XTO expands methane emissions reduction program
ExxonMobil Corp. subsidiary XTO Energy Inc. is implementing a program to further reduce methane emissions from its US production and midstream operations.
The program prioritizes actions at XTO-operated sites and includes efforts to develop and deploy new, more efficient technologies to detect and reduce facility emissions, ExxonMobil said on Sept. 25.
"We are implementing an enhanced leak detection and repair program across our production and midstream sites to continually reduce methane emissions and are also evaluating opportunities to upgrade facilities and improve efficiency at both current and future sites," said XTO Pres. Sara Ortwein.
The initiative will be underscored by a technology research and testing effort and will include personnel training, phasing out of high-bleed pneumatic devices over 3 years, and facility design improvements for new operations, Ortwein said.
The announcement follows XTO's recently completed pilot project in the Midland basin that tested new low-emission designs using compressed air instead of natural gas to operate pneumatic equipment that helps regulate conditions such as level, flow, pressure, and temperature. Results of the pilot test demonstrated the feasibility of using similar designs for new and existing central tank batteries and satellites to help reduce the potential for methane emissions, the company said.
This latest project joins XTO's other efforts at methane emissions reduction and monitoring, including a portfolio of more than two dozen existing methane research projects, studies, and pilots under way involving joint development of more efficient equipment to detect, quantify, and reduce emissions at production sites and midstream, ExxonMobil said.
Statoil achieves carbon dioxide reduction targets
Statoil ASA says it has achieved targets for reducing carbon dioxide emissions from the Norwegian Continental Shelf and is seeking additional efficiencies.
The company said petroleum industry energy efficiency targets were set in 2008. Statoil met an initial reduction target of 800,000 tonnes in 2015, 4 years ahead of schedule. It raised the reduction target to 1.2 million tonnes by 2020 and has met that target.
Arne Sigve Nylund, a Statoil executive vice-president, said, "We did not know how to achieve the targets set in 2008, but we did get there. And the emission reductions have been both quicker and bigger than we defined as our original ambition."
In the past 9 years, Statoil has implemented 228 energy improvement measures. Its initiatives include improved operation of gas turbines, gas compressors, pumping installations, reduction of gas to flare, and smarter fuel consumption for mobile rigs offshore.
Since 2007, Statoil has reduced emissions from gas to flare by 140,000 tonnes of CO2.
By using gravity pressure from the sea instead of a water injection pump in Kristin field, Statoil has reduced CO2 emissions by 7,375 tonnes/year. Also at Kristin, the company installed a check valve to reduce pressure drop in the inlet manifold, reducing CO2 emissions by 10,000 tpy.
Statoil's Norwegian offshore activities emitted 9 million tonnes of CO2 in 2016. Statoil-operated installations on NCS have an average CO2 intensity of 9 kg/bbl of produced oil.
Under the direction of the Norwegian Oil & Gas Association, the petroleum industry in August 2016 set carbon reduction measures equivalent to 2.5 million tonnes on the NCS by 2030 vs. 2020. Statoil's share of the 2030 target is 2 million tonnes.
The company said it pays almost 4 billion kroner/year in carbon tax.
DOE announces funding for carbon capture projects
The US Department of Energy took a pair of steps to advance carbon capture technologies over several days. DOE Sec. Rick Perry announced $36 million in funding on Sept. 22 to support cost-shared projects research and development to continue development to either the engineering scale or a commercial design. He then reportedly asked the National Petroleum Council 3 days later to help find more ways to use captured carbon in enhanced oil recovery.
In its Sept. 22 funding opportunity announcement (FOA), DOE said that selected projects would fall under two areas of interest:
• Up to four awards, with combined DOE funding of as much as $30 million, for scaling of carbon capture technologies to engineering scales using existing host site systems.
• Up to two awards, with combined DOE funding of as much as $6 million for initial engineering, testing, and design for a commercial-scale, post-combustion carbon dioxide capture system.
"Carbon capture technologies are one of the most effective ways we can continue to leverage the sustainability of our nation's fossil fuel resources while advancing environmental stewardship," Perry said.
The projects will undertake engineering-scale testing of transformational solvent-or membrane-based CO2-capture technologies and will conduct design work for a commercial-scale, post-combustion CO2-capture system at an existing coal-fueled generating unit, according to DOE's Fossil Energy Office.
Reuters reported that at the Sept. 25 NPC meeting Perry said he wanted to hear from the oil industry on how to deploy the technology more widely and to provide policy and research and development recommendations.
Mizton-2 well lifts Mexico's Area 1 resource potential
Eni SPA has increased the estimated resource in place for Mexico's Contractual Area 1 to 1.4 billion boe after its Mizton-2 well in Campeche Bay encountered 185 m of net oil pay in the Orca formation.
