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ENI Opens the Tap in Egypt’s Baltim South West

Italian explorer ENI has started up production of the offshore Baltim South West gas field in Egypt.

It is another fast discovery to market by the aggressive operator.

ENI discovered the field in June 2016 and took Final Investment Decision (FID) in January 2018. Baltim South West thus comes on stream 39 months after discovery and 19 months after FID.

The field is located in shallow waters 12 kilometres off the Mediterranean coast of Egypt in the Baltim South development lease. It lies within the Great Nooros area, some 10km from the Nooros field, an area in which ENI says it “first recognised great gas production potential and where it is conducting other new exploration projects”.

With the start-up of the first well, BSW1, the field is now producing with an initial rate of 100 million standard cubic feet per day (scf/d) from a new offshore platform connected to the existing onshore Abu Madi Gas Plant through a new 44 km long, 26 inch diameter pipeline.

The development programme anticipates the drilling of further five wells with the objective of achieving a production target of 500Million scf/d by the second quarter of 2020. Volumes produced by Baltim South West will further contribute to Egypt’s natural gas export capacity. The overall gas potential from the Great Nooros Area is approximately 3Trillion cubic feet (Tcf) of gas in place, of which about 2Tcf are in the Nooros field and the remainder in Baltim South West.

ENI has a 50% interest, through its subsidiary IEOC, while BP holds the remaining 50% interest of the contractor’s stake in the Baltim South development lease. The project is executed by Petrobel, the Operating Company jointly held by Eni and the state corporation Egyptian General Petroleum Corporation (EGPC) on behalf of Medgas, jointly held by contractor (ENI and BP) and EGPC.

 

 


Sylva in Petroleum: Four Years of More of the Same

An Editorial Opinion of the Board of Africa Oil+Gas Report

It is unlikely that Timipre Sylva, a career Nigerian politician more likely keen on dealmaking than overseeing reforms, will follow up on the hot button issues of value addition in Nigeria’s Hydrocarbon landscape.

The passage of the Petroleum Industry Bill, the sale of a slice of NNPC equity in upstream JVs, disposal of state owned infrastructure that the corporation is unable to properly run, the removal of gasoline subsidies: these value yielding initiatives will not likely be delivered in the next four years.

Sylva’s predecessor as Nigeria’s Minister of State for Petroleum, Ibe Kachikwu, took a stab at some things, but he didn’t get very far. He succeeded in pushing the payment of cash call arrears for JV operators, got the President to sign off on policy to licence gas flare sites and launched a policy document each on oil and gas.

But in the absence of an act of parliament reforming extant hydrocarbon laws and operational norms, with those policies at its heart, Mr. Kachikwu’s documents have gone nowhere.  Those policy documents suffered the same fate as Mrs. Diezani Allison Madueke’s Gas Revolution Policy and President Olusegun Obasanjo’s Oil and Gas Reform initiatives.

At the core of the current challenges are two things (1) President Muhammadu Buhari’s statist mindset and his disdain for the Nigerian business class (2), the President’s unwillingness to closely track the ministry’s work, which provides undue advantage to personal aides, especially his chief of staff, Mr. Abba Kyari, to hijack the ministry of petroleum resources and run an upstream lease management agenda focused on handling assets to the NPDC rather than supporting transparent bid processes.

NNPC will remain as powerful and unaccountable as it was in the last four years; a commercial entity pretending to be regulator. NPDC, its operating subsidiary, will pay neither rent nor royalty for acreages it acquires and the state hydrocarbon company will continue spending billions of dollars to refurbish  moribund refineries that otherwise should be privatised –which translates to frittering away what should otherwise flow into the treasury, for the next four years.

We, at Africa Oil+Gas Report would be enormously encouraged if Mr. Sylva could be both courageous and tactful enough to cut through the fog and convince the President to provide an environment for the flourish of investment into what is potentially Africa’s largest hydrocarbon industry. But from where we are sitting, we don’t see that happening.

 


Mixed Signals from Tanzania’s Domestic Natural Gas Market

By Sully Manope, East Africa Correspondent

Indonesian owned, Paris listed operator, M&P, reported a sizeable drop in natural gas production in Tanzania for first half 2019.

But Orca Exploration says it had a surge in Natural gas deliveries from the Songo Songo gas project in the same country.

