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Posted 11:54 pm Sunday, February 03, 2013
The drilling report was produced with data from the Texas Railroad Commission, from January 20 to January 26. The following counties were searched: Anderson, Angelina, Camp, Cass, Cherokee, Dallas, Ellis, Freestone, Gregg, Harrison, Henderson, Houston, Kaufman, Leon, Limestone, Marion, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, San Augustine, Shelby, Smith, Upshur, Van Zandt and Wood. For information contact Business Editor Casey Murphy at cmurphy@tylerpaper.com or 903-596-6289.
Friday, February 15, 2013
ROC Spuds Balai RSC Exploration Well Offshore East Malaysia
ROC revealed Friday that BC Petroleum, the company incorporated to operate and manage the Balai Cluster Risk Service Contract (RSC) in Malaysia, has started drilling the Spaoh-2 well at 1930 local time Thursday. At 0600 local time, the well was drilling ahead at 1,070 feet (326 meters).
Spaoh-2, sited in the Spaoh field offshore East Malaysia, will be drilled to around 8,892 feet (2,710 meters).
The Balai Cluster RSC consists of four fields: Balai, Bentara, West Acis and Spaoh. Petronas entered into a RSC for the pre-development and development of the Balai Cluster fields in 2011 with ROC and Dialog. Under the RSC agreement, ROC is expected to complete the pre-development phase for the fields by mid-2013. On successful completion of the pre-development phase and agreement on the economic viability of the fields, ROC will submit a field development plan, and progress to development of the fields.
There are currently two RSCs in place offshore Malaysia: the Balai Cluster RSC and the Kapal, Banang and Meranti RSC (KBM RSC). Malaysia announced Jan.25 that it has decided not to proceed with the award of the Small Field Risk Service Contract (RSC) for the Tembikai and Chenang Cluster.
RSC contracts from Petronas have drawn much interest among international oil exploration companies, given Malaysia's renewed focus on developing its domestic oil and gas assets.
Back in 2011, Petronas noted that it aimed to award four marginal fields per year. However, as only two RSCs have been dished out over the last two years, industry watchers say that Petronas could ramp up on its efforts on the RSC front, and look to award more contracts this year in order to meet its oil production targets.
Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.
Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.Sound Oil May Accelerate Laura Field Development
Italy-focused Sound Oil announced Friday that its Laura field development in the Gulf of Taranto may be accelerated after the firm began discussions with the Italian Ministry of Economic Development about the project.
Laura is a 30 billion standard cubic feet discovery, previously discovered by ENI in 1980. Sound said that it is talking to the Ministry of Economic Development about applying directly for a production concession – rather than a permit to drill an appraisal well – in order to accelerate production from Laura by at least a year.
Sound also reported that it recently received a farm-in offer for its Badile exploration prospect from what it described as a "high quality" potential partner. The Badile prospect, onshore Italy in the Po Valley, is estimated to hold resources some 23 million barrels of oil.
The firm's 21 billion cubic feet Nervesa gas discovery in northern Italy is currently undergoing operations to prepare the site ahead of production. These operations will continue until February 12, when written permission from the authorities will be needed to proceed to complete the site.
Meanwhile, Sound is also continuing to revamp field facilities at its Rapagnano field in the Marche region of Italy. These facilities are now expected to be successfully commissioned by the end of February, with first gas following shortly afterward.
Sound added that it has completed a full review of its asset portfolio and expects to put in place a structure divestment process for a package of non-core assets.
"The company is making good progress on its core strategic objectives, including potentially accelerating production from the Laura discovery," Sound CEO James Parsons commented in a statement.
"Whilst Italian approval processes are causing operations at Nervesa and Rapagnano to progress slower than we would have liked, both are moving forward and our focus remains on delivering a successful well and commercial first gas for our shareholders."
Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed. Enegi Oil Farms Out North Sea Block to Azimuth
Junior explorer Enegi Oil announced it has reached an agreement to farm out to Azimuth part of Block 3/23 in the UK North Sea. The block holds the Malvolio prospect, as well as a number of potential exploration opportunities.
Enegi said the deal will see Azimuth earn a 50-percent interest in the exploration area in exchange for the completion of an agreed work program that includes certain geological, geophysical and reservoir analysis that will use existing seismic and well data in respect of both the Malvolio area and the exploration area.
Enegi will retain a 100-percent working interest in the Malvolio area.
Enegi CEO commented in a statement:
"We are delighted to have reached agreement with the Azimuth team. We were only offered this Block just over three months ago and the fact that we are already moving ahead with our plans for it shows our desire to deliver and prove up the value that we believe is inherent not only in this asset, but also across our portfolio.
"We know the Azimuth team well and are delighted to be working with them on this project. They are a hugely experienced team backed by leading industry specialists with access to extensive resources, both in terms of data and people."
