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ExxonMobil and Hess Corp. announced today their latest discovery offshore Guyana with the Longtail-3 well that is in the massive Stabroek Block. A net pay of 230 ft (70 m) was reported within hydrocarbon bearing reservoirs that are below the first intervals discovered by the Longtail-1 well drilled in 2018 about 2 miles to the south. The new discovery was drilled in a water depth of about 6,100 ft. Texas-based ExxonMobil said it added two drillships to its Guyana operations, bringing the total to six. The newly arrived assets are the Stena DrillMAX and the Noble Sam Croft which are now part of a 15-well drilling program in the Stabroek Block.
Abstract This research proposed an alternative method for determining the saturation exponent (n) by finding the best correlations for the heterogeneity index using available core data and considering wettability changes. The log curves of the variable n were estimated, and the effect on the water saturation (Sw) calculations and the Stock Tank Oil Initially In Place (STOIIP) in the Tambaredjo (TAM) oil field was analyzed. Core data were employed to obtain the relationship between n and heterogeneity using cross-plots against several heterogeneity indices, reservoir properties, and pore throat size. After filtering the data, the clay volume (Vcl), shale volume, silt volume, basic petrophysical property index (BPPI), net reservoir index, pore grain volume ratio, and rock texture were defined as the best matches. Their modified/improved equations were applied to the log data and evaluated. The n related to Vcl was the best selection based on the criteria of depth variations and logical responses to the lithology. The Sw model in this field showed certain log readings (high resistivity [Rt] reading ≥ 500 ohm.m) that infer these intervals to be probable inverse-wet (oil-wet). The cross-plots (Rt vs. Vcl; Rt vs. density [RHOB]; Rt vs. total porosity [PHIT]) were used to discard the lithologies related to a high Rt (e.g., lignites and calcareous rocks) and to correct Sw when these resulted in values below the estimated irreducible water saturation (Swir). The Sw calculations using the Indonesian equation were updated to incorporate n as a variable (log curves), comparing it with Sw from the core data and previous calculations using a fixed average value (n = 1.82) from the core data. An integrated approach was used to determine n, which is related to the reservoir’s heterogeneity and wettability changes. The values of n for high Rt (n > 2) intervals ranged from 2.3 to 8.5, which is not close to the field average n value (1.82). Specific correlations were found by discriminating Swir (Swir < 15%), (Swir 15%–19%), and Swir (> 19%). The results showed that using n as a variable parameter improved Sw from 39.5% to 36.5% average in the T1 and T2 sands, showing a better fit than the core data average and increasing the STOIIP estimations by 6.81%. This represents now a primary oil recovery of 12.1%, closer to the expected value for these reservoirs. Although many studies have been done on n determination and its effect on Sw calculations, using average values over a whole field is still a common practice regardless of heterogeneity and wettability considerations. This study proposed a method to include the formation of heterogeneity and wettability changes in n determination, allowing a more reliable Sw determination as demonstrated in the TAM oil field in Suriname.
Guyana's President Irfaan Ali announced that the first phase of the Liza offshore crude project had achieved its intended full-production capacity of around 130,000 B/D. Ali told virtual attendees at the Guyana Basin Summit that he expected an additional 10 exploration and appraisal wells to be drilled off Guyana this year. He said the second phase of the Liza project, operated by ExxonMobil, would begin in 2022. The consortium led by Exxon, which includes partners Hess and CNOOC Ltd., has made 18 discoveries containing more than 8 billion bbl of recoverable oil and gas in Guyana's Stabroek block.
ExxonMobil will add to the previously announced gross discovered recoverable resource estimate for the block of around 9 billion BOE via a discovery with its Uaru-2 well. The probe encountered 120 ft of high-quality oil-bearing sandstone reservoir, including newly identified intervals below the original Uaru-1 discovery. The well was drilled in 5,659 ft of water and is located approximately 6.8 miles south of the Uaru-1 well. That well, drilled in January 2020, encountered 94 ft of oil-bearing sandstone. "The Uaru-2 discovery will add to the discovered recoverable resource estimate of approximately 9 billion barrels of oil equivalent," said John Hess, chief executive of Hess Corporation, a partner in Stabroek.