The well, 200 km west of Ciudad del Carmen, was drilled to a final depth of 3,430 m in 33 m of water. The firm reported excellent quality sandstone reservoirs.
Well data indicate a single 280-m thick oil column, and oil gravity is estimated at 28-30°. Mizton-2 is 10 km from the firm's Amoca discovery reported in June.
Extensive borehole data acquisition along with a fluid and rock sampling campaign were carried out. The well will now be temporarily suspended. Eni's exploration campaign will continue with the drilling of a well on the Tecoalli discovery.
Eni holds 100% interest in Contractual Area 1. Development of Mizton field, which is now estimated to hold 350 million boe in place, will be included in the Area 1 development plan.
Eni also is preparing a development plan for Phase 1 of Amoca field, which will be submitted to Mexico's Comision Nacional de Hidrocarburos (CNH). Start-up there is expected in early 2019.
Separately, Eni signed exploration and production licenses for Blocks 7, 10, and 14 in Mexico's Sureste basin following their award in first-phase Round 2 bidding.
Eni will operate Block 7 with 45% interest alongside partners Cairn Energy PLC with 30% and Citla Energy SAPI de CV 25%; Eni will hold 100% interest in Block 10; and Eni will operate Block 14 with 60% interest alongside partner Citla with 40%.
Logs confirm Xanadu discovery in north Perth basin
Wireline logs have confirmed an oil discovery at the Norwest Energy Ltd. group's Xanadu-1 wildcat in inshore permit TP/15 in the north Perth basin offshore Western Australia.
The company said today that logs over a 330-m section confirmed reservoir quality sand intervals throughout the Irwin River Coal Measures with porosities of 15-16%.
Three discreet sand intervals at the top of this formation have log-derived hydrocarbon saturations of 41-66% with a 4.6-m net pay in the top sand.
Fluorescence in rock cuttings seen during the drilling program and log-derived hydrocarbon saturations persist for 120-m in sands below the three upper zones.
Assay results from oil samples obtained from Xanadu-1 are expected by the end of the week.
Plans are now under way for an up-dip sidetrack appraisal from the Xanadu-1 casing shoe. Norwest said that the first well in the Cliff Head oil field discovery further offshore identified a 4.8-m oil column at the top of the Irwin River Coal Measures-the same stratigraphy encountered in Xanadu-1. Cliff Head was then sidetracked to a more favourable up-dip location an intersected a 36-m gross oil column.
The company believes that a similar side track from Xanadu-1 is a good option. The joint venture is investigating the idea of acquiring more seismic data with a mini-survey of short infill lines over the Xanadu discovery prior to the drilling of Xanadu-2.
The discovery well was drilled as a directional well from an onshore coastal location into the offshore Xanadu structure.
Norwest has 25%, with Triangle (Global) Energy Ltd. and 3C IC Ltd. each having 30% and Whitebark Energy Ltd. 15%.
Sri Lanka develops strategic plan for oil and gas
Sri Lanka plans to move forward with a strategic oil and gas exploration and development plan.
The Petroleum Resources Development Secretariat listed several elements of the plan, including continuation of a joint study with France's Total SA of Blocks JS5 and JS6 off the east coast. It also seeks to commercialize natural gas discoveries made on Block M2 of the Mannar basin offshore western Sri Lanka.
A third element is acquisition, marketing, and licensing of 2D and 3D seismic and gravity magnetic data in several offshore locations in three sedimentary basins: Mannar, Cauvery, and Lanka.
PRDS also seeks exploration in the Cauvery basin on production sharing contractual terms, and wants to formulate a natural gas policy that would include export potential.
It foresees "massive long-term fiscal benefits" from the state's share of production-sharing contracts, with estimates of 40-50% of total project profit. That amount would be derived from royalty, tax payments, profit share allocations, national equity participation, bonus payments, levies, and other fees.
Sri Lanka's effort will be directed by Arjuna Ranatunga, the new minister of Petroleum Resources Development.
SDX starts Morocco drilling, updates Egypt operations
SDX Energy Inc. seeks to increase its Moroccan gas sales volumes by as much as 50% and its reserves by more than 100% with its nine-well drilling campaign in the Sebou, Gharb Centre, and Lall Mimouna permits.
The operator spudded the KSR-14 development well, the first in its campaign, in the Sebou permit onshore northeast Morocco. SDX expects to announce drilling results in mid-October. If successful, the company plans to complete, flow test, and connect to existing systems in 30 days. Paul Welch, president of SDX, said this was the company's first well in Morocco. Welch also commented on the company's progress in the Nile Delta's South Disouq concession in Egypt. The company plans to drill the Kelvin-1X and Bragg-1X exploration wells.
