OGJ Newsletter

July 3, 2017
International news for oil and gas professionals


UA: Fracing, saltwater impact 'limited' on seismicity

Research from a University of Alberta geophysicist suggests hydraulic fracturing and saltwater disposal have limited impact on seismic events.

A team of researchers led by Mirko Van der Baan found no state- or province-wide correlation between increased hydrocarbon production and seismicity after reviewing 30-50 years of earthquake rates from US states North Dakota, Ohio, Pennsylvania, Texas, West Virginia, and Canadian provinces Alberta, British Columbia, and Saskatchewan.

They also discovered that human-induced seismicity is less likely in areas where fewer natural earthquakes occur.

The lone exception was Oklahoma, where seismicity rates have changed dramatically in the last 5 years, with strong correlation to saltwater disposal from increased hydrocarbon production.

"It's not as simple as saying 'we do a hydraulic fracturing treatment and therefore we are going to cause felt seismicity.' It's actually the opposite. Most of it is perfectly safe," said Van der Baan, who also is director of the Microseismicity Industry Consortium, a novel, applied-research geophysical initiative.

"What we need to know first is where seismicity is changing as it relates to hydraulic fracturing or saltwater disposal," continued Van der Baan. "The next question is why is it changing in some areas and not others? If we can understand why seismicity changes, then we can start thinking about mitigation strategies."

A next step will be continued monitoring. "Hydraulic fracturing is not going away," Van der Baan said. "The important thing is that we need to find the balance between the economic impact and environmental sustainability of any industry."

Santos sets relationship with Chinese shareholders

Santos Ltd. has established a strategic alliance with two of its shareholders-Chinese entities ENN Group and Hony Capital.

The relationship provides for the three companies to give each other preference to participate in future investments they make in gas and LNG in Australia and Papua New Guinea.

The deal was formalized in a letter from Santos Chairman Peter Coates to ENN founder Wang Yusuo and Hony Chief Executive John Zhao. It will involve ENN senior executive Eugene Shi coming on to the Santos board.

Together, ENN and Hony hold 15.1% of Santos. The alliance will continue as long as that shareholding remains at 15% or above.

Hony's association with Santos began in late 2015 when the private company appeared as a friendly party after the Santos board rejected a takeover attempt from Scepter Partners, a privately owned entity with links in Brunei.

ENN acquired its stake in Santos from Hony in March 2016. It has been seeking a board seat since late last year.

Last month Hony and ENN put pressure on Santos when they staged a "mini raid" that brought their combined shareholding up to the present 15.1%. The register sits at ENN with 10.31% of Santos and Hony 4.8%.

ENN sees the alliance as an effective link of Santos' upstream expertise with China's burgeoning downstream market for natural gas that will enable Santos to move to its full potential as a significant gas and LNG producer.

Santos maintains the relationship will see ENN and Hony supporting future investment Santos might consider and Santos, where appropriate for shareholders, will include ENN and Hony in investment opportunities that arise.

Likewise ENN and Hony will keep Santos abreast of any investment opportunities they are considering so that Santos can decide whether to join in.

CapeOmega ups interest in North Sea's Brynhild field

CapeOmega AS, Bergen, has agreed to buy 39% working interest in Brynhild oil field in PL148 of the Norwegian North Sea from Lundin Norway AS, a wholly owned subsidiary of Lundin Petroleum AB, for $91.5 million, including historic tax and uplift balances.

Following completion of the deal, CapeOmega will hold 49% interest and Lundin Norway will retain operatorship with 51% interest. The deal is effective Jan. 1 and subject to Norwegian government and Lundin Petroleum lender approvals.

Brynhild is a subsea tie-back to the Royal Dutch Shell PLC-operated Pierce field, 38 km to the south on the UK Continental Shelf. It lies in 3,300 m of water. First-quarter production averaged 2,200 boe/d.

Exploration & DevelopmentQuick Takes

Eni, KMG sign Kazakhstan exploration agreements

Eni SPA and JSC KazMunayGas (KMG) have agreed to renew Eni's 50% share of subsoil use rights for exploration and production on Isatay block in the Caspian Sea. The initial agreement was signed 3 years ago.

The new agreement entails the block will be operated by a joint operating company formed by Eni and KMG. The JOC will begin working as soon as the transfer of 50% interest in the license is completed, subject to the approval by Kazakhstan. Eni says the block "is estimated to have significant potential for hydrocarbon resources."

Eni and KMG subsidiary KazMunayGas EP (KMG EP) also have agreed to expand cooperation in upstream technology and evaluate potential joint developments in new projects. The agreement includes a technical and managerial training program for KMG EP staff.