Hess Corporation announced today it is selling about 78,700 acres of its Bakken Shale position to Enerplus Corporation for $321 million. Oil production from the areas that are part of the deal averaged around 4,500 B/D over the first quarter of the year, Hess said in a statement. Calling the Bakken Shale a "core asset" for the company, CEO John Hess said the majority of the assets being sold off were not going to be drilled on until 2026 which "brings material value forward and further strengthens our cash and liquidity position." Enerplus considers much of the acreage to be Tier 1 and estimates it adds 2 or 3 years to its Bakken development runway, giving it an estimated 10 years' worth of drilling locations in the region. At current oil prices, Enerplus said the Tier 1 acreage and other areas amount to 120 undrilled locations.
Exxon encountered noncommercial hydrocarbons with a test of its Bulletwood prospect in the Canje Block in the Guyana-Suriname basin. The well, located in 2846 m of water, was drilled to its planned target depth of 6690 m using drillship Stena Carron. Data collection from the Bulletwood-1 well confirms the presence of the Guyana-Suriname petroleum system and the potential prospectivity of the Canje Block, said partner Westmount Energy. Bulletwood-1 was the first of three scheduled wells to be drilled on the block in 2021. Wells Jabillo-1 and Sapote-1 are expected to spud over the coming months.
Geoscientist Kerry Moreland was ExxonMobil's exploration manager for the Guyana/Suriname Basin from 2014 to 2018, when the energy giant confirmed multiple discoveries, including the world-class Liza-1 find, where for decades drillers hit mostly dry holes. After a stint as West Africa exploration manager and Africa geoscience manager for development and production, Moreland was promoted to her current position: vice president, Sub-Sahara Africa and Asia Pacific, exploration and new ventures, ExxonMobil Upstream Business Development Co. Today, Moreland manages ExxonMobil's oil and gas exploration acreage and evaluates new opportunities across the industry's two most important frontier energy landscapes--Asia Pacific and Africa, which are destined to see the highest growth in energy demand by 2050 as well as present the greatest challenges for managing energy supply in a dual energy environment. This week, Moreland discussed her company's current successes and future vision in one of a series of IPTC Insights interviews conducted by a moderator with thought leaders at the International Petroleum Technology Conference (IPTC) in Kuala Lumpur. Here, JPT reports the highlights of Moreland's interview. IPTC: In January 2020, ExxonMobil increased its estimated recoverable resource base in Guyana to more than 8 billion oil equivalent barrels and announced its 18th discovery in September 2020 at the Redtail-1 well on the Stabroek Block.
Soltani, Amir (Beicip-Franlab) | Decroux, Benoit (Beicip-Franlab) | Negre, Andres (Beicip-Franlab) | Le Maux, Thierry (Beicip-Franlab) | Djarir, Maâmar (Sonatrach) | Selmi, Farouk (Sonatrach) | Lantoine, Martin (Beicip-Franlab)
Abstract EOR surfactants are usually formulated at the initial reservoir temperature. Is this a correct approach? Field data from three Single-Well Chemical Tracer pilots in North Africa are used to answer this question. The objectives are, first, to provide a realistic image of the temperature variations inside the water-flooded reservoir; second, to demonstrate the impact of such temperature variations on the surfactant performances; and last, to introduce a new methodology for estimating the target temperature window for surfactant formulations. During pre-SWCTT pilot tests, water injection, shut-in and back-production were performed. The bottom-hole temperature was monitored to evaluate the reservoir temperature changes (initially at 120°C) and to calibrate a thermal model. The thermal parameters were applied to the reservoir model to simulate 30 years of water injection (with its surface temperature varying between 20°C and 60°C) and to obtain a full picture of the temperature variations inside the reservoir. Multi-well surfactant injection was modelled assuming that the surfactant is only efficient within ±10°C around the design temperature. The impact of this assumption on the additional oil recovery was analyzed for several scenarios. The rock thermal transmissivity was found to be the key parameter for properly reproducing the observed data gathered in the North African pre-SWCTT tests. The measured temperature during the back-production phase demonstrated the accuracy of the thermal model parametrization. It proved that the heat exchange between the reservoir and the injected fluid is considerably less than what industry expects: the injected water temperature inside the reservoir remains far below the initial reservoir temperature even after 11 days of shut-in. When simulating various historical bottom-hole injection temperatures and pre-flush durations, the thermal model showed an average cooling radius of 275m, larger than the industry recommended well-spacing for the EOR 5-spot patterns. This was mainly due to the significant temperature difference between the historical injected water and the initial reservoir temperature. Several simulations were performed for 3 representative bottom-hole injection temperatures of 20°C, 40°C and 60°C, varying the surfactant design temperature range between the injection temperature and the initial reservoir temperature. The results showed that regardless of the injection temperature, the simulated additional oil recovery is highest when the design temperature range is close to the injection bottom-hole temperature. This is an important subject since in the EOR industry, the surfactants are usually formulated at the initial reservoir temperature and thus, the impact of the reservoir cooling on the surfactant efficiency is seldom considered. In a water flooded reservoir, the injected chemicals are unlikely to encounter the initial reservoir temperature. This results in a dramatic loss of surfactant performance especially when there is a considerable difference between the initial reservoir and the injected fluid temperatures.
