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April 2011

Enhancing Exploration Success Through New Collaborative Technologies 

(White Paper - April, 2011

  

 

SUMMARY

     For over 50 years, explorationists have evaluated prospect areas using various near surface measurement techniques to assess the vertical migration of volatile compounds from subsurface reservoirs and thereby identify subsurface reservoirs.  Why the interest in this technology?  Near surface measurement technologies not old identify charged subsurface areas, but cost approximately 90% less than seismic studies.

 

     While many advances in this technology have occurred over the years, one method, Gore's Amplified Geochemical Imaging™, has moved to the forefront. The Amplified Geochemical Imaging™ is the only near surface technique that allows the identification and quantitation of C2-C20 hydrocarbons that move to the surface through vertical microseepage. 

 

Vertical Migration of Hydrocarbons 

Figure 1. Microseepage Diagram

 

     However, Amplified Geochemical Imaging™ results can be enhanced when combined with other complimentary technologies such as near surface extractions. While Amplified Geochemical Imaging™ can indicate charged or uncharged subsurface areas, near surface soil extractions can indicate the depositional environment, organofacies, age, as well as the maturity of detected hydrocarbons.   

 

     Amplified Geochemical Imaging™ is also now being used in  conjunction with basin modeling to define reservoir structures, their potential charge, timing of charge with relation to structure formation, migration pathways, hydrocarbon types (e.g. gas, condensate, or oil), and burial history. Consequently, when explorationists combine Amplified Geochemical Imaging™ with near-surface extractions, and/or basin modeling, they experience extremely high rates of success for accurately identifying hydrocarbon charged reservoirs and obtain a wealth of valuable information that aids them in characterizing the associated petroleum system.

 

 

 

INTRODUCTION

 

     The Amplified Geochemical Imaging™ technique uses a passive hydrophobic adsorbent material to collect C2-C20 hydrocarbons that move to the surface through vertical microseepage. Sampling modules are deployed at a depth of approximately 0.5 meters at predetermined locations in a grid pattern across an area of interest. The modules are kept in-place for 17 days. During this time volatile compounds that rise to the surface through microseepage, are passively adsorbed from the soil (Figure 1). In Figure 1 blue arrows indicate vertical migration of background hydrocarbon seepage, while red arrows indicate the microseepage of hydrocarbon gases arising from a charged reservoir (indicated by the green area).

 

     After the 17 day collection period, each module is retrieved and shipped to the laboratory for analysis. Each sorbent tube is thermally desorbed to release the captured volatile compounds. The 85 organic compounds are then separated and quantified by gas chromatography/mass spectrometry (GC/MS) down to a level of approximately 1 part per billion (1 ppb). This low level of sensitivity is unmatched in the industry and is one of the key components that allow Amplified Geochemical Imaging™ to be successful when other techniques are not.

 

     Traditional near-surface methods typically use GC analysis to identify and measure light-end components up to C5, thus limiting their ability to identify hydrocarbons restricted to the gas range. Amplified Geochemical Imaging™ can detect 85 organic compounds thus identifying not only dry gas and wet gas charges, but also condensates, oils, normal paraffins, iso-paraffins, cyclo-paraffins, aromatics, and naphtheno-aromatics. This extensive target compound list not only enables the user to identify hydrocarbon types with precision, but it also allows differentiation between naturally occurring background hydrocarbons and hydrocarbons found over charged reservoirs. This unique ability is one of the important technical aspects that distinguishes Amplified Geochemical Imaging™ from other techniques and identifies charged areas and predicts dry holes with extreme accuracy.

 

 

MULTIVARIATE STATISTICAL ANALYSIS

 

     The extended compound list and the large grid pattern enables the user to perform sophisticated statistical processing and modeling of complex geochemical signatures (up through phytane).  Some of the processes used include hierarchical cluster analysis, canonical variates analysis and discriminate analysis.

 

     One of the statistical techniques used to interrogate the data is hierarchical cluster analysis (HCA).  HCA groups samples of like composition according to the values of all input variables.  The result is that samples are separated into subsets or "clusters" according to their similarities.  In other words, the HCA evaluation clusters the data into hydrocarbon types such as background, gas, condensate, or oil. This classification is made possible by an extended compound list.

 

     Canonical variates analysis (CVA) is an important part of the quality control process within Amplified Geochemical Imaging's™. CVA provides the ability to distinguish between field samples and control blank samples. As seen in Figure 2, CVA clearly separates field samples, indicated in yellow, from the various quality control samples.

