Manifa to Yield 500,000 b/d by 2013 and 900,000 b/d by 2014 -- Aramco

by David Rachovich

                                Source: Saudi Aramco via OffshoreEnergyToday.com Feb 23, 2011

                                                       Source: Saudi Aramco website 

                [Click on map to enlarge]

                                                                             Source: Saudi Aramco via EIA, here.

"Significant progress was achieved in 2010 on Manifa, the giant Arabian Gulf offshore field under development [emphasis mine and please see map and images above -- D.R.]," Saudi Aramco said in its 2010 annual review, published on Monday (June 6).

"Project elements completed during the year included all drilling islands, as well as the main and lateral causeways. Construction of the Manifa Central Processing complex has begun, with the main spine and process area pipe rack completed. The Manifa development will accommodate a Central Processing Facility with gas-oil separation, wet crude handling, crude stabilization, gas gathering and compression, produced water disposal, water injection and other related facilities. Field development includes 41 km [25 mi] of causeways and 3 km [1.9 mi] of bridges to support 27 [man-made] drilling islands for the shallow water wells, and 13 offshore platforms for deeper water producing and water injection wells. Onshore facilities include 15 drill sites, a Central Oil and Gas Processing Facility, water supply wells and injection facilities, and multiple gathering, water injection, and product transportation pipelines," it added.

"Manifa is designed to produce in staged increments --- 500,000 [barrels per day] bpd of Arabian Heavy crude oil by 2013 and 900,000 bpd by 2014," the report said. And output "will be used as feedstock for planned refineries in the Kingdom [i.e., for two new deep-conversion refineries at Jubail and Yanbu -- D.R.]."

The Manifa Drilling Team set a new record in December 2010 when it finished drilling the longest well in Saudi Arabia to a total depth of 32,136 ft (± 9.8 km) and completed a horizontal power water injector across the Lower Ratawi reservoir. Calgary Precision Drilling rig did the work on the Manifa well. The same drilling team set an earlier record while working on the 30,850 ft (+9.4 km) Manifa well.

Discovered in 1957, Manifa field is in shallow waters southeast of Tanajib, about 200 km (124 mi) northwest of Dhahran. The oil production started when the C reservoir came on stream in 1964, and the B reservoir was brought on production in 1974. Manifa produced heavy crude oil with about 27° API gravity. The field was shut in during January 1984, due to low demand with less than 1% of the reserves produced (Saudi Aramco Journal of Technology, Summer 2009).

Development strategy of Manifa, the world's fifth-largest oil field, is based on optimum use of onshore drilling. Instead of developing Manifa completely from offshore platforms, it is developed from 27 offshore man-made drilling islands connected by a causeway, in addition to onshore drill sites and offshore platforms. Extended-reach wells such as the two mentioned above are required for optimum field coverage. "Manifa field is located in shallow and environmentally sensitive waters, necessitating maximizing drilling from onshore sites while minimizing offshore platforms," the report argued. Actually, the state-of-the art extended reach drilling (ERD) technology reduces the high capital and operating costs of large offshore structures (jackup rigs or shallow water rigs, with legs that reach the bottom of the sea floor) and at the same time minimizes the environmental impact in this sensitive near-shore area.

"The Kingdom's longer-term concern is over whether it needs to increase oil production capacity to meet likely future demand. The Saudi view on oil markets has altered sharply from where it was a year ago, when a battered global economy was still limping out of recession. Riyadh thinks medium- to long-term oil demand growth may be higher than it had previously anticipated, driven by China, India and also Middle East itself, and discussions are now taking place on whether the Kingdom should raise oil output capacity beyond its current 12.5 million b/d," Petroleum Intelligence Weekly (PIW) said in its article "Saudis Consider Need to Raise Output Capacity." "Now, while no decisions have yet been made and while work is unlikely to start this year, expansions at Shaybah, Manifa and Khurais are back on the table," it maintained. "Aramco has already decided to bring forward the 10 billion- 14 billion bbl Manifa project, and could now expand its capacity from 900,000 b/d to 1.2 million b/d," the article said.