Thursday, February 14, 2013
New World Comes Up Dry at Blue Creek
New World Oil & Gas announced Friday that its Blue Creek No.2A side track well in the Petén Basin in northwest Belize has come up dry after the firm drilled to a measured depth of 11,650 feet Jan. 27.
The firm said that, after careful analysis, it was determined that insufficient commercial quantities of hydrocarbons were present to merit running casing and well-testing operations. As a result, New World has decided to plug and abandon the well.
New World pointed out that data has shown that a live hydrocarbon system does exist in the area and that live oil shows were seen in formations during the drill. Technical data garnered from both the No. 2A side track and the Blue Creek No. 2 wells will now be used during the drilling of the company's next well: the Rio Bravo Well No.1 in the West Gallon Jug.
The drilling of the Rio Bravo No. 1 well is expected to begin during the first quarter of this year.
"Analysis of the data gathered from the Blue Creek #2A and Blue Creek 2A ST wells points to the migration of huge quantities of oil through this area. Combined with the presence of a reservoir ideal for oil production, and a large, extensive anhydrite seal, we remain highly confident that the elements required for a working hydrocarbon system are in place in North West Belize," New World CEO Bill Kelleher commented in a statement.
"As highlighted by B Crest, trap remains the key outstanding element required for success in this area and, with multiple prospects already identified, we believe it is only a matter of time before we locate a trap of significant size and in the process make a commercial hydrocarbon discovery. With this in mind, we look forward to commencing drilling operations in the West Gallon Jug Crest prospect later this quarter for which we are fully funded and where the geologic trap mechanism remains independent of B Crest."
Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.Plexus Brings New Engineering Approach to Wellhead Technology
UK-based Plexus Ocean Systems Ltd., a division of Plexus Holdings plc, is utilizing a patented technology that the company believes will improve wellhead design to prevent or minimize the impact of blowouts such as the April 2010 Macondo incident in the Gulf of Mexico and the 2009 Montara blowout offshore Australia.
The company's POS-GRIP technology, invented by the company's CEO and founder Ben Van Bilderbeek employs a method of elastically deflecting an outer wellhead body onto an inner casing or tubing hanger and locking them in place to support tubular weight and activate seals. In surface wellhead applications, the system is powered by reusable hydraulic devices, which are fitted temporarily to flanges on the outside of the wellhead.
Van Bilderbeek said he sees friction-grip technology as the best available and safest (BAST) method of engineering for wellheads for all applications, including:
Exploration wellheadsProduction wellheadsTie-back wellheadsDeepwater dry tree wellheadsSurface blowout preventer (BOP) wellhead systemsWorkover wellheadsGeothermal wellheadsFracking technologyCO2 storage wellheadsPOS-GRIP technology has been used for 12 years in the North Sea, particularly for high-pressure, high-temperature (HP/HT) wells, Van Bilderbeek told Rigzone.
The technology was initially introduced in the North Sea through an adjustable rental wellhead system for jackup drilling operations; later, POS-GRIP technology was developed for use in specialized HP/HT wellhead systems.
Plexus hopes to replicate the success of its HP/HT technology in the larger international production wellhead and subsea arenas as company officials see many applications in unconventional fields.
The company has had discussions with a number of companies to license POS-GRIP technology, and would like to enter the U.S. market with a partner, or potentially sell certain applications that don't fit perfectly with Plexus' business strategy.
"We ourselves are not interested in operating in the U.S. due to the risk factors that apply in U.S. waters," said Van Bilderbeek. There are lots of targets around the world with less risk."
POS-GRIP technology presents a number of advantages over existing spool-type and mandrel hanger wellhead technologies, depending on the application, including:
Installation of hangers through the BOPShorter time for installationRigid assemblyMultiple metal seals over a large contact areas, for a corrosion resistant designIntegral seal design to minimize the number of leak pathsSingle component hangersThe technology also offers superior reliability, reduced life cycle cost and is tolerant to a contaminated environment.
The company's roster of customers includes: Apache Corp., BHP Billiton Ltd., BP Plc, ConocoPhillips Company, Maersk Oil, Lundin Petroleum AB, Newfield Exploration Company, Talisman Energy Inc., Statoil, Royal Dutch Shell Plc, Total S.A. and Wintershall Holding GmbH.
"Recent well control incidents around the world have highlighted the need for robust, high performance, subsea wellheads in oil and gas operations, particularly in extreme and hostile environments," said Van Bilderbeek in a June 19, 2012 statement.
"Specific functionality is required such as instant casing hanger lockdown, the ability to monitor sustained casing pressure and then enable remedial action and bleed off capability."
