Cimarex enters joint development agreement with Chevron

Posted on 25 June 2013

Cimarex Energy has entered into an agreement with Chevron USA, a subsidiary of Chevron Corp, for the joint development of their combined Delaware Basin acreage in Culberson County, Texas. Cimarex will act as operator of the joint development, which covers 104,000 acres.

Chevron will contribute acreage and pay Cimarex approximately US $60 million for a 50% interest in the Cimarex-built Triple Crown gas gathering and processing system and wells drilled on the acreage in 2013.  The contract has an eight-year term.

“Collaborative development of this ‘checkerboard’ acreage ownership makes perfect sense. Optimal well placement for both Second Bone Spring wells and longer-lateral Wolfcamp shale tests can now be achieved,” Tom Jorden, CEO of Cimarex, said.

View the original article here

Statoil sanctions Julia development in GOM with ExxonMobil, pushes ahead with Logan

By Katherine Scott, associate editor

Speaking at the 2013 OTC, Jason Nye, senior vice president US offshore for Statoil, said the company is currently producing three fields in the Gulf of Mexico at approximately 40,000 bbls of oil/day but hopes to increase that number to approximately 200,000 bbls/day by 2020. Statoil recently also announced the sanction of the Julia field development with ExxonMobil.

Pursuing further growth in its US offshore portfolio, Statoil has sanctioned its fourth field development in the Gulf of Mexico (GOM). On 7 May, Statoil and operator ExxonMobil announced the sanction of the Julia field development; the partners each own 50%. “It’s about a $4 billion project for the first phase. I would have to say it’s one of the largest fields ever discovered in the GOM,” Jason Nye, senior vice president US offshore for Statoil, said on 8 May at the 2013 OTC in Houston. “It’s in the emerging Paleogene play, so we decided to do a phase development to reduce some of the risk because it hasn’t been widely drilled or widely produced.”

The first phase will consist of six wells, he said, and drilling operations are expected to start in 2014 and first production in early 2016. “This field is going to be producing for decades and decades, and there will be multiple phases. It’s also going to be a fantastic place to utilize some technology we’re developing and have developed going forward to extract more oil from those reservoirs.” The life of the Julia field is estimated to be up to 40 years, with an initial production rate of as much as 34,000 bbls of oil/day.

The field, located approximately 200 miles south of New Orleans, La., was discovered in 2007 and is estimated to have nearly 6 billion bbls of resource in place. The field development is projected to take approximately three years.

Julia, which is in some 7,000 ft of water and 30,000 ft under the seafloor, will be a subsea tieback to the Jack and St. Malo floating production platform, where Statoil is a co-owner with Chevron, Mr Nye said. The Jack and St. Malo platform is approximately 15 miles from Julia and was sanctioned in 2010.

Further, Statoil is pushing forward with operations in the Logan field, another Paleogene discovery and the company’s first operated discovery in the Gulf of Mexico. The company used the ultra-deepwater semisubmersible Maersk Developer to drill one well in the Logan field, which is currently in the appraisal phase, Mr Nye said. “With that one well, we’ve proved out somewhere between 1 and 2 1/2 billion bbls in place.”

With the block’s lease expiring in April 2015, Statoil has put together a tight schedule to develop Logan. “We expect to have first oil as early as 2018. This could be a stand-alone or a tie-back; it’s an interesting neighbor with some other discoveries.” Statoil will spud Logan’s appraisal well within the next week, again using the Maersk Developer, he said on 7 May, and in about 90 days will know whether to will move forward with project, though the company is very optimistic about the prospects.

Statoil currently has 340 leases in the deepwater GOM and 12 projects, operating in both the Miocene and Paleogene plays. The Miocene is more traditional, Mr Nye said, with high recoveries and high initial rates. The Paleogene play has deeper reservoirs in 7,000 to 10,000 ft of water and reservoirs at 30,000 to 31,000 ft under the seafloor. “I’d say we have a balanced portfolio because we’re evenly mixed between the more mature Miocene and the emerging Paleogene. And we have a significant presence in some of these emerging plays. (Industry has) been producing in the deepwater GOM since the ‘30s, but new plays are coming about, and we’re still finding new things.”

Statoil entered the GOM market in 2004 when the company was looking for areas with significant resource potential, Mr Nye said. “We have a long history of working in challenging and difficult environments, and we felt right at home here in the Gulf of Mexico.”

In addition to its four field developments, the company has three producing fields in its GOM portfolio, including Spiderman, Caesar Tonga and Tahiti. The three fields are currently producing at approximately 40,000 bbls of oil/day total, he said, but Statoil hopes to increase that number to about 200,000 bbls/day by 2020.