Exxon Mobil said on 15 January that its latest exploration well in the prolific Stabroek Block off Guyana's coast did not find oil in its target area. Exxon, which operates the Stabroek Block in a consortium with Hess and China's CNOOC, has made 18 discoveries in the area in 5 years, totaling more than 8 billion BOE, for a combined potential for producing up to 750,000 B/D of crude. The Hassa-1 exploration well was the giant's second setback to its drilling campaign in recent months. The disappointment came after Exxon said in November that its crude discovery at the Tanager-1 well was noncommercial as a standalone development. The well was the first Exxon drilled in the Guyana-Suriname Kaieteur Block, adjacent to Stabroek, and was the deepest drilled in that block to date.
KrisEnergy Pumps Cambodia’s First Crude in 17 Years A Cambodian concession has commenced production after years of delays in a venture between Singapore’s KrisEnergy and the government. The crude comes from oil fields in Block A, comprising 3083 km of the Khmer basin in the oil-rich Gulf of Thailand, off the southwestern coast of Sihanoukville. The concession will progress in phases once new wells are commissioned and completed. Kelvin Tang, chief executive of KrisEnergy’s Cambodian operations, called the 29 December event “an important strategic milestone” for the company, while Prime Minister Hun Sen hailed the first extraction as “a new achievement for Cambodia’s economy” and “a huge gift for our nation.” Ironbark Australian Exploration Well Declared Dry; Co-Owner Stocks Plummet BP has come up dry at its Ironbark-1 exploration well, the anticipated multi-trillion-scf prospect off the west Australian Pilbara coast. The disappointing prospect was once seen as a potential gas supplier to the emptying North West Shelf (NWS) LNG plant, where BP is a co-owner, within 5 to 10 years. After 2 months of drilling to a total depth of 5618 m, “no significant hydrocarbon shows were encountered in any of the target sands,” according to co-owner New Zealand Oil and Gas (NZOG). Petrorecôncavo Buys Petrobras’ Onshore Bahian Stake for $30 Million Brazilian operator Petrobras on 23 December signed a contract with independent producer Petrorecôncavo to sell its entire stake in 12 onshore E&P fields, the Remanso Cluster, in the state of Bahia. The sale value for the fields was $30 million; $4 million was paid on signing, $21 million at the closing of the transaction, and $5 million will be paid 1 year after that. The Remanso Cluster comprises the onshore fields of Brejinho, Canabrava, Cassarongongo, Fazenda Belém, Gomo, Mata de São João, Norte Fazenda Caruaçu, Remanso, Rio dos Ovos, Rio Subaúma, São Pedro, and Sesmaria. Zion Spuds the Israeli Megiddo-Jezreel #2 Well On 6 January, Zion Oil and Gas officially spudded the MegiddoJezreel #2 on its 99,000acre MegiddoJezreel license area in Israel. “With unique operating conditions in the COVID19 environment, our crews have performed an amazing task,” Zion CEO Robert Dunn said. “Mobilizing a rig into a new country during a pandemic and rigging up is the most challenging part of the drilling operation,” Zion’s vice president of operations, Monty Kness, added. Exxon Declares a Dud at Second Guyana Well Exxon Mobil said on 15 January that its exploration well in the prolific Stabroek Block off Guyana’s coast did not find oil in its target area. Exxon, which operates the Stabroek Block in a consortium with Hess and China’s CNOOC, has made 18 discoveries in the area in 5 years, totaling more than 8 billion BOE, for a combined potential for producing up to 750,000 B/D of crude. The Hassa1 exploration well was the giant’s second setback to its drilling campaign in recent months. Heirs Holdings Buys 45% of Shell Nigeria’s OML 17 Field Shell Nigeria announced on 15 January it had completed a $533 million sale