Each of the two companies operates one of the two key natural gas projects that feed Tanzania’s industries, power plants and factories.

M&P operates the Mnazi Bay project, which pumps gas directly into the 532 kilometre National Natural Gas pipeline and connects Mtwara, where the Mnazi Bay gas field is located in the south eastern region of the country with the commercial capital Dar es Salaam.
Orca Exploration operates a natural gas processing facility on Songo Songo Island, off the coast of southern Tanzania.

M&P says its natural gas production (gross) dropped 17% to 66.2Million standard cubic feet per day in first half 2019, from 77MMscf/d averaged in first half of 2018. It cites “a result of the lower demand for gas because of the early and heavy rainy season, which led to a marked increase in hydropower generation capacity at the expense of gas demand”

But Orca Exploration reports its own supply shot up by 68% to 56.6Million standard cubic feet per day (MMscf/d), year to year in the second quarter of 2019.The same project had delivered 33.7 MMscf/d on average in second quarter 2018. Indeed, in the first six months of 2019, the production averaged 59.0 MMscf/d.

Orca says the surge in deliveries “is as a result of higher sales volume to Tanzanian Electricity Supply Company (TANESCO)”. Orca’s plant supplies natural gas to a 25 km 12″ offshore pipeline and a 207 km 16″ onshore pipeline and is used by the power sector and industrial markets in the Dar es Salaam area.

 


Reprocessed 3D Seismic Data For Red Sea Bid Round

Schlumberger and TGS say that a new Three Dimensional (3D) seismic reimaging project will be available before the close of Egypt’s offshore Red Sea international bid round on 15 September 2019.

The project comprises reimaging data from three overlapping seismic surveys totalling 3600km2 that were acquired between 1999 and 2008—the only available 3D data in this part of the Red Sea.

It includes the integration of all legacy seismic and non-seismic data and will apply advanced imaging technologies to better define complex subsalt structures.

The project, which is supported by industry pre-funding, will be carried out by TGS and WesternGeco®, the geophysical services product line of Schlumberger.

The two companies say their collaborative approach “will help our clients identify high-potential play segments, assess exploration risks and accelerate hydrocarbon discovery.”

“The Red Sea 3D reimaging project follows a multi-client 2D seismic acquisition programme that was completed in March 2018 as the initial step in mitigating the complex salt imaging challenges in the area,” said Kristian Johansen, CEO, TGS. “The underexplored offshore Egyptian Red Sea area is made up of large, untested structures that offer exceptional growth opportunities for oil companies.”

Schlumberger and TGS have a long-term commitment with the Egypt Ministry of Petroleum and South Valley Egyptian Petroleum Holding Company (GANOPE) to acquire and process seismic data and promote the prospectivity of the Egyptian Red Sea.

 


Sasol’s Delay in Report Is a Pointer to Governance Risk

Africa’s largest publicly listed hydrocarbon company is pointing fingers at itself, indicating higher governance risk, in the opinion of S&P, the global ratings firm.

“A further delay in the release of South Africa-based integrated chemicals and energy group Sasol Ltd.’s year-end results indicates higher management and governance risk, and suggests potential disclosure restatements in last year’s financial statements”, S&P says in a statement.. “We rate Sasol (BBB-/Stable/A-3) two notches above South Africa (BB/Stable/B)”, S&P declares.

The release of results for fiscal 2019 (ended June 30, 2019) was initially delayed from Aug. 19, 2019 to Sept. 19, 2019. However, this has been extended to no later than Oct. 31, 2019, which is within the respective equity and bond listing authorities’ regulatory deadlines.

“The further delay follows the Board’s decision to commission additional work and to give time for further investigation into particular points raised in the original board-commissioned independent review of recent cost and schedule changes in the Lake Charles Chemicals Project (LCCP)”, S&P says in a note to investors.

The investigation began after Sasol announced further increases to the capital cost estimate in May 2019. A preliminary report was provided to the Board on Aug. 14, 2019. The additional investigation includes assessing if any potential control weakness identified in the preliminary report, as well as the root cause for the changes in the cost and schedule estimate, were present in the previous fiscal year.