On the technology side, Statoil is pursuing a program known as “Crack the Paleogene,” which is focused on developing a tool kit of nearly 20 technologies, including electrical submersible pumps, multilateral technology, and water and gas injection. By applying these technologies, Statoil hopes to increase recovery rates from typical GOM fields from less than 10% to more than 20%, Mr Nye said. “The Gulf of Mexico has been a place where technology has been kind of the leading edge and push the envelope into deeper and deeper water and reservoirs.”

View the original article here

Energy Sector Business Development Account Manager (#771571258)

86575 - Accounts Payable Analyst
Our client is one of the world's largest energy companies employing over 80,000 personnel and operating in over 100 countries worldwide with expertise covering a range of energy sources.

They are currently recruiting for the position of Accounts Payable Analyst, based in Leatherhead.

86575 - Accounts Payable Analyst Our client is one of the world's largest energy companies employing over 80,000 personnel and operating in over 100 countries worldwide with expertise covering a range of energy sources. They are currently recruiting for the position of Accounts Payable Analyst, based in Leatherhead. Job Description Inputting vendor invoices into SAP, ensuring contractual compliance. Assisting with monthly payment performance reporting Maintaining scanned invoice archive in i-hub Running weekly and monthly payment performance reports Maintaining scanned invoice archive in i-hub Inputting of vendor invoices ensuring approved, allocated and paid in accordance with contractual terms onto SAP system and invoice register/tracking Follow SAP monthly reporting requirements Provide accounting information necessary to facilitate the formal closing out of contracts, service orders and other miscellaneous commitments Liaise with Cost Department and Maximo Administrator to ensure funds are available for invoice payment Liaise with Vendor representatives to resolve any invoice queries/ rejections that may arise Develop and maintain co-operative relationship with key contacts such as vendors, Verifiers/Approvers, BROs and user departments. Ensure notifications are forwarded to F&C, Baku advising of changes to vendor bank details. Liaise with Contracts team on all contractual matters. Filing invoices for scanning purposes Send remittance to vendors when requested Running Spends reports as and when requested Skills & Experience Considerable relevant experience of Accounts Payable functions Strong IT skills, in particular excel Good communicator - written and oral A team player SAP experience essential Strong interpersonal and organisational skills Team player with a positive attitude This is a contract position. The rate for this position is negotiable. If you feel that you are well suited to the above opportunity and would like to find out more then please contact Orion Group for more information or apply by forwarding your current CV quoting reference 86575. Orion Group currently supplies over 3,500 personnel in roles including Oil & Gas, Renewables, Power & Utilities, Construction, Mining, Rail, Aerospace, IT & Telecoms, Office and Commercial. With 29 offices worldwide, Orion Group operate in the UK and internationally and in January 2009, were named the UK's number one for engineering recruitment.

Negotiable

View the original article here

Senior Development Chemist (#981538569)

Experience in a similar role within either the nuclear or chemical industry

Position/Job Title: Lead Engineer Department: Engineering Design Discipline: Process Working Hours: 37.5 hrs/week: Mon-Thurs 08:25 - 16:50; Fri 08:25 15:45 Reporting to: Engineering Manager as line manager. Senior Engineer on project deliverables. Description of job purpose: The Lead Engineer is principally a hands-on design based role with a degree of team leadership within discipline. The Lead Engineer can be responsible for delivering a package of work within a project within their discipline. Frequent liaison with other disciplines in the design team and the client would be expected. Lead engineers are the main interface between senior management and hands-on design. Duties: Development of designs to satisfy technical specifications, primarily using AutoCAD and/or Inventor Checking of design calculations of designers and other engineers within the team Prepare supporting design calculations to substantiate design Actively contribute to design reviews, safety reviews (Risk Assessments and HAZOPs) from technical standpoint Preparation of technical specifications in liaison with client and project team Produce design documentation throughout the design process including scope of works, method statements, risk assessments, technical files and other technical documentation to comply with design standards, safety legislation/regulatory requirements and the needs of the client Preparation of installation, commissioning and operating documents Planning and allocation of workload to other members of design team within discipline in order to deliver package of work Management of sub-contractors providing niche services to the design Likely attributes to character: Systematic, methodical, exacting, quality driven Delivery focussed mindset when working to tight deadlines Team leadership: approachable, organised, collaborative, communicative Future possible progression: A typical path is to develop to Senior Engineer then Design Manager upon satisfactory experience, qualifications and client acceptance. Required Qualifications: Preferably degree qualified in a relevant technical / engineering discipline though not essential. Minimum HNC qualification or equivalent gained within a relevant discipline e.g. Chemical Engineering. A full UK drivers licence is essential for this position as travelling between offices may be required. Required Experience: Demonstrable competence gained in a design delivery position Experience in nuclear is essential. Technical experience could be gained from but is not limited to controlled atmospheres, chemical process plant, remote handling systems equipment, sewerage process, steam/pressure systems, cementation, pipes and pumps Fundamental understanding of process/chemical engineering principles and equipment is required Experience of leading teams within a project environment would be a distinct advantage