During the May 2010 Offshore Technology Conference, Zuhair Al-Hussain, Aramco vice-president, drilling and workovers, said production from Manifa will start in mid-2013 but will not ramp up quickly to the original target of 900,000 b/d of Arab heavy crude (Oil & Gas Journal via my post).

Saudi Aramco Annual Review 2010 is available for download on the Saudi Aramco website at: http://www.saudiaramco.com/content/www/en/home.html#news%257C%252Fen%252Fhome%252Fnews%252Fpublications-and-reports%252Fcorporate-reports0%252FAnnualreview.baseajax.html

(Update 1: Saudi Oil Minister Ali al-Naimi, chairman of the board of directors at Saudi Aramco toured oil and natural gas installations in the country on October 16, 2012, as part of a review of the country's long-term energy prospects. During the tour with the Board members, HE Naimi launched the Manifa Field’s reservoir water injection operations in preparation for first phase production of Arabian Heavy crude oil at an initial capacity of 500,000 barrels per day (bpd) in the first half of 2013, and which will gradually increase to 900,000 bpd by 2014. The crude oil from Manifa will feed local refineries that are currently under construction, namely the 400,000 b/d SATORP refinery in the easterm Saudi Arabian city of Jubail with France’s Total, and the 400,000 b/d YASREF in Yanbu' on the Red Sea, the joint venture with Sinopec of China (Aramco has said the new Yanbu refinery, which joins two existing refineries at Yanbu, will produce 90,000 b/d of gasoline, 263,000 b/d of ultralow sulfur diesel, and 6,300 tonnes/day (tpd) of petcoke as well as 1,200 tpd of sulfur--see OGJ Online, Dec 3, 2012), and the upcoming Jazan refinery, which has received Board approval for financing, and the project’s contracts are expected to be awarded in the coming weeks---please see Saudi Aramco website/Latest news, Dhahran, Oct 16, 2012 Update 2: Saudi Aramco has let a contract to Houston-based KBR for front-end engineering and design of an integrated gasification combined-cycle power plant in conjunction with a 400,000 bpd refinery under development at Jazan Economic City, Saudi Arabia, according to OGJ Online, Oct. 22, 2012. The IGCC plant, which KBR says will be the world’s largest such facility, will gasify vacuum residue to supply electricity to the refinery and make 2.4 Gw available to Jazan and the surrounding region---please OGJ Online, Nov 13, 2012. Update 3: Production has begun from the first phase of development of Manifa oil field offshore Saudi Arabia and is expected to reach 500,000 bpd by July [2013]. The start-up was 3 months ahead of schedule, according to Saudi Aramco---please see "Manifa oil flow starts offshore Saudi Arabia," OGJ Online, April 15, 2013 -- D.R.)

German Government Plans Total Nuclear Shutdown by 2022

Deutsche Welle, May 30, 2011
As public opposition to nuclear power remains high, the German government has announced new plans to phase it out completely in the next 11 years. And the proposal may have a chance at support from the center-left.

The German government on Monday announced plans to completely phase out nuclear energy by 2022, a 14-year acceleration of its previous plans.

Environment Minister Norbert Röttgen announced the proposal in the early hours of Monday, after a 12-hour marathon meeting between Chancellor Angela Merkel's Christian Democrats (CDU) and the junior coalition partners, the Free Democrats (FDP).

"It's definite: the latest end of the last three nuclear power plants is 2022," Röttgen told reporters. "There will be no clause for revision."

Last October, the German parliament voted in favor of a much slower nuclear shutdown, lasting until 2036. The government said that it was necessary to ensure the supply of Germany's energy needs.

