ALBERT

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201520, “Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions Into Tight Plugs,” by Mohammad Yousefi, Lin Yuan, and Hassan Dehghanpour, SPE, University of Alberta, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Various chemical additives have been proposed recently to enhance imbibition oil recovery from tight formations during shut-in periods after hydraulic fracturing operations. In the complete paper, the authors develop and apply a laboratory protocol mimicking leakoff, shut-in, and flowback processes to evaluate the effects of fracturing-fluid additives on oil regained permeability. A conventional coreflooding apparatus is modified to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Methodology Proposed Technique for Measuring Oil Effective Permeability. Despite the simplicity of the steady-state method, measuring permeability of tight rocks with this technique is challenging because of its time-consuming nature and the fact that accurate measurement is necessary of extremely low flow rates corresponding to low injectivity of tight rocks. The authors use a pair of plugs from a well drilled in the Montney formation that is a stratigraphic unit of the Lower Triassic age in the western Canadian sedimentary basin located in British Columbia and Alberta. It is mainly a low-permeability siltstone reservoir. In the modified coreflooding apparatus, the authors reduce the effect of compressibility in order to reduce the duration of the transient period by approximately one order of magnitude. Because monitoring changes in pressure is much easier and more accurate than monitoring flow-rate changes, a constant flow-rate mode is used and pressure is recorded with time. Oil is injected at different constant flow rates (qo), and the inlet pressure is monitored. The stable pressure difference across the plug is recorded for each flow rate. After steady-state conditions are reached based on the pressure profile, the qo is increased. This process is repeated until four stable pressure differences corresponding to four different qo are obtained. After the highest qo is reached, it is decreased in similar steps to check the repeatability of each data point. The permeability is calculated with the Darcy equation and slope of the qo vs. stable pressure difference across the plug.

Description: The concept of a standalone production system on the seabed with automated wellbore construction and production processes has been an industry goal for a long time. Electrification of subsea facilities and of wellbore and reservoir equipment offers many opportunities to improve operational efficiency, reduce life-of-field capital and operating expenses, and reduce carbon footprint, among other benefits. Talk of a subsea electrification revolution being “just around the corner” has been ongoing for more than 20 years. And, millions of dollars in investments and numerous joint industry projects (JIPs) over the past decade have moved the vision closer to fruition (Fig. 1). But the upstream industry continues to lag others in replacing hydraulics with electrics. The reasons echo those for slow uptake of other new technologies and methodologies—fear of change, the unknown, and failure. Now, recent events are stirring up interest and expectations. “Four to five years ago, only a very small percentage of the buying community were making big noises about the future state of the electrified subsea or subsurface,” said John Kerr, subsea production systems and technology director for Baker Hughes, in a recent interview. “During the past 18 months the narrative has increased rapidly with many more operators looking at electrification as the base case for subsea solutions. We’ve seen a groundswell of interest to the point that we now see 3-, 5-, and 7-year lookaheads with electric solutions as the base case design concept,” Kerr said. What has changed? “Electrification of subsea devices has always been a solution to solve specific technical needs,” said Kerr. “The predominant one was extreme long-distance stepouts, where once you get to 250 miles or so, the ability to pump hydraulic fluids through small umbilicals presented so much pressure loss that it became impractical to implement a hydraulic solution, so all-electric became the solution of choice. Now we are seeing much more understanding of what electrification can deliver in the commercial and operational sense. “During the last 2 years, there has also been rapid adoption of dialogue around the aspect of increased carbon credentials and carbon reduction as an advantage,” Kerr continued. “The interest is much more comprehensive, driving different behavior in concept selection for operators.” Has the pandemic played a role? The consensus of participants in a subsea electrification panel at the virtual 2020 SPE Annual Technical Conference and Exhibition (ATCE) was that unless you’re surrounded by a crisis, you’re not encouraged to change. “The moment you put someone in a crisis situation, they understand that they have to change,” said Rory Mackenzie, leader for subsea electrical technologies at Total. “2020—the pandemic, oil price collapse, and environmental issues—this created a crisis. People are now much more open to considering change.” The panelists included Alvaro Arrazola, completions engineer, Chevron, North America Upstream; Glenn-Roar Halvorsen, project manager subsea all-electric, Equinor; Christina Johansen, managing director, Norway, TechnipFMC; Samantha McClean, intelligent wells technical advisor, BP; Rory Mackenzie, head of subsea electrical technologies, Total R&D; and Thomas Scott, global product line director, intelligent production systems and reservoir information, Baker Hughes. Edward O’Malley, director of strategy and portfolio, oilfield services, Baker Hughes, moderated the session.