The review and subsequent additional work followed Sasol’s announcements in February and May 2019 of cost overruns, with LCCP’s capital expenditure exceeding the $11.1 billion it had communicated in September 2018 by $1.5Billion-$1.8Billion. In its Aug. 16, 2019 and Sept. 6, 2019 announcements, Sasol’s Board indicated that it expects no change to the earnings guidance in the company’s trading statement of July 25, 2019, and has also confirmed its previous LCCP capital cost guidance of $12.6Billion-$12.9Billion. The LCCP ethane cracker unit achieved beneficial operation at the end of August 2019.

S&P says it expects “that the financial results for fiscal 2019 will include information on the qualitative aspects of LCCP cost estimation/projection controls, specifically reporting and oversight, further informing our view on Sasol’s management and governance risk”.

 


Accra based Springfield on a Historic Deep-water Journey

By Toyin Akinosho, Publisher

In a matter of weeks, Springfield E&P will be the first home-grown, African owned E&P operator to spud a well in a new deepwater licence.

Its planned drilling of Oak-1, for which it had contracted the Stena Forth drillship, is significant history making.

The 11 year old company plans to follow up the well with another, the Afina-1, both of them in West Cape Three Points (WCTP) Block 2, offshore Ghana.

By all accounts Springfield will be drilling the wells as a full blown operator.

Oak-1 is on trend with the Beech structure, on which Hess Corp. discovered oil in Beech-1 in 2013, in 1,713 metres of water.

Both prospects are to be tested on the basis of interpretation of an 800 sq kilometre, three dimensional (3D) seismic data, acquired by PGS and paid for by Springfield, in 2017.

It will not be the first time that a company owned by African businessmen would drill, or be part of drilling, in deepwater, but there’s a context.

“Other African owned E&P companies with licences in Ghana, including Amni, Oranto, Brittania U and Sahara, were all awarded their different blocks in the country before Springfield.”

The Nigerian founded Erin Energy, now in bankruptcy, was drilling wells in over 400 metres of water offshore western Niger Delta. It was running a 40,000BOPD Floating Production Storage Offshore (FPSO) facility, the Armada Perdana, until it stopped being a going concern in mid-2018. Its licence to OML 120 was revoked by the government in June 2019.

London listed Afren discovered the Ogo field in 2013, said to be one of the largest discoveries in the world in that year, with, in part, funding raised by LEKOIL, the AIM listed firm founded by a Nigerian entrepreneur.

But Erin Energy (formerly Allied Energy, a subsidiary of Camac, and listed in NYSE Amex), was an operator by default; it came from being a non-operating partner to Statoil, which discovered the asset, Oyo field, in 1995, and ENI, which put it on stream in 2010 and was producing it until it pulled out of that asset. At no time from discovery to commissioning was Erin in operational charge of Oyo field.

LEKOIL, meanwhile, was, on Ogo discovery, also a non-operating partner to Afren, a company founded by a diverse mix of nationalities and which also has ceased to exist.

Springfield was awarded the WCTP Block 2 in 2016, with Ghana National Petroleum Corporation (GNPC) and its operating subsidiary, GNPC Explorco, as carried partners.

Other African owned E&P companies with licences in Ghana include Amni, Oranto, Brittania U and Sahara. They were all awarded their different blocks in the country before Springfield but have not announced any concrete drilling plans.


Eunisell Committed to Reducing Marginal Field Challenges.

By Akpelu Paul Kelechi, Technology Correspondent

“Delivering The Qua Ibo field is a clear example of what we have done”, company beats its chest.

Eunisell, the Nigerian oil & gas production solutions provider, says it us committed to assist marginal oil field operators overcome complex technical and financial challenges.

This will help the government achieve its local content programme objectives, the company’s top management argues.

“Eunisell brings in its own assets and resources to help achieve early cash flow and accelerate the marginal oil field development”, says Chika Ikenga, Eunisell’s Group Managing Director. “Our track record speaks for itself. We are there to help build viable, Nigerian oil and gas businesses,” he explains.

“Achieving the objectives of the local content programme, is a vital factor in sustaining Nigeria’s economic development and oil industry growth.

“The marginal field development programme and the recent divestments of fields by IOCs have increased the participation of Nigerians in the oil and gas industry. The gap in technical and financial resources that have fallen out of recent developments, is being closed by Eunisell’s unique production solutions”.