 

 

Canonical-Variates Scores 

Figure 2. Canonical-Variates Scores for QC 

 

CONTOUR MAPS OF GEOCHEMICAL PROBABILITIES

 

     The results of the Amplified Geochemical Imaging™ are expressed in terms of maps that are plotted at a scale appropriate to the size of the survey and spatial distribution of the samples.  When possible, geographical information system (GIS) layer files containing relevant geological and geophysical (G&G) information (seismic line locations, structural interpretation contours, mapped fault polygons, etc) should be provided by the client for appropriate integration into the geochemical result. An example of a finished survey map is seen in Figure 3. As seen on the map legend, the shading transitions from gray to dark blue indicating the presence of background hydrocarbons or a dry hole area. The purple and deep red areas indicate a strong probability of hydrocarbons resulting from a reservoir charge.

 

Map Contouring of Reservoir Hydrocarbon Probabilities 

 Figure 3.  Map contouring of reservoir hydrocarbon probabilities.

 

CASE STUDY - RUSSIA

 

     NOVATEK OJSC drilled in the Western Siberian Basin for many years and had determined that this was an active gas and/or gas condensate field. To date, no oil had been discovered in this field despite fairly extensive drilling. The area of interest for the client was the middle and lower Jurassic formations at 2,500 - 3,000 meters. Sampling took place in frigid Western Siberian winter conditions of frozen ground and temperatures at -40OC (see Figure 4).

 

Wester Siberian Site 

Figure 4.  Western Siberian field

 

     Data supplied by the client showed a gas condensate well 30 km south of the survey site. Upon completion of the project, the survey data indicated not only a gas condensate signature on the site, but also an oil accumulation. As seen in Figure 5, hierarchical cluster analysis (HCA) indicated three distinct groups of samples, gas condensate, background, and oil. Each horizontal line is a single sample from the site. Each red mark indicates a carbon compound at that carbon number.

 

W Siberian HCA 1 

Figure 5.  HCA Results for W. Siberian Basin

 

     The lower group shows hydrocarbons detected in the C4 to approximately C12 carbon range. The middle group of samples depicted little or no hydrocarbons present while the uppermost cluster indicated hydrocarbons in the C10 to C20 range (i.e. oil range). Figure 6 provides an alternate representation of the data for clarification.

 

HCA 2 

Figure 6.  Alternate HCA data view for W. Siberian Basin

 

     The colored lines to the right of each cluster represent the samples associated with each cluster type (i.e. gas condensate, background or oil). As oil had never been found in this field previously, the client was skeptical of the survey results. Drawing on these survey results the client was able to pinpoint the location of optimal well placement, resulting in a major oil discovery. Based on this success, the client decided to use Amplified Geochemical Imaging™ for all future projects and wrote the following letter of recommendation, 

 

"Performing the geochemical survey on the area allows us to rank those local uplifts 

which were earlier identified by the seismic work 

depending upon the degree of their prospectivity.

The geochemical anomalies identified at the Yarudey and Shuginskaya areas 

were 100% proven by drilling and the discoveries of oil and gas condensate deposits."

Victor E. Ponomarev

Head of Resources Base Development and Reserves Balance".

 

COLLABORATIVE CASE STUDY - OFFSHORE

 

     GORE and StratoChem Services conducted an offshore survey collecting piston core samples. Part of each piston core sample was sent to GORE for Amplified Geochemical Imaging™ analysis. The data confirmed what the client suspected in that they had an offshore petroleum system. The GORE survey clearly delineated the extent or the petroleum system. 

 

     Additionally, part of each piston core was also sent to StratoChem Services for extraction and analysis. Each extract was analyzed for oil fingerprint analysis by GC and then later analyzed for biomarkers by GC/MS. The resulting biomarker data indicated that the offshore oil system was similar in make-up to an onshore petroleum system. Thus, the StratoChem Services analyses not only confirmed the presence of an offshore system, as detected by the Amplified Geochemical Imaging™ survey, but indicated that instead of having two separate petroleum systems the client had one large system that started onshore and extended offshore.

 

 

CASE STUDY - EGYPT

 

     GORE Amplified Geochemical Imaging™ can also be used in conjunction with basin modeling. One client in Egypt wanted to release potential property within a lease and performed an Amplified Geochemical Imaging™ survey to validate that the section did not contain significant hydrocarbon quantities.

 

     The client subsequently commissioned StratoChem Services to perform a basin model of the area to confirm the GORE survey and to direct future drilling efforts for the retained property. Figure 7 shows an overlay of the GORE survey and the basin modeling results. The blue shaded areas indicate potential positive anomalies for hydrocarbon reservoirs based on the StratoChem Services basin modeling while the red shaded areas indicate potential positive anomalies for hydrocarbon reservoirs based on the StratoChem Services basin modeling. The heavy black line indicates the area being evaluated for relinquishment by the client.

 

An overlay of survey map basin 

Figure 7.  An overlay of a GORE survey map and a basin modeling map.