After the nuclear disaster at the Fukushima nuclear power plant in Japan [please see my March blog posts under the category/label "Japan." -- D.R.], public opposition to nuclear energy sharply increased. In March, Merkel announced a temporary shutdown of seven older nuclear plants [Chancellor Angela Merkel decreed that the country's nuclear power reactors which began operation in 1980 or earlier, i.e., Biblis-A, Neckarwestheim 1, Brunsbüttel, Biblis-B, Isar 1, Unterweser, Phillipsburg 1, should be immediately shut down---please see my post/remarks, here. Those units then closed and were joined by another unit/Krümmel already in long-term shutdown, despite having started up in 1984, making a total of 8336 MWe offline under her direction, about 6.4% of the country's generating capacity. -- D.R.]

The new timeline would keep those [...] [eight] plants offline permanently. Six more would be shut down in 2021, and three would stay on until 2022 to ensure no disruption to power supply [Thus, all 17 of the country's nuclear plants will be shut by 2022 -- D.R.]. [Read more]

(Before March's moratorium on the older power plants, nuclear power supplied 23% of Germany's electricity. The United States is the world's biggest nuclear-electricity producer, followed by France, Japan, Russia, South Korea and Germany, according to the 2009 data---please see here. -- D.R.)

Study: North America Dominates Global Shale Gas Market

by Jonathan Katz, IndustryWeek, May 26, 2011
North America will hold a 78% share of the global shale gas production in 10 years because of the region's technical expertise and availability of resources, according to a report released May 25 by Markets and Markets [please see remarks below -- D.R.].

In 2010 North America was the only region active with commercial shale gas production. But current exploration and production activities by major oil and gas companies in Europe and Asia Pacific are expected to lead to shale gas commercialization in these regions by 2016, the report says.

The markets representing high growth rate in shale gas production from 2016 to 2021 are China (6.2%), Poland (6%), France (5.4%) [regarding shale exploration in France, please see my post "Shale Gas Development in Europe" below -- D.R.], South Africa (5.1%) and the United States (5%).

Global shale gas production is expected to grow to 6,991 billion cubic feet in 2021 at a compound annual growth rate of 5.4% [sic; from 2011] through 2021. [Please see remarks below -- D.R.]

Rising shale gas production will likely boost ethylene production by 6.6% by 2021. Ethylene is a feedstock [that can also be] derived from natural gas that is used in petrochemicals. [Also, please see my post, including remarks, here -- D.R.]

Challenges that could hinder shale gas development include the capital-intensive nature of shale gas projects and environmental issues associated with hydraulic fracturing. [Full story]

(Please see a press release from Markets and Markets "MarketsandMarkets: Global Shale Gas Market to reach 6.9 tcf by 2021 and With 78% Market Share North America Continues to dominate the Shale Gas Market." According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010. In 2010, U.S. shale gas production constituted 23 percent of total U.S. natural gas production---please see here. For exploration of shale gas in Poland, please see my post "Marathon, Nexen to Jointly Explore Shale in Poland," here. For shale gas in Europe, please see my post "World Watch [Shale Gas Development in Europe]," here. For China's quest for unconventional gas, please see my post "China Plans to Exploit its Shale Gas Resources," here. For Mexico's first shale gas production, please see, inter alia, here. Also, please see Table: Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries, Compared to Existing Reported Reserves, Production and Consumption during 2009 --- EIA, here. -- D.R.)

World Watch [Shale Gas Development in Europe]

by Jim Washer, London, EI, May 16, 2011
Shale gas is beginning to take off in Europe, as a subject of debate and as a plausible new energy supply option. France’s National Assembly last week voted to ban the controversial technique of hydraulic fracturing in shale oil and gas exploration, a move which threatens to strangle the country's shale gas sector at birth. But elsewhere in the region, interest in shale exploration is growing, with Total farming into two concessions in Poland operated by Exxon Mobil, which is also assessing unconventional gas prospects in neighboring Ukraine. Europe can’t match North America’s shale gas resource potential, nor its attractive framework for onshore gas development. But one factor which typically complicates energy development elsewhere -- politics -- may encourage shale development in Europe. Countries like Poland and Ukraine both depend heavily – and not always happily -- on Russia for gas. Developing more indigenous gas resources would improve these countries’ security of supply, as well as strengthening their hand in gas supply and transit negotiations with Moscow.