Ikenga notes that the company’s taking the Qua Ibo field to first oil “is a clear example of what we have done.

“Apart from building a production facility in record time with the skills of highly experienced Nigerian professionals, Eunisell’s fast track solution helped to get these fields into early cash flow”.

Eunisell’s fast track production facilities also helped to achieve first oil in record time at Oil Mining Lease (OML) 56 in Delta State, and the OML 46 Atala field in Bayelsa.

Eunisell, with more than 20 years’ experience, was recently certified as an ISO 9001:2015 company. “We are immensely proud of our ISO certification; it underlines our longstanding ability to deliver critical Quality Management Systems (QMS) and Processes to our customers,” . Ikenga declares.


Pushing Boundaries with ‘Cement-less’ Completions

By Akpelu Paul Kelechi

“Many wells today where you have well integrity and zonal isolation issues are a result of a failure of the cement”

It is practically impossible to discuss well completions without a nod to the cementing process: the standard procedure that isolates the various down-hole formation zones.

Prior to 1921, one of the greatest obstacles to successful development of oil bearing sands was the encountering of liquid mud, water and other sediments during and after the process of drilling a well; this was before the art of well cementing was “perfected.” It is easy to assume that almost a century later in 2019, well cementing would have advanced so much technologically that no undesirable basic, sediment and water (BS&W) would be produced from oil wells due to the failure of the cement to seal. Unfortunately, we still have frequent challenges mainly due to the hole geometry, formation types, pore pressure, differential pressure, etc. The production from typical oil wells which are hampered by BS&W intrusion require time, energy and expense to correct and has led to the abandonment of many wells which would otherwise have developed more profitable results for operators.

WAI Deployed in a Deepwater well

In July 2019, the French major Total announced that it successfully deployed a new breed of cementless completion called the Welltec Annular Isolation (WAI) in the Moho North Albian field.  According to Ronan Bouget, the Drilling and Completions manager of Total E&P Congo, the technology was jointly developed with Welltec. Gbenga Onadeko, Senior Vice President, Welltec Africa, tells Africa Oil+Gas Report that the “Welltec Annular Barrier (WAB) provides effective zonal isolation at discrete points within the well, whereas, the WAI provides zonal isolation across the length of the reservoir replacing the cement.”

“Many wells today where you have well integrity and zonal isolation issues are because of failures of cement. Attempting to place cement and achieve full circumferential coverage around a piece of pipe that is over three kilometres downhole in a well could be challenging due to gravitational effects especially if the well has some deviation, Gbenga explains. “The cement will tend to go to the lower side of the liner / casing while the upper side of the liner / casing may be left without cement, creating what is called a channel. The cement could also be contaminated due to interactions with mud and formation cuttings. The channels and micro annulus may lead to a loss of integrity or isolation between zones which could accelerate the production of water or gas break through.”

Squeeze cementing is a remedial cementing technique deployed when challenges occur during the primary cementing process. Gbenga continues. However, “this has a relatively low success rate with high cost. This is often the reason why wells produce 60% to 70% water cut from day one and is a contributor to cost overrun. In addition, depending on the age of the well, for example in the case of a relatively old well, cracks could develop in the cement due to thermal expansion and contraction, which can then lead to the leakage of gas or water.”.

Major IOC Review of 96 Cement Operations

 

The WAI technology can be deployed in various and even hostile well environments, adds Joseph Bagal, who is the Director of Well Completions for Welltec Africa. Joseph is a sand control expert with global experience and gained significant knowledge of the Niger Delta from various assignments living and working in Nigeria. He is familiar with the challenges associated with clastic depositional environments of the Niger Delta and he says that “although the first deployment of the WAI was in the Moho North which is a carbonate field, the WAB and the WAI technologies are also applicable in clastic environments.

WAB Preventing Water and Gas Production in the Benin Basin, Offshore, Nigeria

The materials used to manufacture the WAI are the same as used for very hostile environments including within Geothermal wells. They are highly resistant to corrosion and specifically selected for their life of well properties. Today, the industry continues to use cement because that is historically the solution utilized (even though as mentioned many well integrity issues arise from cement failure). The technical qualification performed on the Welltec Annular Sealing Products (WAB, WLP, WAI) are more stringent than the qualification tests on cement, when used for isolation – particularly their sealing capabilities” he claims.