In June, SDX's partner IDR Inc., with 45% working interest, reported the discovery of the Phase I commitment well, SD-1X, tested 25.8 MMcfd and 43 bbl of condensate on a 48/64-in. choke. The gas-condensate discovery was in the Abu Maadi formation at 7,100 ft.
Drilling & Production — Quick TakesBP Oman brings Khazzan gas field on stream
BP Oman said production has started from Phase 1 of Khazzan field in the Oman desert 350 km south of Muscat. BP, the operator, expects to drill about 300 wells during the field's life. Combined production from Phases 1 and 2 is expected to be 1.5 bcfd.
BP has 60% interest. Partner Oman Oil Co. Exploration & Production holds 40%.
Liam Yates, Wood Mackenzie Ltd. analyst for the Middle East and North Africa upstream, said Khazzan Phase 1 is expected to supply 25% of Oman's gas by 2019.
Oman's gas production likely will increase by 25% during 2016-19, Yates said. He also expects Khazzan to support incremental liquified natural gas exports of 1.5 tonnes/year.
Longer term, Khazzan will help replace declining Oman production, particularly from Petroleum Development Oman, which currently produces more than 90% of Oman's gas.
Yates said Phase 1 is expected to cost $12 billion, a 25% reduction from the original development plan. Phase 2 of BP's Block 61 project is expected to start up by 2020.
TEN development drilling off Ghana to restart
In the aftermath of resolution of a maritime boundary dispute between Ghana and Ivory Coast, Tullow Oil PLC said it will work with Ghana on permits to restart development drilling in the offshore TEN fields. The company expects to resume drilling around the end of the year.
The Special Chamber of the International Tribunal of the Law of the Sea (ITLOS) in Hamburg, Germany, made its decision on Sept. 23.
Tullow said the new maritime boundary as determined by the tribunal does not affect the TEN fields, Tweneboa, Enyenra, and Ntomme, which began production in 2016.
"While the TEN fields have performed well during the period of the drilling moratorium, we can now restart work on the additional drilling planned as part of the TEN fields' plan of development and take the fields towards their full potential," said Paul McDade, Tullow chief executive officer.
Gazprom Neft starts production from Otdelnoye field
Gazprom Neft PJSC said it has brought Otdelnoye field in Russia into commercial production, with two wells producing a total of 170 tonnes/day of oil.
More than 20 wells are to be drilled in the field in 2017-18, including 13 horizontal wells.
The field is in northern part of the Surgut district in the Khanty-Mansiysk autonomous okrug.
Gazpromneft-Noyabrskneftegaz secured subsoil usage rights following an auction in 2014.
Chaparral, Bayou City launch STACK drilling venture
Drilling has commenced on the first well in a new STACK joint venture between Oklahoma City operator Chaparral Energy Inc. and Houston private equity firm Bayou City Energy (BCE).
The joint development agreement, which involves those firms' respective affiliates, Chaparral Energy LLC and BCE Roadrunner LLC, will fund development of Chaparral's 110,000-acre STACK position in Oklahoma.
Under the JDA, BCE will fund all drilling, completion, and equipping costs for 30 STACK wells as part of a first tranche, with Chaparral drilling and operating 17 wells in Canadian County and 13 in Garfield County. The tranche, subject to average well cost caps that vary by well-type across location and targeted formations, will have a maximum capital commitment of $100 million. The JV could be expanded to additional tranches in the future.
In exchange for funding, BCE will receive wellbore-only interest in each well totaling 85% working interest until the program reaches a 14% internal rate of return. Once the IRR is ready, ownership interest in all wells will revert such that Chaparral will own 75% working interest and BCE will retain 25% working interest of Chaparral's leasehold interest in each well.
Chaparral will retain all acreage and reserves outside of the wellbore, with both parties paying lease operating expenses based on relative ownership interests.
PROCESSING — Quick TakesTall Oaks plans STACK gas gathering, processing system
Tall Oak Midstream LLC, Edmond, Okla., plans to build a natural gas-gathering system spanning southeast Oklahoma's Hughes County and portions of Seminole, Pontotoc, Coal, Pittsburg, Atoka, and McIntosh counties to serve producers' development of multiple stacked pay zones of the state's East STACK play, including the Woodford, Caney, and Mayes formations.
Scheduled for startup by yearend, subsidiary Tall Oak III LLC's East STACK system initially will include more than 50 miles of 12-20-in. pipeline, two compression facilities, a 5,000-b/d stabilizer, an associated slug catcher, and condensate storage, according to Tall Oak.
The company also said discussions are under way with area producers to determine the best size and strategic location for a proposed cryogenic natural gas processing plant to be added to the system sometime in the future.