Eni, KMG, the Ministry of Energy of the Republic of Kazakhstan, and the Kazakh Committee of Geology and Subsoil Use also have signed a memorandum of understanding to evaluate future cooperation in the Kazakh-Russian Pre-Caspian Basin where several oil fields have been discovered. The MOU is part of the energy ministry's Eurasia project to study the exploration potential of the basin.

Eni in Kazakhstan is joint operator of Karachaganak field and is an equity partner in several projects in the northern Caspian Sea, including the giant Kashagan field.

Barossa appraisal bodes well for Darwin LNG supply

A ConocoPhillips-led combine reported a successful appraisal well in Barossa natural gas field in Bonaparte basin retention lease NT/RL5 in the eastern Timor Sea, 300 km north of Darwin. The results enhance the field's prospects as the best source to supply back-fill gas to the combine's Darwin LNG plant that is now supplied by Bayu-Undan field in the Timor Gap.

Well logs and pressure data from the Barossa-5 and Barossa-6 wells confirmed that the primary Elang reservoir is gas-saturated. The reservoir zone also is in communication with previous wells drilled in the field.

This information justified production testing to confirm reservoir productivity and to obtain dynamic data to incorporate into plans for field development.

The group chose Barossa-6 for the test because the reservoir interval there is similar to the high-quality reservoir with 104 m of net pay penetrated in the offset Barossa-3 well drilled in 2014 about 4.3 km east.

Barossa-6 flowed gas and condensate from the interval 4,103-4,144 m at a maximum rate of 65 MMcfd on a 68/64-in. choke. Condensate content was measured at the surface as 7 bbl/MMcf.

The combine said gas composition analysis showed that the percentage of inert gasses was "as expected." Previous wells have recorded as much as 16% carbon dioxide in the field.

The Barossa-6 flow rate was constrained by test facilities and multiple samples were taken for further analysis.

All data will now be integrated into subsurface models to support a front-end engineering and design entry decision early next year.

Barossa field was discovered in November 2006 in 320 m of water. The first appraisal program-Barossa-2, 3, and 4-was completed during first-half 2015.

The Barossa discovery was predated by a smaller discovery about 20 km southwest at Caldita in 150 m of water during September 2005. Caldita-2 was drilled in 2007. That field is now held in retention lease NT/RL6.

A development plan, always referred to as Barossa-Caldita, will link the two discoveries.

Interest holders are operator ConocoPhillips with 37.5%, South Korean combine SK E&S also with 37.5%, and Adelaide company Santos Ltd. with 25%.

ConocoPhillips and Santos are also interest holders in the Darwin LNG plant.

Beach Energy completes Callawonga drilling campaign

The Adelaide duo of Beach Energy Ltd. and Cooper Energy Ltd. has completed a five-well campaign in Callawonga oil field in PPL220 in the South Australian Cooper-Eromanga basins.

The final appraisal well in the current program, Callawonga-17, was cased and suspended as a future oil producer after being drilled to 1,452 m TD. Its primary target, the McKinlay Member sandstone, was encountered 2.7-m high to prognosis.

The well drilled through a 2.6-m gross thickness in this reservoir with an interpreted 1 m of net oil pay in clean sand. A further 1.8 m of net oil pay was encountered in the underlying Namur sandstone.

The aim of the five-well program was to examine the potential of the McKinlay Member that the partners considered to be underexplored. The results have been much better than anticipated, with all five wells finding oil. These results will lead to an upgrade in reserves estimates for the Callawonga field and the data will be incorporated into plans for future development of the McKinlay Member.

Gazprom Neft starts exploration on Ayashsky block

Gazprom Neft PJSC reported the start of exploratory drilling on the Ayashsky block in the Sea of Okhotsk by Japan Drilling Co. Ltd.'s Hakuryu-5 semisubmersible drilling rig.

Drilling, core sampling, geophysical investigations, and testing at target intervals are to be completed by Gazpromneft-Sakhalin during this year's ice-free season. Results will lead to development of preparations for test drilling during next year's ice-free season.

The company said all waste drilling mud, sludge, and cuttings will be shipped onshore for recycling.

The Ayashsky block is part of the Sakhalin III project and is next to developed fields of the Sakhalin I and Sakhalin II projects.

Drilling & ProductionQuick Takes

MEI: US shale oil output to hit 9 million b/d by 2025

Under a price-recovery scenario that assumes West Texas Intermediate oil prices will hit $60-70/bbl from 2019 onwards, shale drilling and completions will increase at 20%/year and production will increase at 12%/year through 2021, according to the newly released North American Shale Oil Outlook by McKinsey Energy Insights (MEI), an energy data and analytics specialist.