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31250, “Wandoo B: Application of Advanced Reinforced Concrete Assessment for Life Extension for Non-Jacket Structures,” by Robert Sheppard, Spire Engineering; Colin O’Brien, Vermilion Oil and Gas; and Yashar Moslehy, Spire Engineering, et al., prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Wandoo B is a concrete gravity-based structure (GBS) and is the main production facility for the Wandoo field offshore northwest Australia. It was installed in 1997 with a design life of 20 years. The structural assessments discussed in this paper are part of a comprehensive life-extension project encompassing wells, subsea systems, marine and safety systems, and topsides facilities and structures to demonstrate fitness for service through the end of field life. Background The GBS serves as the support structure for the Wandoo B facility and provides oil storage for the Wandoo field. The structure has four shafts approximately 11 m in diameter that support the top-sides facilities and a base structure with permanent ballast and oil storage cells (Fig. 1). It was originally developed as an ExxonMobil-led project and now is owned and operated wholly by Vermilion Oil and Gas Australia. The reinforced concrete (RC) shafts and the base top slab are pretensioned. In the shafts, tendons are enclosed in 20 ducts distributed around the circumference. The top of the shafts provides a mating point with the steel topsides structure with the connection formed by embedded anchor bolts in a bulge in the shaft cross section. The topsides structure is a three-level braced steel frame system supporting production operations for 12 well conductors contained within the northeast shaft and three outboard well conductors. Life-Extension Project The facility was designed with a target life of 20 years. The life-extension project was intended not only to satisfy the operator’s responsibility to continue safe operations and adhere to their safety case but also to meet the expectations of the regulator. The structural aspects of the project included four phases, the first two of which are detailed in this synopsis: - Design assessments per latest standards and modifications where required - Ultimate capacity assessments with retrofit modifications where required - Risk studies and workshops to demonstrate that risk is as low as reasonably practicable (ALARP) - Integrity-management manual and inspection plan The first two phases were addressed using the latest condition-assessment, weight, and environmental data available. The phased approach allowed the assessment team to use basic linear approaches to demonstrate code compliance and only use the more-advanced analysis techniques to evaluate the critical components that did not satisfy code or were needed to provide input to the ALARP assessment and establish target reliability for the facility.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202260, “Inversion of Advanced Full Waveform Sonic Data Provides Magnitudes of Minimum and Maximum Horizontal Stress for Calibrating the Geomechanics Model in a Gas Storage Reservoir,” by Zachariah J. Pallikathekathil, SPE, Xing Wang Yang, and Saeed Hafezy, Schlumberger, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. In 1D geomechanics projects, calibration of stress is extremely important in the construction of a valid mechanical earth model (MEM). The effective minimum horizontal stress (Shmin) data usually are available from traditional measurements, but these have a few deficiencies. The complete paper presents a technique for deriving stresses in which the radial variation of acoustic velocity from an advanced dipole sonic logging tool is inverted to obtain stress. These derived stresses are then used to calibrate the 1D MEM for a gas storage field. Regional Geology The field is in the Otway Basin in Western Victoria. Gas is trapped in the Late Cretaceous Waarre formation at depths between 1155 and 1200 m subsea. The reservoir is sealed by the overlying marine Belfast mudstone, which is the common seal in the stratigraphy across the onshore Otway Basin. The reservoir has excellent reservoir quality and has proved ideal for gas storage. Challenge Posed by the 1D MEM Challenge Posed by the 1D MEM Well 1 was recently drilled in the basin. A 1D MEM - a numerical representation of the geomechanical properties and stress state of the earth at any depth - was planned to be constructed to obtain the current-day far-field principal stresses (Shmin), effective maximum horizontal stress (SHmax), and effective vertical stress (SV)] in the Belfast and Waarre formations. Understanding the stress field was important, especially in the caprock (Belfast) and in the reservoir (Waarre) so that the pressure limits for safe gas-storage operation could be defined better. However, for a variety of reasons, no conventional stress measurements were available to calibrate the modeled stress in the 1D MEM. Without any calibration of the stress, the geomechanics model would feature high uncertainty to be used to define the pressure operational limits for gas-storage operation. Fortunately, a new wireline sonic tool was recorded in the reservoir section and the overburden sections of the borehole in Well 1. A quick dispersion analysis of the waveforms showed that the Paaratte formation, above the Belfast formation, was acoustically stress-sensitive and that advanced processing could be performed to invert the acoustic information to stress values.