 

     Both the Amplified Geochemical Imaging™ survey and the basin modeling results indicated little presence of hydrocarbons within the area of interest. This confirmatory information provided the client with a great comfort level when deciding to relinquish the area. Additionally, the basin survey identified large high prospect areas to the northwest of the survey area. Thus, the use of both Amplified Geochemical Imaging™ and StratoChem Services basin modeling allowed the client to rank their prospects and identify hot prospect areas for future drilling. The client later drilled to the area in the northwest resulting in an oil discovery.

 

 

CONCLUSION

 

     Amplified Geochemical Imaging™ is an innovative technology, which provides for the direct detection of surface geochemical microseeps caused by subsurface oil & gas accumulations. While the Amplified Geochemical Imaging™ surveys have demonstrated a 93% accuracy rate of predicting hydrocarbon accumulations, this accuracy and information can be enhanced when combined with near surface soil extraction technologies and basin modeling.

 

Near surface extraction can not only confirm the presence of subsurface accumulations, but can also indicate:

  depositional environment,

  organofacies,

  age, as well as

  maturity of detected hydrocarbons. 

 

 

Basin modeling can be used to define:

 

  reservoir structures,

  their potential charge,

  timing of charge with relation to structure formation,

  migration pathways, and

  hydrocarbon types (e.g. gas, condensate, or oil), and burial history.

 

Resultantly, these collaborative technologies can now be used together to enhance exploration success and help clients rank prospects with greater certainty.

 

 

 

 

For additional information contact Rick Schrynemeeckers with StratoChem Services at:

Rick.S@StratoChemLabs.com

 

 

 

 


Egypt to Revise All Foreign Gas Deals 

(www.egyptoil-gas.com - April 14, 2011) 

 

   Egyptian flag small     

 

     Egypt's prime minister has asked for the revision off all contracts to supply gas abroad, including to Israel, the official news agency MENA reported. Egypt supplies an estimated 40 percent of Israel's gas in what, under ousted Egyptian president, was a highly controversial deal. Prime Minister Essam Sharraf "has directed the revision and review of all gas contracts Egypt agreed to with all countries, including Jordan and Israel," MENA said.

 

     The contracts are to be revisited so the gas "would be sold with deserved prices that achieve the highest returns for Egypt," it added. Sharraf is to meet Jordanian Energy Minister Khaled Tuqan on April 14 to discuss the deal with his country, MENA said, adding the revisions could bring Egypt an extra $3 billion-$4 billion in revenue.  Shipments of gas resumed to Israel in March, after they were interrupted in a February 5 attack on a Sinai pipeline as Egypt was rocked by protests that brought down Mubarak.

 

     In December, four Israeli firms signed agreements to import gas under a 20-year contract valued at $5 billion-$10 billion (3.7-7.4 billion euros). The contract was signed with the Israeli-Egyptian East Mediterranean Gas (EMG), in which Ampal-American Israel Corp has a 12.5 percent stake. 

 

     EMG has signed a number of agreements with Israeli firms since 2005, and the new contracts will boost the volume of Egyptian gas imports to six billion cubic metres, worth $19 billion (14 billion euros). The agreement has been repeatedly challenged in Egyptian courts on the grounds of its secretive clauses and because it was done without parliamentary consultation.

 

     A court imposed an injunction on the deal, in a move ignored by the government. A higher court overturned the freeze in 2010, on condition the government regulate the quantity and price of gas exported. Both the Israeli foreign ministry and the national infrastructure ministry, which is responsible for energy, declined to comment on the report.

 

 

Algeria: Sonatrach Seeking Partners for Shale Gas Pilot Project in 2012
 
(www.energy-pedia.com - March 24, 2011) 

 Algerian Flag                                                                      

        

   State-owned energy giant Sonatrach will launch a pilot project for developing unconventional gas resources in 2012 in Algeria and has spoken to international oil companies, an executive said on Wednesday. 'We are ready to go it alone if we cannot find a partner,' the head of Sonatrach E&P Exploration Djamel Bekkouche told Reuters on the sidelines of an energy conference.

 

     The North African OPEC member supplies about 20 percent of Europe's natural gas but some analysts say it has under-invested in new oil and gas projects.  Bekkouche, who described the shale gas prospects as very interesting, said there had been an exchange of views with international oil companies about shale gas development. 'Italian oil and gas group Eni is looking,' he said.  

 

     Eni has entered shale gas development projects in Poland and the United States. It has agreed to develop shale gas opportunities with China's PetroChina. It has said it is looking into non-conventional resource development in North Africa.

 

     Bekkouche said it normally took between five and eight years for shale gas projects to come on line. come on tap, said Sonatrach is planning to invest $46 billion in upstream activity in the medium term.

 

Tunisia: BG Plans $300 Million Investments in Tunisia in 2011

(www.energy-pedia.com - March 23, 2011) 

 

Tunisian Flag     

 

     British oil and gas firm BG Group plans some $300 million of investments in Tunisia in 2011 to develop its production sites in the North African country, the state TAP news agency said on Thursday. BG Tunisia is the operator of an exploration permit offshore Sfax, in the south, and pipes oil and gas throughout Tunisia, supplying more than 50 percent of the country's domestic gas.