of its stakes in an onshore OML 17 oil field in Nigeria to African strategic investor Heirs Holdings, Nigeria’s largest publicly listed conglomerate. The deal is one of the largest oil and gas financings in Africa in more than a decade, with a financing component of $1.1 billion provided by a consortium of global and regional banks and investors. Heirs Holdings, in partnership with Transcorp, one of the largest power producers in Nigeria with 2000 MW of installed capacity, purchased 45% stake in the field. It acquired the stakes of Shell, Total, and Eni to further its expansion into the oil and gas industry. Apex Discovers Oil in Egypt’s Western Desert Privately held independent E&P firm Apex International Energy, backed in part by UK energy investment firm Blue Water Energy, on 18 January announced a discovery in the Southeast Meleiha Concession (SEM) in the western desert of Egypt. The discovery was made at the SEMZ-11X well located 10 km west of Zarif field, the nearest producing field. The well was drilled to a total depth of 5,700 ft and encountered 65 ft of oil pay in the Cretaceous sandstones of the Bahariya and Abu Roash G formations. Testing of the Bahariya resulted in a peak rate of 2,100 B/D with no water. Additional uphole pay exists in the Bahariya and Abu Roash G formations that can be added to the production stream in the future. Kosmos Announces Oil at Winterfell Well Dallas-based E&P independent Kosmos Energy announced on 19 January an oil discovery in deepwater US Gulf of Mexico. The Winterfell discovery well, the product of infrastructure-led exploration (ILX), was drilled to a total depth of approximately 23,000 ft and is located in approximately 5,300 ft of water. This subsalt Upper Miocene prospect in off-shore Louisiana encountered approximately 85 ft of net oil pay in two intervals. ILX exploration, which has featured prominently in upstream operators’ portfolios in recent years of relatively low oil prices, is exploration around producing hubs that can be hooked up to those facilities easily and cheaply. The development sidesteps the need for costly and time-consuming individual hub construction. Equinor Gets Permit To Drill North Sea Wildcat Well The Norwegian Petroleum Directorate has granted Equinor a drilling permit for wildcat well 31/11-1 S in the North Sea offshore Norway, 62 km south of the Troll field. The drilling program is the first exploration well to be drilled in production license 785 S, awarded on 6 February 2015 (APA 2014). Operator Equinor and Total E&P Norge are 50/50 partners in the license, which consists of parts of Blocks 26/2 and 31/11. Petrobras, ExxonMobil Hit Hydrocarbons at Urissanê Well, Offshore Brazil Brazilian state-owned Petrobras announced on 29 January it had discovered hydrocarbons in a well located in the Campos Basin presalt off Brazil’s coast of Campos dos Gotyacaze in the State of Rio de Janeiro. Well 1-BRSA-1377-RJS (informally called Urissanê) is located in Block C-M-411, at a depth of 2950 m approximately 200 km offshore. Petrobras, which operates the block in a 50/50 partnership with Exxon Mobil, said it would analyze the well data to better target exploratory activities and assess the potential of the discovery. BP Offloads 20% Share of Oman’s Block 61 To PTTEP Marking another significant step in its divestment program, BP will sell a 20% participating interest in Oman’s 3950 km Block 61 in central Oman to Thailand’s national PTT Exploration and Production (PTTEP) for $2.59 billion. BP will remain operator of the block, holding a 40% interest. The sale comprises $2.45 billion payable on completion and $140 million payable contingent on preagreed conditions. After the sale, BP will hold 40% interest in Block 61, while OQ holds 30%, PTTEP 20%, and Petronas 10%. Block 61 contains the largest tight gas development in the Middle East.