Description: As production chemists, we are all aware of the overall concepts of improved oil recovery (IOR) and enhanced oil recovery (EOR). Perhaps, though, fewer of us are aware of the different idiosyncrasies that exist within (and even between) these two broad categories of recovery and then how chemistry and chemicals can have an effect upon these processes. I would like to propose that the lines once were quite distinct between IOR and EOR: IOR was a standard waterflood operation, and EOR (from a chemist’s perspective) was the addition of chemistry to that waterflood (typically polymer or surfactant). Nowadays, the science has evolved massively to create many sub-genres of IOR and EOR. A waterflood is rarely just a waterflood anymore. We can alternate water and gas injection. We can add chemical conformance aids to direct better the flow of water. We can change the salinity of the water to promote better wettability for higher recovery factors. The list goes on. One just has to search out the number of EOR papers vs. (pretty much) every other discipline of production chemistry to see the commitment this industry still has to the research of this discipline. In recent years, the focus has tended to move away from deep-reservoir EOR to focus on near-wellbore stimulation. Interestingly, the mechanistic considerations that we make as production chemists are nearly identical in all cases, and significant synergies exist between these subdisciplines. Therefore, from the recent research published by SPE, two focused topics of IOR/EOR have arisen: the use of nanoparticles and the use of water-shutoff technologies. Nanoparticle use is gaining significant traction in the oil and gas industry, and field applications are now being reported. The area of IOR/EOR is no exception. Water shutoff is not a new technology area. However, are these established, production-sustaining IOR techniques seeing a resurgence caused by the headwinds our industry has faced during the COVID-19 pandemic? Recommended additional reading at OnePetro: www.onepetro.org. OTC 30123 - Thermal and Rheological Investigations on N,N’-Methylenebis Acrylamide Cross-Linked Polyacrylamide Nanocomposite Hydrogels for Water-Shutoff Applications by Mohan Raj Keishnan, Alfiasal University, et al. IPTC 20210 - Chemical and Mechanical Water Shutoff in Horizontal Passive ICD Wells: Experience and Lessons Learned in Giant Darcy Reservoir by Mohamed Abdel-Basset, Schlumberger, et al. SPE 203831 - Efficient Preparation of Nanostarch Particles and Mechanism of Enhanced Oil Recovery in Low-Permeability Oil Reservoirs by Lei Zhang, China University of Geosciences, et al.

Description: For this feature, I have had the pleasure of reviewing 122 papers submitted to SPE in the field of offshore facilities over the past year. Brent crude oil price finally has reached $75/bbl at the time of writing. So far, this oil price is the highest since before the COVID-19 pandemic, which is a good sign that demand is picking up. Oil and gas offshore projects also seem to be picking up; most offshore greenfield projects are dictated by economics and the price of oil. As predicted by some analysts, global oil consumption will continue to increase as the world’s economy recovers from the pandemic. A new trend has arisen, however, where, in addition to traditional economic screening, oil and gas investors look to environment, social, and governance considerations to value the prospects of a project and minimize financial risk from environmental and social issues. The oil price being around $75/bbl has not necessarily led to more-attractive offshore exploration and production (E&P) projects, even though the typical offshore breakeven price is in the range of $40–55/bbl. We must acknowledge the energy transition, while also acknowledging that oil and natural gas will continue to be essential to meeting the world’s energy needs for many years. At least five European oil and gas E&P companies have announced net-zero 2050 ambitions so far. According to Rystad Energy, continuous major investments in E&P still are needed to meet growing global oil and gas demand. For the past 2 years, the global investment in E&P project spending is limited to $200 billion, including offshore, so a situation might arise with reserve replacement becoming challenging while demand accelerates rapidly. Because of well productivity, operability challenges, and uncertainty, however, opening the choke valve or pipeline tap is not as easy as the public thinks, especially on aging facilities. On another note, the technology landscape is moving to emerging areas such as net-zero; decarbonization; carbon capture, use, and storage; renewables; hydrogen; novel geothermal solutions; and a circular carbon economy. Historically, however, the Offshore Technology Conference began proactively discussing renewables technology—such as wave, tidal, ocean thermal, and solar—in 1980. The remaining question, then, is how to balance the lack of capital expenditure spending during the pandemic and, to some extent, what the role of offshore is in the energy transition. Maximizing offshore oil and gas recovery is not enough anymore. In the short term, engaging the low-carbon energy transition as early as possible and leading efforts in decarbonization will become a strategic move. Leveraging our expertise in offshore infrastructure, supply chains, sea transportation, storage, and oil and gas market development to support low-carbon energy deployment in the energy transition will become vital. We have plenty of technical knowledge and skill to offer for offshore wind projects, for instance. The Hywind wind farm offshore Scotland is one example of a project that is using the same spar technology as typical offshore oil and gas infrastructure. Innovation, optimization, effective use of capital and operational expenditures, more-affordable offshore technology, and excellent project management, no doubt, also will become a new normal offshore. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202911 - Harnessing Benefits of Integrated Asset Modeling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field by Yukito Nomura, ADNOC, et al. OTC 30970 - Optimizing Deepwater Rig Operations With Advanced Remotely Operated Vehicle Technology by Bernard McCoy Jr., TechnipFMC, et al. OTC 31089 - From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil by Paulino Bruno Santos, Petrobras, et al.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31284, “Greater Tortue Ahmeyim Project for BP In Mauritania and Senegal: Breakwater Design and Local Content Optimizations,” by Alexis Replumaz, Yann Julien, and Damien Bellengier, Eiffage Génie Civil Marine, prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. During summer 2017, the authors’ company was invited by BP to bid for the construction of a concrete caisson breakwater protecting an offshore liquefied natural gas (LNG) floating terminal at a water depth of 33 m on the Mauritanian/Senegalese maritime border. As a result of subsequent front-end engineering design (FEED) studies, including 3D model testing, the company was able to reduce the amount of concrete required by 40% compared with the initial design, leading to financial and environmental benefits. Introduction The BP Tortue development comprises a subsea production system tied back to a pretreatment floating, production, storage, and offloading (FPSO) unit, which transfers gas to a near-shore hub for LNG production and export. Phase 1 will provide sales gas production and domestic supply and will generate approximately 2.5 mtpa of LNG to Mauritania and Senegal. The Phase 1 FPSO, in 100–130 m of water, will process inlet gas from the subsea wells located across several drill centers by separating condensate from the gas stream and exporting conditioned gas to a hub, where LNG processing and export will occur. The hub, 10 km from shore, comprises a breakwater to protect marine operations, including LNG processing and carrier loading. A single floating LNG vessel will condition the gas for LNG export. Hub construction began early in 2019 and should be completed in 2021 for a first-gas target in 2022. The breakwater design was conceived during the bidding stage of the project at the end of 2017 by proposing an alternative design for the breakwater adapted to project-specific conditions and regional facilities. The design has been improved continuously and optimized during the FEED stage based on a collaborative approach between the client and the contractor. Client Preliminary Design Optimizations During pre-FEED and bidding stages, the client performed an intensive geotechnical campaign based on several shallow and deep boreholes and a large-area geophysical survey. In water depths greater than 18 m along the maritime boundary between Mauritania and Senegal, a significant layer of soft soil exists, except around the outcrop located on the west side (10–11 km offshore in approximately 33 m of water). Although rock quantities could be slightly higher in the western location, the reduction of the dredging quantities and the reduction of the effect on the nearby coastal community of Saint Louis (lighting, noise, and vessel traffic) led to selection of this location for the hub terminal. The initial breakwater type was a rubble-mound structure. However, a composite breakwater (caisson on berm foundation) allowed for optimization of dredging and rock quantities. The change in breakwater type allowed a rock-quantity drop from 5.8 million to 1.1 million m3.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201698, “Finding a Trend Out of Chaos: A Machine-Learning Approach for Well-Spacing Optimization,” by Zheren Ma, Ehsan Davani, SPE, and Xiaodan Ma, SPE, Quantum Reservoir Impact, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Data-driven decisions powered by machine-learning (ML) methods are increasing in popularity when optimizing field development in unconventional reservoirs. However, because well performance is affected by many factors, the challenge is to uncover trends within all the noise. By leveraging basin-level knowledge captured by big data sculpting, integrating private and public data with the use of uncertainty quantification, a process the authors describe as augmented artificial intelligence (AI) can provide quick, science-based answers for well spacing and fracturing optimization and can assess the full potential of an asset in unconventional reservoirs. A case study in the Midland Basin is detailed in the complete paper. Introduction Augmented AI is a process wherein ML and human expertise are coupled to improve solutions. The augmented AI work flow (Fig. 1) starts with data sculpting, which includes information retrieval; data cleaning and standardization; and smart, deep, and systematic data quality control (QC). Feature engineering generates all relevant parameters entering the ML model. More than 50 features have been generated for this work and categorized. The final step is to perform model tuning and ensemble, evaluating model robustness and generating model explanation and uncertainty quantification. Geology