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"To win the SONT award and to help our client enable an enhanced level of reservoir understanding are great achievements," said Christina Johansen, senior vice president of TechnipFMC subsea product management. "Solutions such as Odassea transform our clients' project economics and demonstrate how we are continuously driving change in the industry." TechnipFMC and Halliburton announced they received an Offshore Technology Conference (OTC) Spotlight on New Technology (SONT) award for their Odassea Subsea Fiber Optic Solution, an advanced downhole fiber-optic sensing system. ExxonMobil selected the solution for its Payara development project in Guyana. The award followed completion of front-end engineering and design studies and qualifications.
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.