(Poland's technically recoverable resources of shale gas are estimated to be 187 trillion cubic feet/tcf or c. 5.3 trillion cubic meters/tcm, the highest in Europe, followed by France with 180 tcf or c. 5.1 tcm---please see my post/table "Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries -- EIA," here. Also, please see my post "World Shale Gas Resources Outside US Assessed," here. For exploration of shale gas in Poland, please also see my post "Marathon, Nexen to Jointly Explore Shale in Poland," here. In theory, unconventional gas resources "might be able to cover European gas demand for another 60 years," said a recent study on unconventional gas – EUCERS Strategy Paper No 1, p. 30. -- D.R.)   

US Horizontal Rigs Drift past 1,000 Mark on "Shale Sail"

By Starr Spencer, Platts oil blog - The Barrel, May 13, 2011
Apologies to Bob Seger, but it seems just about everyone in the oil and gas industry these days is following the sentiment in this song, or at least doing a reasonable facimile.

There are all sorts of statistical goodies buried in the Baker Hughes weekly rig count. Here is one of them:

Apart from the fact that the US oil rig count is soaring and has now surpassed the number of rigs drilling for natural gas, which happened last month , US rigs drilling horizontal wells also passed the 1,000 mark in April [data showed on April 1st -- D.R.] for the first time.

And it continues its upward march. This past week ended May 13, 1,041 rigs were drilling horizontal wells, out of a total 1,830 total rigs. [Horizontal rigs now make up about 57 percent of the total rig count, up from a low of less than 4 percent in Sept 1998. Also, for the total drilling rigs in historical perspective, please see remarks below -- D.R.] That is the highest number since Baker Hughes began keeping track of such data in 1991, and probably [sic] is an all-time record.

The surge in horizontal drilling can only be traced to the shale explosion, which is truly one of the energy industry's Biggest Things. Everyone seems to be exploring for or at least reading about shale oil and gas these days, and in the process the purses of oil operators and also national economies are reaping the benefit.

Once companies hit on the idea, sometime in the early 2000s, that they could get a lot more natural gas by not only drilling down vertically, but then taking the well sideways or horizontally once they reached total depth, it was one of those "Eureka!" moments.

They then coupled that with fracture-stimulating or forcing fluid into rock at high pressure, and drilling increasingly longer laterals to access more of a reservoir from a single wellbore. The greater cost of a horizontal well was offset by more output. Once oil prices began to climb, they applied these notions to oil wells, with similar results.

Rig numbers tell the story. Horizontal drilling before the early 2000s wasn't unknown, but at that point it was more in the experimental stage. When Baker Hughes began keeping track of horizontal versus vertical wells starting the first week of January 1991, 100 rigs were drilling horizontally out of a total 1,108 rigs that week. Another 81 rigs were drilling directionally while the vast majority--927 rigs--worked on vertical wells.

In the succeeding years, horizontal drilling largely stayed below--sometimes well below--100 rigs. That is, until 2004, when the Barnett Shale [in Texas] began to glitter things up and everyone wanted to ride the shale trail. Then kicked off an upward trend of horizontal drilling that, except for the economic pullback of late 2008 to late 2009, continues to this day. [Also, horizontal rigs comprised less than one-third of oil-directed rigs in September 2008, and with a tripling of horizontal oil rigs since then, that share has increased to about 46 percent---please see my post "Domestic Oil Production Reversed Decades-Long Decline in 2009 and 2010," here. -- D.R.] 

Now the excitement of shale drilling is becoming an international phenomenon. Canada is several years into several shale gas and oil plays there; places such as Poland [please see my post "Marathon, Nexen to Jointly Explore Shale in Poland," here -- D.R.] and Germany are exploring their potential, and even Mexico has begun drilling its northern regions for shale gas which it regards as an extension of the US' frenzied Eagle Ford Shale in South Texas, a bonanza which contains both oil and gas [please see remarks below -- D.R.].