The complete paper provides a detailed geological background of the Permian Basin and its Wolfcamp unconventional layer, an organic-rich shale formation with tight reservoir properties. To find a solution for the multidimensional well-spacing problem in the Permian Basin, multiple sources and types of data were gathered using publicly available sources. The detailed geological attributes, including structure, petrophysics, geochemistry, basin-level features, and cultural information (such as counties or lease boundaries) have been combined in an integrated database to extract and generate features for the ML algorithm. Most attributes are available either in a limited number of wells, mostly vertical, or through the low number of available cored wells across the basin. Therefore, a significant amount of data imputation has been processed with mapping exercises using geostatistical modeling techniques. The mapping process augmented the ML attribute-generation step because these features were distributed in both vertical and lateral dimensions. All horizontal wells within the area of interest across the Permian Basin have been resampled with the logged and mapped information. The geological features also are reengineered into multiple indices to reduce the number of labeled features to include in the ML process. This feature-reduction process also has helped in ranking and selecting the most-important parameters relevant to the well-spacing problem. Here, a key attribute called the shale-oil index was introduced, which is generated for the ML-driven process and is used in understanding the level of contribution of geological sweet spots to well-spacing optimization. In addition, the initial well, reservoir, or laboratory data, including logs, have been normalized before mapping and modeling to eliminate potential bias. This study has focused on Wolfcamp layers; however, both geological and engineering attribute generation work flows used for this practical ML methodology to find optimization solutions for common problems are highly applicable to other unconventional layers, such as Bone Spring or Spraberry.

Description: Fluid samples collected using either wireline or logging-while-drilling (LWD) formation-testing technology for reservoir fluid characterization have long been accepted as the most representative of reservoir fluid. This, though, comes with a caveat that the collected sample is clean and devoid of any mud-filtrate contamination. With both techniques performed soon after drilling a well, there is always a risk of contaminating the collected fluid with mud filtrate. Toward the goal of reducing this risk, since the early 2000s, technologies have been brought forth to help identify the fluid down hole. There have been multiple developments with sensors for absorbance spectroscopy, fluorescence, fluid resistivity, fluid refractive index, and so on. Each sensor development was targeted toward a specific fluid interaction with the mud filtrate, thereby helping to differentiate the reservoir fluid from the mud filtrate. Downhole sampling conditions can be classified into two broad groups: one case where the reservoir fluid is miscible with the mud filtrate and the other where the reservoir fluid is not miscible with the mud filtrate. The immiscible cases are generally straightforward, since sensors such as absorbance spectroscopy can easily differentiate among oil, water, and gas. In addition, the technique can be used to determine the fractional portion of each phase in the flow. Complications arise when the reservoir fluids happen to be miscible with the mud filtrate system; for example, while sampling reservoir water in the presence of water-based mud filtrate, absorbance spectroscopy by itself is unable to differentiate among the fluids. Table 1 provides generic information about different fluid systems as well as the sensors used to differentiate the fluids. While there are other sources of correlation-based fluid-property information, the basic sensors mentioned are the ones used for correlations. As mentioned, each sensor provides detailed information for specific cases, but only sound speed provides a single-sensor solution for the conditions expected. Sound-Speed (SS) Measurement While acoustic data have long been used for reservoir characterization, data have been used for fluid characterization during downhole sampling for only a decade. Experience has shown that this measurement is sensitive enough to not only differentiate injection water or formation water but also to track and quantify small changes in oil compressibility—an important step in focused sampling. The measurement uses a pulse-echo technique based on the principle that an acoustic signal propagates approximately as a plane wave, and that the speed of sound is based on the distance the pulse travels divided by the time it took to traverse the distance. (SPWLA-2013-FFF). The 10-MHz piezoelectric transducer is mounted onto a machined flat surface on the flowline of RCX (the wireline formation testing tool reservoir characterization instrument) as schematically shown in Fig. 1. The travel path length is the distance between the two internal surfaces of the flowline. The result was a bulk measurement of the speed of sound across all the fluid flowing though the flowline. The only calibration needed is for this path length, which can differ due to slight machining variations. A calibrated sensor was able to differentiate fluids which exhibited sound-speed differences as small as 4.7 m/sec (0.5 msec/ft of sound-speed slowness).