 

     TAP said Sami Iskander, executive vice-president and managing director of BG, Africa, Middle East and Asia had met Prime Minister Beji Caid Sebsi on Thursday. It quoted him as saying the investments aimed to keep production in the fields of Miskar and Hasdrubal - drilling of new wells, maintenance of platforms - in the region of Sfax.

 

    Iskander and Sebsi also discussed ways to attract more investment in Tunisia and improve the group's relations with communities living near production sites, TAP said. It quoted Iskander as saying the situation in some Tunisian production sites had improved after strikes hit operations. BG Tunisia recently signed an agreement with representatives of communities living near its sites under which it pledged to create 120 jobs as well as establish a fund of $2 million in 2011 to finance social investment and micro-credit projects.

 

     Investments of BG Tunisia, a subsidiary of BG Group, have reached 3.5 billion Tunisian dinars ($2.5 billion) so far.

 

East Africa - Continent's New Hotbed for Oil & Gas Exploration!


(http://mergersandacquisitionreviewcom.blogspot.com- March 29, 2011)



 

     Traditionally, west and north Africa have been the continent's hotspots of oil & gas E & P, but recent success in east Africa may change that.  North Africa has seen 20,000 wells sunk over the past few decades, while drillers have sunk 14,000 wells in and off West Africa.  In East Africa, the total is about 500 wells.

 

     Significant discoveries in the region, combined with a range of new opportunities through licensing rounds, are attracting new plays to relatively under-explored countries on the eastern part of the African continent. 

 

     The East African Region has a total of 28 prospective sedimentary basins with resource potential of about 2 billion barrels of oil in place and 3 tcf of natural gas.  Data monitor forecasts total oil production in the region (excluding Sudan and South Africa) to reach approximately 210,000 barrels per day (bpd) in 2015, and nearly 389,000 bpd by 2020.

 

... oil & gas hunters!

 

  • Tullow Oil has already made significant discoveries in Uganda, and is targeting other exploration fields in the East African rift basins, mainly in Kenya and Ethiopia.
  • Wildcatters and majors such as Italy's Eni, Petronas of Malaysia and China National Offshore Oil Corporation (CNOOC) have all moved on East Africa in the past few years,  hoping to mimic Tullow Oil's Success in the region.
  • Africa Oil Corp with its assets in Ethiopia and Somalia is yet to explore the region.
  • In addition, Dominion Petroleum has invested nearly $40m in drilling activities in Tanzania and Uganda in recent years and will continue its efforts in the region,  including some farm-out initiatives.
  • Anadarko and Cove Energy also have plans to move into south-east Africa, and together intend to invest around $150m in drilling activities over the next two years.

 

 

ExplAct Name

Operator

Country                         

Block 1

Tullow Oil

Uganda

Block 10A

Tullow Oil

Kenya

Blocks 2/6 & 7/8

Africa Oil Corp

Ethiopia

Range Resources Ltd - Somalia Exploration

Africa Oil Corp

Somalia

Adigala

Africa Oil Corp

Ethiopia

Block 12A & Block 13T

Tullow Oil

Kenya

Block 3A

Vanoil Energy Ltd.

Kenya



     Datamonitor forecasts a total offshore capital expenditure (CAPEX) in the region (excluding Sudan and South Africa) of nearly $400m in 2010 ($312m on drilling and $77m on seismic activities). The total offshore CAPEX is forecast to grow by a compound annual growth rate of 20%, totaling nearly $994m in 2015.

 

Future holds bright for East Africa!

  • Uganda Prime Minister Apollo Nsibambi said, "East African countries will jointly explore their "vast" oil and gas fields to foster development of their economies". The cooperation will attract more investment capital and spur economic growth, Nsibambi told a petroleum conference in Kampala, the Ugandan capital, with giving details on how this will work.
  • Uganda will issue more oil-exploration licenses later this year after a new industry law is formulated, Nsibambi said. It has five remaining oil blocks after suspending the awarding of concessions in 2006 pending the new law, he said.
  • Kenya issued six exploration licenses between 2000 and 2002 and two more to CNOOC in the next four years. "Despite a long history of unsuccessful exploration, the oil companies are investing in Kenya," says Mwendia Nyaga, managing director of the National Oil Corporation of Kenya. "The question is not if any hydrocarbon deposits exist, but where they are."

 

     Other East African countries which are likely to hold significant resource potential are Somalia, Ethiopia and Mozambique. However, Somalia remains a no-go zone for investors due to its political unrest while Ethiopia's eastern Ogaden region is beset by a violent rebel insurgency. Mozambique is still recovering from its civil war which broke out in 1992.