40k + Benefits

View the original article here

Petronas works on capability development, master’s program for drilling

Posted on 08 May 2012

http://www.drillingcontractor.org/wp-content/jw-flv-player/player.swf?file=http%3A%2F%2Fwww.drillingcontractor.org%2Fwp-content%2Fuploads%2F2012%2F05%2Fvideo-petronas-05042012.flv

Datuk George Ling Kien Sing, drilling division advisor for Petronas Carigali, sat down with DC publisher/editor Mike Killalea at the 2012 IADC Drilling HSE Asia Pacific Conference in Singapore on 25 April for an exclusive video to talk about how Petronas is working to accelerate capability development of its employees, an initiative to work with a university to develop a master’s degree program for drilling, and how IADC and its members in the Asia Pacific can collaborate with Petronas to share ideas and improve performance.

View the original article here

Chinese Operator Slashes 60% Off Development Cost with Mini-Beta One-Trip Multi-Zone Completion System

HOUSTON, TEXAS (June 26, 2000) – China's Bohai Oil Corporation cites Baker Oil Tools' Mini-Beta One-Trip Multi-Zone Completion System for helping slash completion time per well by up to 66% and total development cost by more than 60% in its JZ93 Bohai Bay field. The Mini-Beta system, which was used to complete 30 of 47 wells in the JZ93 Bohai Bay field, enabled the operator to individually frac pack or gravel pack four zones in as few as 2.4 days.

"Even with the relatively inexpensive costs in the Bohai Bay area, the use of the Mini-Beta One-Trip Multi-Zone Gravel Pack System resulted in saving more than $2.5 million US in rig time for the wells that were completed during this project," said Liang Yue Liu, Design Manager, for Bohai Oil. The savings figure was based on rig time valued at $40,000 per day. As a result of the success of this project, Bohai Oil awarded the completion of all 186 wells in its SZ36-2 Bohai Bay field to Baker Oil Tools. That contract is valued at $15 million.

Big rewards without sacrifice

The Mini-Beta System combines Baker's field proven CK-FRAQ crossover tool technology with one-trip multi-zone expertise to allow multiple producing intervals to be gravel- or fracpacked with a single trip into the wellbore. Each interval can be treated individually while maintaining complete zonal isolation during all steps of the treatment. In addition to multiple producing intervals, the system is particularly well suited for areas where the producing formation is layered and subsequently difficult to treat as one complete interval. These layered reservoirs can be short or extremely long. To work in these varying lengths, the Mini-Beta System is adjustable for interval spacing, including intervals as close together as 28 ft (8.5 m). As a result, layered reservoirs of any length can now be treated quickly and efficiently.

"All of these attributes offer users of the Mini-Beta System the opportunity to reap big savings in rig time and cost without having to sacrifice production time or quality," said Carroll Newman, Baker Oil Tools Product Line Manager for Stimulation and Pumping Services. Newman pointed out that one particular advantage of the system is the ability to optimize technology vessel logistics so that pumping operations on all zones can be completed without operation standby.

View the original article here

MPD makes the difference in offshore Indonesia offshore gas development program

By Linda Hsieh, managing editor, and Katherine Scott, editorial coordinator

An offshore well in Indonesia’s Ujung Pangkah field went from a potential failure to an invaluable success once managed

Clifford Lang (right), Hess, was among a panel session looking that examinedat the state of play of MPD and UBO technologies from the operator’s perspective at the 2012 MPD and UBO Conference and Exhibition on 21 March in Milan, Italy. The session was moderated by Dag Ove Molde (from left), Statoil, and included Claudio Molaschi, Eni, and Dave Elliott, Shell.

pressure drilling (MPD) was deployed, said Clifford Lang, drilling and completions manager of Europe, Eurasia and North Africa for Hess. “We surveyed the rig for MPD prior to getting on location … as a precaution,” he said during a presentation at the 2012 IADC/SPE MPD and UBO Conference and Exhibition on 21 March in Milan, Italy.

The first well in the gas-drilling program was completed without losses. However, on the second well, during the drilling of a sidetrack through carbonates in the reservoir section, “we hit the cave,” Mr Lang said. Losses totaling 96,000 bbl were experienced before the company began bullheading seawater with high-viscosity pills to push the gas back into place. The goal was to pull the pipe at least partly out of the hole. “We had to get out of the hole to get MPD in place,” he said.

A second gunk pill that was pumped down at 4,652-ft MD gave the team a chance to get out of the hole. Reduced hydrostatic pressure on top of the gunk pill allowed it to support the fluid above and allowed surface pressure to be bled off to zero.  A 9 5/8-in. drillable subsurface plug was set at 4,325-ft MD, and a cement plug was set on top to secure the well. “That took us 10 days of pain and losses,” Mr Lang said.