Description: Eni Confirms Block 10 Oil Strike Offshore Mexico Eni confirmed it encountered oil shows in the Upper Miocene sequences on the Sayulita Exploration Prospect in Block 10 in the mid-deep water of the Cuenca Salina Sureste Basin. Preliminary estimates put the new find at between 150 and 200 million BOE in place. Sayulita-1 EXP is the seventh successful well drilled by Eni in the basin and the second commitment well of Block 10. It is located approximately 70 km off the coast and just 15 km away from the previous oil discovery of Saasken that will be appraised toward year-end. The well was drilled to a total depth of 1758 m by the semisubmersible Valaris 8505 in a water depth of 325 m. APA Touts Appraisal Success Off Suriname APA Corp. said its Sapakara South-1 appraisal well, located on the eastern edge of the Sapakara area, encountered approximately 30 m of net black-oil pay in a single zone of high-quality Campano-Maastrichtian reservoir. Drillship Maersk Valiant will soon mobilize to the next exploration prospect at Bonboni, about 45 km to the north, before returning later in the year to flow-test Sapakara South-1. A second appraisal well encountered two thin intervals of black oil above water in the Campano-Maastrichtian at Kwaskwasi, impacting a small portion of the eastern edge of Kwaskwasi. The Campano-Maastrichtian intervals at Kwaskwasi and the Sapakara South-1 discovery are separate and unrelated. Shell Begins Barracuda Production Shell Trinidad and Tobago, through BG International, a subsidiary of Royal Dutch Shell plc, has started production on Block 5C in the East Coast Marine Area in Trinidad and Tobago. Block 5C, known as Project Barracuda, is a backfill project with approximately 140 MMcf/D of sustained near-term gas production with peak production expected to be about 220 MMcf/D. It is Shell’s first greenfield project in the country and one of its largest in Trinidad and Tobago since the BG Group acquisition. “Today’s announcement strengthens the resilience and competitiveness of Shell’s position in Trinidad and Tobago,” said Maarten Wetselaar, director of integrated gas, renewable, and energy solutions for Shell. “This is a key growth opportunity that supports our long-term strategy in the country as well as our global LNG growth ambitions.” Eni Strikes Oil With Eban Well Off Ghana Eni has struck a significant oil discovery on the Eban exploration prospect in CTP Block 4, offshore Ghana. The Eban-1X well is the second well drilled in CTP Block 4, following the Akoma discovery. Preliminary estimates place the potential of the Eban-Akoma complex between 500 and 700 million BOE in place. The Eban-1X well is located approximately 50 km off the coast and about 8 km northwest of Sankofa Hub, where the John Agyekum Kufuor FPSO is located. It was drilled by drillship Saipem 10000 in a water depth of 545 m and reached a total depth of 4179 m. The well encountered a single light-oil column of about 80 m in a thick sandstone reservoir interval of Cenomanian age with hydrocarbons encountered down to 3949 m. Talos Lines Up Gulf of Mexico Successes Talos Energy drilled a successful sidetrack of its Crown and Anchor well at Viosca Knoll Block 960. The probe was drilled to a true vertical depth of about 13,000 ft and encountered around 50 ft of net oil pay in the M62 Middle Miocene target horizon. The project has moved to the completion phase and will produce through existing subsea infrastructure to the nearby Marlin tension-leg platform. First production is targeted by the late third quarter of 2021. Talos holds a 34% working interest in the project along with Beacon Offshore Energy (operator) and Ridgewood Crown & Anchor LLC. Greenland Calls Halt to New Oil Exploration Greenland has ended its decades-long pursuit to become an oil-producing nation after announcing 16 July it would stop granting oil and gas exploration licenses, adding that “the future does not lie in oil.” Oil exploration began for the country in the 1970s, with several major operators coming in to test the area’s prospectivity. Exploration for hydrocarbons in Greenland peaked between 2002 and 2014, when more than 20 offshore licenses were granted. Those companies that drilled walked away empty-handed. “There’s no doubt that our subsoil is rich in oil resources,” the government said in the 16 July press release. “But oil extraction won’t only have positive effects on our society, it will adversely affect our nature and environment, and may adversely affect fisheries as well as contribute to the worsening global climate crisis.”