 

     Every new frontier area for oil and gas exploration & production faces its difficulties and East Africa is no exception to that. The political hurdles in the region if addressed properly, this region will prove to be a boon not only to exploration and production companies, but also to other market participants in the oil and gas value chain, such as drilling companies, service providers, and equipment manufacturers.

 

                             
     

Oman: Tethys Oil Contracts Second Rig to Accelerate Work Programme Onshore Oman   

 

(www.energy-pedia.com - March 30, 2011)


Oman Flag

 

     Tethys Oil has accelerated the development and exploration programme on Blocks 3 and 4 onshore the Sultanate of Oman with the contracting of a second drilling rig. The first well being drilled by this rig is the Farha South-6 well (FS-6) on Block 3. 

 

     The new rig, a 750 horsepower Deutag T-55, is operated by UK drilling contractor KCA Deutag Drilling Company. The new rig will be used alongside the Abraj 204 rig already in use on the Blocks, and currently drilling theSE-7exploration well on Block 4.

 

     'We are very pleased that the work programme of Blocks 3 and 4 of Oman is been accelerated, underpinning both the extent of Blocks 3 & 4 areas which remain un-explored to-date as well as remaining geological uncertainties before a fully-fledged development plan is put in place. Two rigs will allow a speedier drilling schedule for 2011,' says Magnus Nordin, Managing Director of Tethys Oil.


     FS-6 is drilled as a vertical well, designed to target the lower Barik formation. The drill site is located 140 metres southeast of well FS-4 and 750 metres south-southwest of well FS-3. Tethys has a 30 per cent interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East with 20 per cent and the operator CC Energy Development (Oman branch) holding the remaining 50 per cent.

 

Nations Going Global on Drilling Standards 

 

(www.fuelfix.com - April 15, 2011)  



     Drilling regulators from a dozen countries on Thursday agreed to form a working group that could eventually develop global offshore drilling standards.  

 

     Interior Secretary Ken Salazar suggested the idea at the end of a daylong summit on offshore drilling safety that focused on learning lessons from last year's Deepwater Horizon disaster, including a need for better ways to rein in runaway underwater wells. "The working group can help us figure what the best organization is" and "can help us develop global protocols for oil and gas development," Salazar said.

 

     The current set-up - a patchwork of standards that vary from ocean to ocean and country to country - doesn't recognize the reality that the same companies drilling in the Gulf of Mexico are also drilling off Brazil, Angola and Norway, Salazar said. "I feel confident in what we are doing with the Gulf of Mexico, but the oil and gas industry is a global industry," Salazar said. And, he added, "it's one ocean in this Earth."

     "When we get to the second anniversary of the Macondo spill, hopefully we will be able to be working on global standards that go beyond just our own backyard," Salazar said.

    The representatives at Thursday's summit - including those from the United Kingdom, the European Union, Russian Federation and Australia - tentatively agreed to meet again in Oslo, Norway, in 2012, on the Gulf spill's second anniversary. Salazar tasked his offshore drilling chief, Michael Brom-wich, with developing the framework for the international working group within 90 days.

     One notable absence in the planned collaboration - at least initially - and at Thursday's international summit is Cuba, which expects five wells to be drilled off its coast in the next two years. Salazar said the U.S. was concerned about the potential drilling 60 miles off Florida, within the loop current that travels up the East Coast.

     The drilling regulators at Thursday's summit stressed that the blowout at BP's failed Macondo well is shaking up government oversight of coastal oil and gas exploration far beyond the Gulf of Mexico. Geoffrey Podger, chief of the United Kingdom's health and safety executive, called the blowout of BP's Macondo well a seminal event, like the 1988 explosion on the Piper Alpha platform in the North Sea that killed 167 people. "The accident was a watershed for the oil industry," said Mario Gabriel Budebo, Mexico's undersecretary of hydrocarbons, who has been meeting with U.S. officials to try to harmonize standards for drilling in the Gulf.

     One of the biggest post-Macondo lessons, Budebo said, was "the need for drilling and development plans to include design of emergency procedures" for countering blowouts.

     Jan de Jong, the Netherlands' inspector general of mines, stressed that "it is absolutely necessary to raise standards in industry." "This accident is not unique for deep-sea drilling in general, nor BP, nor for the Gulf of Mexico," Jong said. "It could have happened anywhere."

     Norway's top petroleum and energy minister, Per Rune Henriksen, said he was dismayed by the inability to cap blowouts as evidenced by the Gulf spill that took 85 days to contain and the Montara blowout near Australia that leaked for 74 days before it was finally killed in November 2009.

     Those crude-containment failures are "highly unsatisfactory," Henriksen said. "This is an area where the industry must provide solutions."