Once the team rigged up the MPD equipment and went back in with the drill string, the well reached TD and became Hess’ most productive on the field at 55 million standard cu ft/day. Mr Lang believes that surveying the rig for MPD in advance and having a contract in place with a service company was key to turning the well around when “we were staring at failure in the face.”

MPD has reduced the operational NPT associated with losses in the reservoir section to virtually zero, he added. Hess now makes sure that it has MPD equipment hooked up prior to seeing potential issues drilling through carbonates. Specifically on the Ujung Pangkah field, the company ended up deploying MPD twice out of the first six wells. “(MPD) enables us to do things we wouldn’t have been able to do. It will be used on all future wells and exploration wells in that area. Wherever we have carbonates we will be using this,” Mr Lang said.

Instead of fighting Mother Nature with LCM during loss situations, working with her natural pressure profile through the use of MPD techniques could save significant costs and time. “It will save you a fortune,” Mr Lang stated. “It’s safe, practical and it allows us to do so much more than we expected to do with these wells.”

Platinum sponsors for the 2012 SPE/IADC MPD & UBO Conference & Exhibition were Eni and Schlumberger; gold sponsor was Halliburton.

View the original article here

The essentials of dual-gradient drilling: Several variations under development

By Linda Hsieh, managing editor, and Katherine Scott, editorial coordinator

Although dual-gradient drilling has been around for years, many in the industry appear to remain unclear as to how the technology works or what it does. In a presentation at the 2012 IADC Dual Gradient Drilling Seminar on 19 March in Milan, Italy, AGR Subsea senior technology advisor Roger Sverre Stave reiterated IADC’s definition of dual-gradient drilling as a variation of managed pressure drilling that uses “two or more pressure gradients within selected sections to manage the well pressure profile.”

Roger Sverre Stave, AGR Subsea, noted that a significant industry focus on dual-gradient technologies has led the IADC Dual Gradient Subcommittee to take on many new initiatives, including organizing the 2012 IADC Dual Gradient Drilling Seminar on 19 March in Milan, Italy.

Whereas in conventional drilling, bottomhole pressure (BHP) is a function of single-gradient mud, dual-gradient methods make up BHP “based on multiple columns of fluid such that bottomhole pressure is a sum of two or more columns of fluid,” Mr Stave said.

“As long as the pore and frac pressures are increasing with depth, you will create a pressure gradient this is more compatible than pore pressure and frac pressure by introducing dual-gradient technologies,” he said. Effectively, dual-gradient drilling opens the “drilling window” by increasing margins. The technology also provides opportunities for faster recognition of instability, including loss and influx, as well as faster response to reestablish pressure balance.

Several variations of dual-gradient technology are under development within the industry, such as controlled annular mud level technologies and mudline pumping riserless technologies. Dual-gradient mudlift is another example, which is expected to be deployed by Chevron later this year in the deepwater Gulf of Mexico (GOM). Statoil too plans to deploy “light” versions of two variations of dual-gradient drilling in a pilot project in 2013, according to a separate presentation at the same seminar by John-Morten Godhavn, principal researcher for Statoil.

“And we have other technologies that create the dual-gradient effect by diluting and lightening the gradient in annulars of the drilling riser either by gas or fluid,” Mr Stave added.

Dual gradient goes back to as early as 1975 with the Howell patent and has been studied under various joint industry projects through the years, such as the MudLift JIP with ChevronTexaco, Conoco, BP and Hydril, and DeepVision with BP, ChevronTexaco, Transocean and Baker Hughes. “Shell SubSea Pumping system was also one major effort at the time with a seawater-filled riser but also having a separator system on the seafloor to pump out the solids and leave the cuttings behind on the seafloor,” Mr Stave said.

While only the MudLift JIP made it through to a successful field trial in 2001, Mr Stave notes that the need for dual gradient technologies has certainly not disappeared, particularly with the growing importance of the ultra-deepwater market in the GOM. “What I have seen is more industry focus along with various initiatives post-Macondo, but more related to safety now than previously when it was more focused on drilling efficiency,” he said.

Further, Mr Stave believes that ultra-deepwater leases and advanced drilling rigs may require dual-gradient drilling as an enabling technology going forward, meaning that it is impossible or very hard to drill those prospects without the dual-gradient drilling technique to manage the equivalent circulating density or dynamic friction loses. The technology allows the pressure gradient to fall more naturally within the pore and frac pressures of the well, he said.

Mr Stave acknowledged that dual-gradient technologies have been difficult to commercialize due to the investments required, as well as equipment integration issues. However, the concept remains on the agenda for many companies who are seeking to develop ultra-deepwater resources. “We are moving forward and we are making progress, but it takes a long time to implement these kinds of technologies.”

View the original article here