The application of the WAI on the Moho North field dates back to 2016, when TOTAL E & P Congo selected the WAB in the development of the Moho North Albian field “this initial application was in conjunction with cement (assurance to provide a seal to isolate the zones)”, comments Joseph. “Total initially selected a cemented and perforated liner solution, the liner length was short and deep, implying the volume of cement was relatively small, which increases the operational risk of cementing the reservoir section. Because of the potential of cement contamination and also to increase the success rate of placing it behind the liner, the volume of cement pumped was increased by enlarging the hole (under-reaming) and drilling deeper i.e. a longer rat hole section, which placed the toe of the well within less preferential sections of the formation increasing the drilling and production risks.

With the liner deployed and cement in place, the WAB is expanded quickly under full surface control sealing against the formation rock, displacing the cement, providing a high integrity pressure isolation between zones. This in turn ensures that even if channels or micro-annulus are present in the cemented interval, effective isolation is still achieved within the annulus.

WAB for Cement Assurance in a Deepwater well

Following this initial success with the WAB and the efficiency drive by TOTAL E & P Congo to further reduce drilling expenditure (partially driven by the low commodity prices), this presented an opportunity to extend the scope of the utilization of the WAB to make the project more economical. This provided the impetus for the joint development of the WAI between Welltec and Total E & P Congo.

The WAI technology is based on the WAB platform, with the packers extending over the complete length of the liner (the joints are not covered). The WAI effectively replaced the cement within the annulus across the reservoir interval. A large quantity of Welltec Proprietary seals are installed along the length of the WAI, providing zonal isolation down to each 20 cm, with each seal qualified for 4,500 PSI of differential pressure. By eliminating the cement completely from the reservoir section of the wells, the drilled interval is shortened (i.e. no rat hole), the need to under-ream for hole enlargement is removed along with the need to perform extensive wellbore cleanout. This reduction in work scope delivered significant savings in the number of days predicted to complete the well compared to the best composite result achieved in the field. Non-Productive Time (NPT) from the wells where the WAI were deployed was reduced. The use of the WAI led to a reduction in rig time and saved a huge amount of cost for our client.”

Returning to the WAB technology, which has been deployed all over the world including clastic environments in the North Sea and as well as in the Benin Basin Offshore Lagos, Nigeria. “If you have a clastic reservoir, cement is pumped all the way to the cap rock to achieve isolation and well integrity. We successfully used the WAB product to assist a minor deepwater operator in Nigeria to achieve approximately 3,000 barrels per day of oil production. Two WABs were installed in the side-tracked section of their last well which successfully eliminated the water cut, but more importantly eliminated the gas flowing from the gas gap and the associated sustained casing pressure as monitored at the well head. It is understood that the well has kept this state since 2017 when it was put on production.”

The catch with the oil and gas industry however, is the conservative nature of the industry in adopting new and improved technology. As an innovative company with pioneering technologies, Welltec often experiences this challenge. Gbenga sums it up with these words: “We develop cutting edge technologies and work extremely hard to convince our clients to deploy the value adding solutions. One of values we add to the industry is to assist our clients in overcoming their initial reluctance. We want to ensure that these technologies are included in their field development plans to avoid paying premiums later due to rush mobilizations. Including the technologies in their initial plans reduces the risk of budget variation. With the WAI, we predict that cost savings of up to $75Million to $100Million over a 15 to 20 wells deepwater field development plan can be achieved (including reduced NPT). Proportional savings can also be achieved in onshore and shallow offshore markets. Approaching it from a larger scale makes the value proposition more obvious. We like to think that we work on solutions that are best for the well and the overall project. In most cases, our industry is integral to the economies of the oil and gas producing countries. We therefore believe that we are having a positive impact on the overall wealth of the nations we operate in.”


LEKOIL Looks For Partner to Take Over Disputed 23% Stake in OPL 310

LEKOIL has agreed with Optimum, its partner in Oil Prospecting Lease (OPL) 310, in deepwater Nigeria, to use its 22.86% equity stake in the Block as a potential funding and security vehicle for the accelerated development of the Block by an industry partner or a third party that elects to farm-in to the Block to fund field development.