 

Egypt's Amir SE-7X Successfully Sidetracked 

 

(www.petroleumafrica.com - April 12, 2011)   

 

Egyptian flag small      

 

     Circle Oil said that the Amir SE-7X water injector well on the Al Amir Development Lease on Egypt's NW Gemsa Concession, has been successfully sidetracked and has now reached target depth at 15,600 ft measured depth in the Lower Rudeis. The main objectives for this well were to provide water injection support into the Kareem sands and to delineate the Kareem oil-water contact, which is required for technical reasons including resource estimation.

 

     Circle said that the Kareem sands were encountered between 10,664 and 10,852 ft and these have been successfully cased off. The Main Shagar Sands, encountered between 10,738 and 10,770 ft, were water bearing and of excellent reservoir quality. As a result Al Amir SE-7X should provide a good initial water injection well. The overlying sand stringers from 10,664 to 10,718 ft have indicated oil saturations on logs. This places the deepest oil in Al Amir SE for the Kareem at approximately 10,200 ft subsurface, which positively corresponds with the latest estimates for the oil-water contact calculated using formation pressure data.

 

     The company reported that additional work is to be undertaken to refine this elevation. The well has been plugged back to 11,180 ft MD and is being completed as a water injector in the Kareem sands to support the updip oil producers. A further development well and water injection wells form the immediate drilling program for the Al Amir SE field.

 

   The secondary objective of the well was to evaluate the Lower Rudeis thin sand stringers with indicated hydrocarbon saturations between 15,553 and 15,567 ft MD, which were previously encountered in the Al Amir SE-6X well. Log analysis by the operator identified 6 ft of pay with an average 10% porosity and a hydrocarbon saturation of 68%. The decision was taken not to test this interval due to mechanical problems, but to conduct further drilling to properly evaluate the productivity of the Lower Rudeis sands.

 

     In the drilling of the up-hole section of Al Amir SE-7X, sand stringers with potential hydrocarbon saturations containing 6 ft of potential pay were encountered in the South Gharib (5,634 to 5,645 ft MD) and a further 4 ft of potential pay in the Belayim (8,400 to 8,404 ft MD). These zones will be the subject of further evaluation in future drilling which will be undertaken to properly evaluate these positive occurrences for additional hydrocarbons in the NW Gemsa block.

 

     Further intensive exploration, appraisal, and development drilling is planned over the next eighteen months. This will include drilling water injection wells to support the oil production in both the Al Amir SE and Geyad fields as required.

 

     In addition, construction is now underway to construct facilities together with an 8-inch gas pipeline to the nearby facilities for gas export and the sale of gas and associated liquids. These facilities are expected to be completed by year end, with an associated increase in gas and liquids production.

 

     The current production rate from the NW Gemsa fields of Geyad and Al Amir SE is approximately 7,500 bopd gross as fluid off-take from the fields is controlled in line with best reservoir management practice as the water flood is initiated, becomes operational, and is proven to be effective in maximizing recovery rates. By mid-2012 the production rate is expected to rise to approximately 12,000 bopd gross as water flood operations become effective.

 

     Work is currently underway on an independent third party report to identify the ultimate recoverable resources for NW Gemsa. The results are expected during Q2 2011 and will be incorporated within Circle's Annual Report for 2010.

 

API: White House is Stopping Domestic Oil and Gas Production

 

(www.fuelfix.com- March 25, 2011)

    
  
     The American Petroleum Institute is circulating a graphic that aims to highlight what the trade group says is a series of Obama administration decisions that are thwarting domestic oil and gas development. The document, which will be circulated on Capitol Hill, represents the latest attack by API, which has taken an increasingly adversarial role fighting the administration's energy policies.

     With images ripped from the roadway, API argues that the administration "has taken specific steps to stop or delay the development of domestic oil and natural gas resources." According to the trade group, those include:

  • The Interior Department's decision not to proceed with a Bush-era plan for leasing the outer continental shelf that would have opened broad swaths of coastal waters for oil and gas development. The Bush plan would have run from 2010 through 2015 and replaced an existing leasing blueprint that runs through the middle of 2012.
  • The suspension in early 2010 of 61 oil and natural gas leases issued in Montana as part of a settlement with several environmental groups that had challenged them in court. The Bureau of Land Management ultimately lifted suspensions on 45 of the leases but maintained suspensions for six of them.
  • The Bureau of Ocean Energy Management, Regulation and Enforcement decision last November to prepare a supplemental environmental impact statement for the Gulf of Mexico - effectively a post-spill update of an earlier environmental study of the region - before selling more leases there.
  • Delays in the permitting of offshore drilling projects. Since new safety and environmental mandates were imposed last year, the ocean energy bureau has approved 38 new wells in shallow water and five drilling projects that were blocked by a ban on deep-water exploration.
  • The State Department's decision to do more environmental studies before choosing whether to approve the Keystone XL pipeline that would deliver oil sands crude from Alberta, Canada to Gulf Coast refineries. The State Department indicated it would make a final decision on the project this year.