"The East STACK is an exciting play that lacks the infrastructure required to handle the emerging growth in production from rich, horizontal gas wells," said Carlos Evans, chief commercial officer of the Tall Oak companies.
The new system comes as part of the company's strategy to develop infrastructure required to stay ahead of its customers' immediate and long-term needs, according to Evans.
Announcement of the new East STACK system comes just 2 months after the formation of Tall Oak III, which is backed by an initial equity commitment of up to $200 million from EnCap Flatrock Midstream and the Tall Oak III management team.
Tall Oak, which sold subsidiary Tall Oak Midstream I LLC to the EnLink Midstream companies in January 2016, said Tall Oak Midstream II LLC will continue focusing on operating and expanding its midstream assets in the Northwest STACK play.
Petrojam refinery revamp in Jamaica placed on hold
Jamaica's Prime Minister Andrew Holness reported that the planned expansion and overhaul of the Petrojam Ltd. joint venture's 36,000-b/d hydroskimming refinery in Kingston has been placed on hold because of the continued political unrest in Venezuela.
The governments of Venezuela and Jamaica earlier this year finalized an agreement to undertake the long-planned expansion and modernization of the joint Petrojam project.
"The refinery upgrade has been on the table for a long time and since the escalation of events in Venezuela nothing has changed-in other words, we are no closer to a refinery upgrade," Holness said.
The expansion would increase the refinery's processing capacity to 50,000 b/d as well as add units for vacuum distillation, delayed coking, and diesel desulfurization.
The upgrade work was expected to total $1 billion with both the Jamaican and Venezuelan governments splitting the cost.
Kuwait group lets contract for paraxylene unit
Kuwait Paraxylene Production Co. (KPPC) has let a contract to Honeywell International Inc. subsidiary Honeywell UOP LLC, Des Plaines, Ill., to provide a suite of cloud-based technology and interactive support services aimed at improving productivity, efficiency, and profitability of operations at the Shuaiba petrochemical complex in Safat, Kuwait.
KPPC will implement two of Honeywell's proprietary Connected Plant services, including the Process Reliability Advisor (PRA) and Process Optimization Advisor (POA), to ensure optimal performance of its continuous catalytic reforming (CCR) platforming and aromatics complex at Shuaiba, which produces 780,000 tonnes/year of paraxylene for plastic fibers and films, Honeywell UOP said.
Using big-data analytics and machine learning, both PRA and POA will integrate KPPC's specific plant data with UOP's history of operating experience to identify real-time operational adjustments that will enable the complex to run more reliably and at maximum efficiency.
Leveraging Honeywell UOP's process and fault models configured to each operation, PRA is designed to detect problems that could hamper production, providing the operator an opportunity to take corrective action to prevent unplanned downtime, while POA provides recommendations based on continuous monitoring of real-time, plant-specific information-including actual operating constraints and economics-that can be used to improve overall plant profitability.
The service provider disclosed neither a value of the contract nor a timeframe for its scope of work on the contract.
A wholly owned subsidiary of Kuwait Aromatics Co.-a joint venture of Kuwait Petroleum Corp. subsidiary Petrochemical Industries Co. (PIC), Kuwait National Petroleum Co., and Qurain Petrochemical Industries Co. (QPIC)-KPPC is operated by Equate Petrochemical Co., itself a JV of PIC 42.5%, Dow Chemical Co. 42.5%, Boubyan Petrochemical Co. 9%, and QPIC 6%.
As PIC's aromatics unit, KPPC also produces 370,000 tpy of benzene used locally by fellow Equate-operated Kuwait Styrene Co. to produce 450,000 tpy of styrene monomer, according to Equate's web site.
TRANSPORTATION — Quick TakesGazprom Neft notes shipments of Badra oil to the US
Gazprom Neft PJSC said a shipment of 1.78 million bbl of oil is being exported from Badra field in eastern Iraq to the US in the New Solution crude oil tanker.
It's the second oil consignment to the American market by Gazprom Neft Badra, operator of Badra field.
Twelve preceding shipments were for European companies and refineries in the Asia-Pacific region. Gazprom Neft said exports from Iraq are delivered by the State Oil Marketing Co.
MPLX to proceed with Wood River-to-Patoka expansion
MPLX LP subsidiary Marathon Pipe Line LLC will move forward with its planned 130,000-b/d expansion of the Wood River-to-Patoka crude oil pipeline after completing a binding open season on Aug. 31.
The expansion will allow for additional crude to be moved from the US Midcontinent to the US Midwest. The pipeline stretches from Wood River, Ill., to Patoka, Ill., a large hub for crude storage and distribution.
The project will lift capacity to 345,000 b/d by increasing horsepower and adding drag-reducing agents. The expansion is expected to begin service in second-quarter 2018.