Meanwhile, US shale oil production is estimated to reach 9 million b/d by 2025, but this could vary by 5.4 million b/d depending on oil price scenarios.

According to MEI, although North American shale oil margins have struggled to bounce back after the market plummeted in 2014, drilling activity since second-quarter 2016 has more than doubled. The report highlights that recent key operational improvements-such as increased drilling efficiency, better completion designs, and high-grading-will help margins widen and enable drilling to become profitable beyond the most resource-rich basins.

MEI found that operators have reduced drilling time by an average of 5 days while improving initial production (IP) by 33% from 2014 to 2016. Wells with better completion designs-like high-proppant-volume wells-have experienced 35% higher IP than average, but these gains are subject to additional costs because of water and sand sourcing.

MEI forecasts that the number of wells completed will rise at 21%/year until 2021, requiring total capital expenditures to increase 25% each year to reach 2014 spending levels.

MEI expects the Permian basin to be the primary shale oil area to watch over the next 10 years due to its resource quality and size, proximity to markets, and existing infrastructure. The Permian's average core breakeven price for 2017 is less than $41/bbl. Low breakeven is enabling the Permian to remain profitable despite well cost increases of 30%.

The Permian's IP growth rate for the past 5 years was 20% compared with Eagle Ford and Bakken, at 2%, and the Permian has more remaining drilling locations as it is still in the early development stage.

From 2016 to 2021, MEI projects that 47% of growth in rig activity will come from the region with remaining activity similarly spread across the other major basins.

Kraken heavy oil goes onstream in UK North Sea

EnQuest PLC confirmed Kraken heavy oil field went on stream on June 23, saying seven production wells and six injection wells have been completed. Those production wells will be brought online in phases.

Production was delivered on schedule and under budget, executives said. The UK North Sea field is 125 km east of the Shetland Islands.

EnQuest said it is shifting its focus from heavy capital investment to cash generation. EnQuest has a 70.5% interest in Kraken. Cairn Energy PLC owns the rest.

Kevin Swann, Wood Mackenzie Ltd. research analyst, called Kraken production "a welcome boost for the UK oil and gas industry." He said, "Although other heavy oil fields have produced in the UK, this is the first of a batch of projects that were discovered some time ago but were previously deemed too challenging technically to develop."

WoodMac estimates Kraken production will average 20,000 b/d for the year, Swann said, which would account for 15% of year-on-year production growth in the UK in 2017.

WoodMac expects production will peak at almost 50,000 b/d in 2019, providing 4.5% of overall UK liquids production that year.

Repsol Sinopec starts Cayley production in North Sea

Repsol Sinopec Resources UK Ltd., Aberdeen, has started gas production from Cayley field, the third and final discovery to be brought on stream during the major redevelopment of the Montrose area in the central North Sea.

Gross incremental production from Cayley, Godwin, and Shaw fields is expected to peak at 40,000 boe/d, extending the life of the Montrose facilities, installed in 1976, to beyond 2030. Production from Shaw field began last month (OGJ Online, May 9, 2017).

The Montrose area redevelopment project incorporates a new bridge-linked production platform connected to the Montrose Alpha platform to provide additional process and plant support facilities.

Godwin field has already been developed via an extended reach well from the Arbroath platform. Cayley and Shaw fields have been developed as subsea tie-backs to the BLP. The project overall is expected to provide up to 100 million boe of additional production, including life extension of legacy fields.


Braskem selects La Porte for Delta PP project

Braskem America Inc., Philadelphia, a subsidiary of Braskem SA, Sao Paulo, is investing $675 million to build what will become North America's largest polypropylene (PP) production line at the company's existing manufacturing site in La Porte, Tex., about 26 miles outside of Houston.

Approved by the company's board as of June 22, the PP unit will add another 450,000 tonnes/year of production capacity for homopolymers, random copolymers, impact copolymers, and reactor thermoplastic polyolefins to the La Porte plant's current PP production capacity of 354,000 tpy, Braskem said.

The Delta production line comes as part of Braskem's global growth strategy to help meet rising demand from customers both in the Americas and abroad by leveraging access to low-cost sources of feedstock from North American shale production as well as existing support infrastructure already in place to accommodate the expansion, the operator said.

With project engineering design already well under way and construction scheduled to begin by midsummer, Braskem said it expects to reach mechanical completion of the PP unit during first-quarter 2020.

Once completed, the Delta project will boost Braskem's total US PP production capacity to 2.02 million tpy from a current output of 1.57 million tpy.

Braskem's announcement of the planned PP expansion follows the late-2016 commissioning and early 2017 full startup of the company's UTEC ultrahigh-molecular weight polyethylene production plant at the same La Porte site.