The company has designed wellheads to be the strong link in the well system, Van Bilderbeek noted in a presentation for U.S. government officials in December 2012, and is pursuing a policy of preventing blowouts "by design". Achieving the goal of wellheads as the strong link includes matching wellhead standards to those for casing and tubing couplings, Van Bilderbeek noted.
To prevent blowouts, the company argues that the industry needs to eliminate the practice of lifting BOPs from the wellhead to set casing. Wellheads must be designed to be permanent safe platforms for well control devices, while maintaining dual barriers across the well bore and annular spaces adhered to at all times.
Additionally wellhead designs where possible should rely on rigid metal sealing for integrity beyond field life, and such standards should apply to all applications, rather than just for HP/HT wells.
Van Bilderbeek pointed out that current wellhead qualification test procedures are component based, whereas emerging standards require specific qualification tests treating seals as part of a system. Currently, standards for casing and tubing couplings are far more stringent than for wellheads.
Most blowouts occur when the BOPs are away from the wellhead, as American Petroleum Institute (API) spool type systems require removal of the BOPs to set casing.
One justification for continuing the century old habit of lifting BOPs is that this method eliminates to need to space out casing, avoiding the extra work of measuring pipe into ground.
"Further excuses include the need to tension casing, which is negated by the fact that this can be done with through BOP technology," Van Bilderbeek noted.
There is no longer any justification for ever designing wellheads that require the lifting of BOPs to be set casing, as without a BOP in place a well is left under the sole protection of single barriers for an extended period of time.
The Montara Commission of Inquiry Report links the design of pressure containing corrosion caps to the Montara incident, adding that removing abandonment caps from the well before a riser with a well control device on top is re-established clearly breaks the dual barrier rule, Van Bilderbeek noted.
The United States' forerunner agency to the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement (BSEE), the U.S. Minerals Management Services had recognized the risk of lifting BOPs; they proposed a solution to improve cementing techniques, as seen in an incident that occurred in April 1997 at East Cameron Block 328. On that day, a serious blowout and fire occurred on Platform A. The U.S. Department of the Interior (DOI) concluded the probable cause of the incident was formation gas migrating through the cement between the 9-5/8-inch casing and the 13-3/8-inch casing.
DOI officials also concluded there was not enough wait-on-cement time prior to nippling down the BOP. A possible contributing cause was that, since the well had been drilled horizontal, the casing may not have been properly centralized, resulting in a non-uniform cement job.
Plexus' solution would be to require that the BOPs be left in place by using thru-BOP wellhead technology, which is available from all major suppliers. This allows an operator to control a well-kick during casing installation procedures.
Van Bilderbeek believes the industry would benefit from a wider acceptance of the simple and obvious BAST rule -- never lift BOPs unless absolutely necessary.
When a POS-GRIP wellhead is activated, multiple metal seals interact over a long interface between the wellhead bore and casing hanger. Conventional annular seal are no longer required, and movement between parts is eliminated for integrity beyond field life. Qualification has taken place under simulated and extended field life testing conditions, Plexus officials noted.
In subsea wellhead applications, the technical solutions available to lock and seal casing and tubing annuli have been problematic. As a direct consequence, the industry has adopted a procedure of installing lock-down sleeves to fix casing hangers in the well bore at the end of the drilling program.
These devices, which are time consuming and can cost between an estimated $2 million and $5 million to install, are used because of the problems associated with using remotely activated lock-ring devices in the contaminated environment of a subsea well.
To be functional, a lockdown sleeve needs to be set with downward load on the casing hangers. The length of the weight string of pipe hanging from below a lockdown sleeve can dictate the setting depth for the cement plug, depending on the chosen installation sequence, van Bilderbeek noted.
If mud is replaced with seawater prior to setting of the cement plug, its setting depth can contribute to under-balancing of the well, which suggests that the use of a lockdown sleeve to secure casing hangers in a subsea wellhead, because conventional lockdown devices are problematic, can lead to well control incidents.
"Conversely, on surface wellhead applications, all casing hangers are individually locked down as soon as casing is cemented, and this is done for good reason," Van Bilderbeek noted, and the same logic and safety disciplines should apply subsea for the protection of personnel and the environment.
Van Bilderbeek noted that DOI's May 2010 report advising that all casing hangers should be instantly locked down following cementing is correct.
Van Bilderbeek, who met with U.S. government officials in early December 2012 as part of a teaching mission on technology available for wellhead design, and to highlight the conflict which comes into play when a technology is both BAST and proprietary, notes that no justification exists for ever leaving casing hangers unlocked in a subsea wellhead at any time during drilling or production.
Van Bilderbeek commented that Shell has issued revised qualification guidelines which require that the lockdown capacity for subsea casing hangers during drilling is proven to a level equivalent to the requirement for production casing hangers in the field, Van Bilderbeek noted.