     "The administration has repeatedly decided to pursue policies and actions that delay, defer or deny access and production from our domestic resources," said Erik Milito, API's upstream director, in a conference call with reporters Thursday.

     Administration officials argue that some of the environmental decisions are designed to ensure later lease sales and drilling decisions will stand up to legal scrutiny. Interior Secretary Ken Salazar has repeatedly noted that an increasing number of regulators' decisions are being challenged - and reversed - in court, a practice that amplifies the need for more deliberate assessments by the government agencies that must defend them.

      Michael Bromwich, the head of the ocean energy bureau, also says his agency is moving as "expeditiously" as it can - with the resources it has - to examine proposed drilling projects and ensure they satisfy new safety mandates. Bromwich also has stressed that until recently, the oil and gas industry was unable to prove it could swiftly tame a blowout in deep Gulf waters, which is a requirement for those projects to be permitted.

              

Libya's Fuel Imports Hit Snags, Put Pressure on Gadhafi

 

(www.marketwatch.com- April 15, 2011)

           

    International political pressure is hitting the regime of Col. Moammar Gadhafi's Libya where it hurts-fuel imports that could be critical to sustain its war effort against the rebels. In recent weeks, sanctions blocked a Libya-bound gasoline cargo, while Tunisian activists forced fuel trucks to return empty to their North African neighbor.

     While the sanctions have stymied access to cash reserves abroad and crude-sale revenue, they are also cutting into one of Libya's lifelines. Like many oil-producing countries, Libya has constrained refining capacity and has long relied on outside supplies for its fuel. It bought 80,000 barrels a day of refined products abroad in 2010, according to the International Energy Agency.

 

     The civil war has worsened the situation, leaving many domestic refineries out of order or in rebel hands, triggering fuel shortages and forcing the country to search for more fuel abroad. But late March, the "Breeze A," a tanker transporting products from Greece, was stopped in Malta on its way to Libya, according to an official at the ship's owner, Athens-based Ancora Investment Trust Inc. The Ancora official said the cargo "couldn't go because of the sanctions" against Libyan state-oil companies.

 

     In Tunisia, activists who had helped topple Zine El Abidine Ben Ali in January also stopped three large fuel trucks that had come from Libya to refill, official agency Tunisie Afrique Presse reported March 31. The activists were concerned the fuel could be used by Col. Gadhafi's forces against opponents.

 

     Oil products are a well-known vulnerability for countries under sanctions. Last year, the U.S. enforced measures specifically targeting Iran's gasoline imports. That forced the Islamic Republic to curtail its consumption and to forgo lucrative petrochemicals exports for a boost in domestic fuel production. But while Iran has long been helped by its nationals abroad, opponents to Col. Gadhafi are actively scrutinizing shipments they suspect could be heading for Libya.

 

     On March 17, a Libyan resident in Malta, acting on behalf of opponents, filed for a precautionary warrant of arrest for a tanker, his lawyer Louise Anne Pulis said. The opponents feared it was bound to Libya after rebels in Benghazi intercepted a fuel vessel destined for the regime a few days earlier, she said.

     A local court acceded to the request, based on sanctions and humanitarian grounds, and the tanker was only allowed to leave empty, the lawyer said. However, Oiltanking Malta, which operates the terminal where the ship was stationed, denied in a statement that Libya was the vessel's next port of call.

Unlike Iran, Libya's fuel snags also come amid a military effort-where gasoline is known to play a key role.

     According to "The Prize," Daniel Yergin 's epic saga on oil politics, the British feared they could be defeated in World War I because of fuel shortages. The Germans lost the subsequent international conflict in part because they failed to access huge oil fields in Azerbaijan and the Middle East, the book says.

     Yet Libya's fuel situation doesn't appear to have reached the breaking point. The government imported 19,000 metric tons of gasoline on a Libyan ship, Agence France-Presse reported last week, citing an unnamed official close to National Oil Corp.

     Speaking to Dow Jones Newswires on Sunday, NOC Chairman Shokri Ghanem said the Zawiya refinery was also still supplying the fuel needed for power stations.

Oil Firms to Deploy New Containment Device for Deepwater Spills

(www.online.wsj.com - April 15, 2011)  

     

   

      The high-tech marvel enabling oil companies to return to the deep waters of the Gulf of Mexico sits in a sun-baked industrial lot in the outskirts of Houston, not far from a gas station, a taco truck, and a highway that could quickly take it to the scene of the next Gulf oil spill. 

 

     The new spill-containment device was developed by a consortium led by Exxon Mobil Corp. to control future spills similar to the largest marine oil spill that leaked more than four million barrels in the Gulf last April.


     "We like it here," Marty Massey, chief executive of Marine Well Containment Co., said Friday as the company unveiled to reporters the device, called a capping stack, that is the heart of the containment system. "[The device was] built here; the people who built it can maintain it" and can be deployed to its destination "in a matter of days," Mr. Massey said. "We are ready to go."