Pemex plans late July restart of Salina Cruz refinery

Pemex Transformacion Industrial (PTI), the processing arm of Mexico's state-owned Petroleos Mexicanos SA, is working to restart its 330,000-b/d Antonio Dovali Jaime refinery in Salina Cruz, Oaxaca, by the end of July following the plant's complete shutdown in the wake of a June fire caused by flooding from Tropical Storm Calvin.

Alongside beginning cleanup and repairs in areas of the manufacturing site impacted by the fire, PTI also is now installing pumps to expedite delivery of crude feedstock to portions of the refinery not affected by the June 14 incident, Pemex said.

The pumps should allow PTI to restart pumping crude oil to these unaffected areas of the refinery before cleaning and repair works are completed, the operator said.

In addition to carrying out cleaning, rehabilitation, and repair works aimed specifically at resuming operations at the refinery, PTI has decided to use the current shutdown period to bring forward routine scheduled maintenance originally planned for April 2018.

Pemex-which also has completed a root-cause analysis investigation of the June fire-said it expects the Salina Cruz refinery to resume full operations on July 30.

The company reiterated that measures remain in place to guarantee timely fuel supplies to regional customers during the ongoing shutdown period.

The June 14 fire occurred following Pemex's coordinated suspension of processing activities at the Salina Cruz refinery after torrential rains from Tropical Storm Calvin caused flooding in several areas of the refinery, Pemex said.

Rising floodwaters in the containment dam of a crude oil storage tank resulted in an oil spill that subsequently ignited, sparking a fire in the containment dam that later spread to the refinery's pump room.

The fire-which Pemex firefighters fully extinguished on June 16-led to one fatality and several injuries.

Dangote lets another contract for Lekki refinery

Nigerian conglomerate Dangote Industries Ltd. (DIL) has let a contract to Air Liquide Engineering & Construction, a division of Air Liquide SA, Paris, to provide hydrogen production technology for subsidiary Dangote Oil Refining Co.'s (DORC) 650,000-b/d grassroots integrated refining complex now under construction in southwestern Nigeria's Lekki Free Trade Zone.

Air Liquide E&C will supply two hydrogen production steam methane reformer (SMR) units for a hydrogen-generation complex that will produce 200,000 normal cu m/hr of hydrogen and high-quality steam for the DORC refinery, the service company said.

This latest equipment contract for the SMR package follows a previous contract DIL awarded to Air Liquide in 2015 for related technology licensing and process design on the Lekki project, Air Liquide E&C said.

Slated for completion during fourth-quarter 2019, DIL's now $12-billion Lekki integrated complex will include a 650,000-b/d crude distillation unit, a 3.6 million-tonne/year polypropylene plant, a fertilizer plant, and a subsea pipeline project


APA Group plans Australian grid pipeline expansion

Sydney-based APA Group is to build a gas pipeline as part of an expansion to its east coast gas grid following the signing of a memorandum of understanding with Brisbane company Blue Energy Ltd.

The pipeline is part of a negotiation with Blue Energy to connect its Bowen basin coal seam gas province reserves in central eastern Queensland to the southern manufacturing and residential demand centres.

The pipeline link will enable gas resources to be supplied and traded between Townsville in Queensland down to Hobart in Tasmania using APA's east coast grid.

Blue Energy also is engaged with several parties interested in purchasing its Bowen gas, including existing users and new entrants. The volumes sought range from 2-3 petajoules/year to volumes that enable development of Blue Energy's entire resource base now estimated at 300 petajoules of 3P reserves.

Eni lets subsea contract for Coral South FLNG

Eni East Africa SPA has let a contract to GE Oil & Gas for the supply of subsea production systems, ancillary equipment, and services for the Coral South floating LNG (FLNG) project in Area 4 offshore Mozambique. The agreement also covers future potential upstream projects on Area 4.

GE Oil & Gas will provide seven Christmas trees, three 2-slot manifolds with integrated distribution units, MB rigid jumpers, seven subsea wellheads with spare components, a complete topside control system to be installed on the FLNG facility, and associated services equipment and support including intervention workover control systems and landing strings, tools, spares, and technical assistance for installation, commissioning, and startup.

Eni also recently signed drilling, construction, and installation contracts for the project with JGC Corp., TechnipFMC PLC, and Samsung Heavy Industries Co. Ltd.

Coral South FLNG is the first phase of Eni's wider plan of development for Rovuma basin Area 4. It includes the installation of a 3.4 million-tonne/year FLNG facility fed by six subsea wells and is expected to produce as much as 5 tcf of gas. Expected startup is in mid-2022.