In October 2010, a joint industry project (JIP) was formed by Plexus to focus on development of a new class of subsea wellhead system, the POS-GRIP HGSS subsea wellhead, with particular focus on addressing systemic deficiencies of current technology. The JIP's primary target is to design a wellhead system in which all casing hangers can achieve rigid lockdown following cementing, while remaining releasable if it becomes necessary to recover casing.
The JIP's member rosters now include ENI, Oil States Industries, Maersk Oil subsidiary Maersk Oil North Sea UK, Shell Plc subsidiary Shell International Exploration and Production, Wintershall Holdings GmbH subsidiary Wintershall Noordzee, Total S.A., and Tullow Oil Plc. The project is expected to take between 18 and 24 months from the February 2012 launch date at a cost of approximately $2.3 million to $3.1 million (GBP 1.5 million to GBP 2 million). Any intellectual property created through the JIP will be owned by Plexus.
Key features that Plexus hopes to incorporate into its new POS-GRIP HGSS subsea wellhead design include:
18-3/4-inch full bore system, rated to 15,000 per square inch (psi) and 350 degrees FahrenheitAbility to upgrade to 20,000 psi, 450 degrees Fahrenheit4 million pounds of "instant" casing hanger lockdown capacityAvoidance of acknowledged problems associated with using lock down ringsAnnulus monitoring and bleed-off capability to address sustained casing pressure situations, with diagnostic and remedial capabilityAbility to open and reseal the casing annulus to enable remedial cement job proceduresRigid metal annular seal technology qualified to match the standards for premium casing couplingsMeeting the API 17/D/ISO 13628-4 requirements, recently provided operator requirements, and Plexus Life Cycle TestingThe wellhead standards utilized by the Plexus JIP will be more stringent than those proposed by API for similar technology, Van Bilderbeek commented.
The Plexus wellhead standard will be pitched to match the standards required of premium casing and tubing couplings. Van Bilderbeek noted that this is not the approach that API currently takes by allowing a single sample test, and unlimited number of attempts.
The Plexus JIP also requires make and break testing, test to failure, simulate field conditions, and test under loading, Van Bilderbeek noted.
BSEE has identified the need for development work on 20,000 psi extreme HP/HT subsea drilling equipment and well design. However, Van Bilderbeek pointed out that a recent BSEE report fails to address systemic shortcomings of conventional 15,000 psi and below applications, focusing only on work to be done in the 20,000 psi and above category.
The BSEE has reported that additional developments and qualified work will be required before 20,000 psi systems are commercially available for subsea applications. For 20,000 psi drilling equipment, the current direction is the development of custom products. Wellhead systems with working pressures in excess of 15,000 psi are under development and not expected to be ready for use for a number of years.
Van Bilderbeek reported that the HGSS wellhead technology design work is underway, based on qualified hanger designs used on 20,000 psi surface drilling operations in the North Sea.
Testing on the HGSS JIP to adapt POS-GRIP technology for subsea applications is well advanced, and a POS-GRIP HP/HT tie-back connector designed to allow operators to pre-drill HP/HT production wells is now available.
Plexus believes POS-GRIP's potential in its HP/HT tieback application is one of the most far reaching developments in many years. According to Plexus, HP/HT and ultra high-pressure/high-temperature (XHP/XHT) wells could be safely tied back at a future date, negating the disposable nature of these wells.
Potential savings for the operator is the entire cost of the well, which Plexus estimates is between $75 million to $450 million per HP/HT well, and the well can begin to generate revenues at a much earlier date. HP/HT wells in a proven field could be pre-drilled and abandoned ready for completion while the platform was being designed and construction.
Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.
Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.Seadrill Orders Two Jackups from Dalian Shipbuilding
Deepwater drilling specialist Seadrill announced Friday that it has ordered two jackups for delivery in the first half of 2015 from Chinese firm Dalian Shipbuilding Industry Offshore.
The two units, which will cost $230 million per rig, will be based on the F&G JU2000E design, with water depth capacity of 400 feet and drilling depth of up to 30,000 feet. Seadrill has also arranged option agreements with Dalian to construct an additional two rigs for delivery in the third and fourth quarters of 2015, said the firm.
Seadrill Chairman John Fredriksen commented in a statement:
"These newbuilds position us for additional growth in a strengthening jackup market, providing further earnings upside for Seadrill. The premium jackup market continues to demonstrate strength as evidenced by increasing day rates and utilizations. Customers continue show preference for newer units from drilling contractors with proven track records of safe and efficient operations.
"Currently 312 jackups, or 65 percent of the total fleet of 483 jackups are older than 25 years. These two new firm orders increases our fleet of modern jackups to 25 rigs with an average age of three years, and further strengthens our position as the leading operator of premium modern, high-quality drilling units."
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