the SC 63 Kawayan 3D seismic survey during 2010, Nido says it plans to implement an initial five well exploration drilling program across its NW Palawan acreage commencing in early 2011.

The drilling program will test high potential value prospects located in SC 54B (Gindara), deepwater block SC 58 (Balyena or Butanding), SC 63 (Aboabo-2 and Kalapato) and SC 54A (Lawaan). The company began pre-planning activities for the drilling program during 2010, including the purchase of some of the long-lead items required for the multi-well program.

Nido was awarded 100% interest Service Contract (SC) 54 in 2005. The block surrounds SC 14A, which contains the Nido oil fields, and is adjacent to SC 6B. Nido holds participating interests in these blocks of 22.49% and 7.81%, respectively. The block lies immediately on trend with the giant Malampaya field with 2.7 tcf of gas.

In May 2006, Yilgarn Petroleum Philippines Pty. Ltd., a wholly owned subsidiary of Kairiki Energy Ltd., farmed into the block for a 40% participating interest.

In 2007 and 2008, the SC 54 joint venture acquired the 850 sq km (328 sq mi) Abukay 3D seismic survey located over the northern, deepwater sector of the block. Full PSDM processing of the 3D volume was completed in 2009. This data set has defined the current prospect list for the deepwater area of the block. The shallow-water area of SC 54 is covered by a multi-client 3D seismic survey, licensed by Nido in 2004. This data defined the shallow-water prospect list.

Nido is operator with 42.4% interest. Joint venture partners in SC 54A are Kairiki Energy Ltd (30.1%), Trafigura Ventures III (15%), and TG World Corp. (12.5%).

Nido also is operator of SC 54B with 60% interest while joint venture partner Kairiki Energy Ltd holds 40%.

SC 54B has been a key area of exploration focus following the acquisition of the 845 sq km (326 sq mi) Abukay 3D seismic in 2007 and 2008. Based on PSDM processing in 2009, Nido completed the interpretation of the 3D seismic data that identified the large Gindara prospect and a number of smaller satellite structures.

The company says that Gindara has mean unrisked oil in place of 1 Bbbl within three play types – the Nido limestone, Miocene clastics and deeper Mesozoic plays.

Drilling unit Aquamarine Driller with hook-up to dynamically positioned FSO offshore The Philippines.

Nido says that Gindara is drill-ready and is the highest ranked prospect in the Nido prospect and lead inventory. The first well is set to begin drilling in 2011. The block contains three existing exploration wells, all of which encountered hydrocarbon shows but were sub-optimally located due to the relatively poor quality vintage 2D seismic data on which these wells were drilled. Nido says that based on modern PSDM 3D seismic, significant upside potential exists within the northern sector of the block.

Service Contract 58 is a large deepwater block of 13,440 sq km (5,189 sq mi) that lies immediately outboard of the Malampaya gas field. No wells have been drilled in the block to date. Water depths are in excess of 1,000 m (3,280 ft) over most of the block.

In July 2006, Nido farmed into SC 58 for a 50% participating interest. As part of the agreement, the company assumed operatorship of the block and is responsible for all exploration activities and costs up to and including the drilling of the first exploration well to earn a 50% participating interest.

In 2006 and 2007 Nido implemented an aggressive seismic acquisition campaign, acquiring 3,184 km (1,229 sq mi) 2D seismic in 2007, followed by 661 sq km (255 sq mi) of focused 3D seismic over four large high-graded deepwater leads. Nido says that interpretation of the seismic data has confirmed the presence of an extensive deepwater play fairway comprising Oligocene-Miocene Nido limestone platform and reefal plays and Miocene turbidities. Nido has an extensive hit list for the block, dominated by five large prospects: Balyena, Balyena East, Butanding, Butanding West and Dorado.

The main activity during 2010 was the acquisition of a multi-beam and deepwater seabed coring program, which was completed in April. The survey will be used to help decide the final drilling sequence in the block. Currently, the Balyena prospect is the expected first well to be drilled and forms part of the five well drilling program planned to begin in 2011.

More Offshore Issue Articles
Offshore Articles Archives
View Oil and Gas Articles on PennEnergy.com