Still, not all shales require horizontal drilling. Small oil-focused Venoco, which held a nearly two-hour conference call this week and spoke at length about its pioneering Monterey Shale operation onshore southern California, said it expects vertical wells are the most likely way to develop that oil pool. However, with only one rig drilling Venoco's slice of the Monterey for the rest of the year, it appears to be the exception that proves the rule. [Full story]

(Since 1944 the highest weekly U.S. rig count was 4,530 recorded on December 28, 1981, the height of the oil boom. The lowest rig count of 488 was recorded on April 23, 1999. In Canada the highest weekly rig count of 718 was recorded on February 17, 2006. The lowest weekly rotary rig count of 29 was recorded on April 24, 1992---please see my post > remarks, here. Separately, please see my post/table "Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries -- EIA," including China, Argentina, Mexico, Australia, Canada, Poland, France, etc., here. Also, please see my post "China Plans to Exploit its Shale Gas Resources," here.  Mexico's state-owned oil company Petróleos Mexicanos/Pemex, said in March it had produced its first shale gas from an exploratory well at the Eagle Ford Shale formation in the northeastern state of Coahuila in February. -- D.R.)

Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries -- EIA

Extracted from the EIA's overview, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, April 5, 2011

Table 1. Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries, Compared to Existing Reported Reserves, Production and Consumption during 2009 -- EIA 

	2009 Natural Gas Market1                             (trillion cubic feet, dry basis)			Proved Natural Gas Reserves2 (trillion cubic feet)	Technically Recoverable Shale Gas Resources (trillion cubic feet)
	Production	Consumption	Imports (Exports)
Europe
France	0.03	1.73	98%	0.2	180
Germany	0.51	3.27	84%	6.2	8
Netherlands	2.79	1.72	(62%)	49.0	17
Norway	3.65	0.16	(2,156%)	72.0	83
U.K.	2.09	3.11	33%	9.0	20
Denmark	0.30	0.16	(91%)	2.1	23
Sweden	-	0.04	100%		41
Poland	0.21	0.58	64%	5.8	187
Turkey	0.03	1.24	98%	0.2	15
Ukraine	0.72	1.56	54%	39.0	42
Lithuania	-	0.10	100%		4
Others(3)	0.48	0.95	50%	2.71	19
North America
United States(4)	20.6	22.8	10%	272.5	862
Canada	5.63	3.01	(87%)	62.0	388
Mexico	1.77	2.15	18%	12.0	681
Asia[-Pacific]
China	2.93	3.08	5%	107.0	1,275
India	1.43	1.87	24%	37.9	63
Pakistan	1.36	1.36	-	29.7	51
Australia	1.67	1.09	(52%)	110.0	396
Africa
South Africa	0.07	0.19	63%	-	485
Libya	0.56	0.21	(165%)	54.7	290
Tunisia	0.13	0.17	26%	2.3	18
Algeria	2.88	1.02	(183%)	159.0	231
Morocco	0.00	0.02	90%	0.1	11
Western Sahara	-	-		-	7
Mauritania	-	-		1.0	0
South America
Venezuela	0.65	0.71	9%	178.9	11
Colombia	0.37	0.31	(21%)	4.0	19
Argentina	1.46	1.52	4%	13.4	774
Brazil	0.36	0.66	45%	12.9	226
Chile	0.05	0.10	52%	3.5	64
Uruguay	-	0.00	100%		21
Paraguay	-	-			62
Bolivia	0.45	0.10	(346%)	26.5	48
Total of above areas	53.1	55.0	3%	1,001[*]	6,622
Total world	106.5	106.7	0%	6,609

 Sources [and Notes]:
¹Dry production and consumption: EIA, International Energy Statistics, as of March 8, 2011.
² Proved gas reserves: Oil and Gas Journal, Dec., 6, 2010, P. 46-49.
³Romania, Hungary, Bulgaria.
⁴U.S. data are from various EIA sources.

[*Excluding the United States – D.R.]

(Please see my post "World Shale Gas Resources Outside US Assessed," here. -- D.R.)