 

     The 30-foot-tall, 100-ton stack-a tree-shaped mass of blue, yellow and white steel with protruding knobs and gauges-is meant to be lowered on top of a deepwater gusher, either killing the flow or funneling the oil to ships. It draws on the lessons of the system BP PLC struggled to develop during the three months it fought to control the damaged Deepwater Horizon well that unleashed a major environmental disaster. The company said the containment system the device is part of can capture up to 60,000 barrels a day from wells up to 8,000 feet below sea level.

 

     Massey said the consortium, created by Exxon, Chevron Corp., Royal Dutch Shell PLC andConocoPhillips, is developing a similar system with a higher capacity capable of capturing up to 100,000 barrels a day from gushers as deep as 10,000 feet. This improved version, Massey said, will operate from several bases along the Gulf Coast and be ready around mid-2012.

 

     As the government suspended deepwater drilling following the Gulf disaster, the oil industry needed to quickly take steps and prove it was capable of controlling any future deepwater spills. In late February, the government lifted the moratorium on deepwater drilling, following the development of MWCC's containment system and a competing system developed by Helix Energy Solutions Group Inc.

 

     Ten deepwater drilling permits have been granted so far by the Bureau of Ocean Energy Management, Regulation and Enforcement, a U.S. Department of Interior agency. The fact that there are two systems now available to cap deepwater rogue wells in the Gulf of Mexico is "a huge step forward," said Tad Patzek, head of the Department of Petroleum and Geosystems Engineering of the University of Texas at Austin. The technology was always available in principle, but it wasn't really proven to work until, after much effort, BP used it to control the well that caused last year's spill, Mr. Patzek said.

 

     While it's fortunate that these systems now exist, Mr. Patzek said, "none of these devices should ever be deployed," if the oil industry does the job right. With these devices, it could take 10 days instead of three months to stop a spill after a well blowout, but "still, considerable damage will be done, not to mention [possible] loss of life," Mr. Patzek said.

In the event of a deepwater blowout, MWCC will transport the capping stack to a Gulf Coast port and to its offshore destination. Its operation will be placed under the control of a joint command of U.S. authorities and the company responsible for the oil spill.

 

     When submerged at the bottom of the sea, it will be able to withstand gusher pressures of up to 15,000 pounds per square inch with tough steel blades that shut close. If the well cannot be shut in, the escaping oil and gas will be shipped to the surface through a series of tubes. The captured oil will be stored in drill ships and captured gas will be flared, said Dan Smallwood, MWCC's chief operating officer. MWCC also keeps another capping stack, designed to operate at lower pressures.

 

     The company has commissioned the construction of two large vessels to store oil, to augment the improved version of the system, Massey said. When not in use for controlling spills, the ships will be used to offload oil from tankers in the Gulf.

 

     Besides its four founders, six other companies have joined MWCC, putting up a total common investment of $1 billion. These are BP, Apache Corp., Norwegian oil giant Statoil ASA, BHP Billiton Ltd., Anadarko Petroleum Corp. and Hess Corp.

 

     Massey said that the 10 companies that equally share investment and operational expenses account for 70% of the deepwater wells drilled in the Gulf. Other companies can pay fees to use the system even if they don't want to become full-fledged members of the consortium.

 



               

Issue: 04-2011
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Oil Chart April 2011
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In This Issue
Egypt to Revise All Foreign Gas Deals
Algeria: Sonatrach Seeking Partners for Shale Gas Pilot Project in 2012
Tunisia: BG Plans $300 Million Investments in Tunisia in 2011
East Africa - Continent's New Hotbed for Oil & Gas Exploration!
Oman: Tethys Oil Contracts Second Rig to Accelerate Work Programme Onshore Oman
Nations Going Global on Drilling Standards
Egypt's Amir SE-7X Successfully Sidetracked
API: White House is Stopping Domestic Oil and Gas Production
Libya's Fuel Imports Hit Snags, Put Pressure on Gadhafi
Oil Firms to Deploy New Containment Device for Deepwater Spillls
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  • GeoInformatics 2011 in Kyiv, Ukraine - starting 10 May 2011
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  • Sfax Student Lecture Tour North Africa in Sfax, Tunisia - starting 12 May 2011
  • SPE/DGS Annual Technical Symposium and Exhibition in Al Khobar, Saudi Arabia - starting 15 May 2011
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  • New Representation of Seismic Data - Aiming at Increased Information Density at Less Cost (Vienna '11 Workshop) in Vienna, Austria - starting 22 May 2011
  • Capturing Realistic Sedimentary Architecture in Geocellular Reservoir Models (Vienna '11 Workshop) in Vienna, Austria - starting 11 May 2011
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  • Electromagnetics for Integrated Reservoir Development - What needs to be done? (Vienna '11 Workshop) in Vienna, Austria - starting 23 May 2011
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