The AIM listed LEKOIL has a 17% equity on the lease that has been authorised by the Nigerian authorities, but has been unable to get the consent of the government for another 22.86%, equity, which it purchased with $13Million from Afren in 2015, mainly because Optimum, the holder of the licence (who sold the stake to Afren in the first place), disagrees that LEKOIL had legitimately bought the equity from Afren.

“This dispute has been the principal reason that development of the Block has been delayed”, LEKOIL says in a release.

LEKOIL had taken the President of Nigeria (who is the Minister of Petroleum) to court over the non-granting of consent for that equity for four years. It lost the case and decided not to appeal.

“Rather than pursue this matter further, the Parties have agreed to recourse to sourcing a third party that will bring money to fund the appraisal and development of the field”, LEKOIL explains.

The resource estimates of the Ogo field, the undeveloped discovery in the licence, is 750Million barrels of oil equivalent. The two probes on the structure were not tested, so the volumes could be less. But they also could be more and there’s the perception that most of it is natural gas, which now has a growing market in Lagos, the nearest city inshore of the field.

The potential Funding Partner may be sourced by either LEKOIL or Optimum. The agreement does not address the recovery of the $13Million consideration previously paid by LEKOIL with respect to the acquisition of the shares of Afren Oil & Gas (Nigeria) Limited (“AOGNL”) in 2015 (which held the 22.86% participating interest in OPL310). The idea is that this money will be part of the farm in consideration to be taken care of by the incoming funding partner.


How We Arrived: From Osuno To Akinyanmi

When Ben Osuno was hired by ShellBP Upstream in Nigeria in September 1960, the company’s idea was to mix the expatriate white technical staff with some locals.

After 11 years and eight months in Shell(discounting the civil war period, May 1968-January 1970), the pioneering Nigerian petroleum geoscientist left for a government job and at some point became the Director of Department of Petroleum Resources, the country’s petroleum regulator.

Still, while there have been several generations of homegrown technical staff after Osuno, it took 42 years after 1960 to produce the first Nigerian managing director of a major multinational firm operating in the country.

Basil Omiyi’s appointment as Chief Executive of Shell Nigeria in 2002 was widely greeted as some form of validation of the capacity of the Nigerian to run a large industrial enterprise, but things have shaped up a little differently since then.

Today, it is less fashionable than it was 20 years ago to aspire to be a senior executive in a multinational company. Why not become a founder, co-owner and Chief Executive of an upstream resource company?

The careers that exemplify the new age include those of Layiwola Fatona, Austin Avuru, Emeka Okwuosa and Demola Adeyemi -Bero.

Twenty years after Osuno was hired by Shell, Avuru was a fresh graduate of geology from the University of Nigeria, Nsukka, serving his mandatory National Service at NNPC, the state hydrocarbon company; Fatona was returning home from Imperial with a PhD in Sedimentology; Okwuosa was two years away from a Bachelor’s degree in Engineering at Ife and Adeyemi-Bero was still in higher secondary school in the UK.

Today, Fatona is retiring from Niger Delta Exploration and Petroleum, an integrated company with majority holdings in three upstream acreages in Nigeria and footprints in South Sudan; Avuru is the chief executive of Seplat Petroleum, the only Nigerian firm listed on the main board of the iconic  London Stock Exchange; Okwuosa’s Oilserv operates an upstream acreage in the Republic of Benin and  is the busiest hydrocarbon pipeline construction company in Nigeria. These are some of the industry’s ranking businessmen whose start up stories are profiled in the September 2019 edition of Africa Oil+Gas Report.

Our inaugural PETROLEUM PEOPLE SPECIAL overviews the emerging local and international personnel taking charge of things in the African E&P space. It is part of making sense of the paradigm shift in the industry, for the benefit of our subscribers.

The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions, for useful analyses of Africa’s oil and gas industry. Published by the Festac News Press Limited since November 2001, AOGR is a monthly, 40 page e-copy and hardcopy publication delivered to subscribers around the world. Its website remains www.africaoilgasreport.com and the contact email address is info@africaoilgasreport.com. Contact telephone numbers in our West African regional headquarters in Lagos are +2347062420127,+2348036525979 and +2348023902519.

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