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_ Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed. For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess. From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the countryโs offshore oil and gas footprint has grown significantly, with todayโs production from the pre-salt Campos and Santos basinsโlocated farther from shore and in much deeper waterโlaunching state-run oil company Petrobras to a top spot among the ranks of global producers. The ongoing development of its offshore fields will continue to boost the countryโs oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output. The fifth oneโthe FPSO Sepetibaโdelivered a New Yearโs Day surprise when it came online at Mero 2 oil field on 31 December 2023. HISEP, a new subsea technology currently being readied for pilot testing, could potentially ensure continued future production of the Mero field and others by capturing CO2-rich dense gases directly from the wellstream and reinjecting it into the reservoir. The technology also frees up much-needed space and reduces weight on the FPSOโs topside by moving the separation process to the seafloor. Challenges and Solutions Brazilโs challenging offshore pre-salt regionโfirst explored by Petrobras in 2005โcontains estimated reserves of 30 to 40 billion BOE and comes with an extensive list of development challenges. Its Santos Basin, for example, lies in ultradeep water with hydrocarbon reservoirs located at extreme depths ranging from 5500 to 7600 m below sea level and under salt layers more than 2000 m thick. But the challenges do not end there. Managing the basinโs high gas/oil ratio (GOR) and CO2 content leaves a significant operational footprint. In OTC 29762, authors from Petrobras noted that developing the pre-salt reservoirs requires โlarge production facilities with complex gas processing plants that limit the oil processing and storage capacities.โ In the paper presented at the 2019 Offshore Technology Conference (OTC) Brasil, the authors said that the gas processing plants for some pre-salt fields with high production indexes, GOR, and CO2 content account for nearly 60% of the total FPSO topsides area. The Santos Basin is home to the Mero oil field, the countryโs third-largest pre-salt field and the first under a production-sharing contract awarded to the Petrobras-led Libra Consortium. The field is considered one of the largest hydrocarbon discoveries in the past decade, covering about 320 km of the Libra block and with a net pay zone reaching 420 m filled with 29 ยฐAPI oil and high productivity, according to Ana Luiza Neder, et al. (OTC 32784).
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.91)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Libra Block > Mero Field (0.99)
- South America > Brazil > Alagoas > South Atlantic Ocean > South Atlantic Ocean > Sergipe-Alagoas Basin (0.99)
- South America > Brazil > Alagoas > Sergipe > South Atlantic Ocean > Sergipe-Alagoas Basin (0.99)
- (2 more...)
_ The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Fig. 1), thereby providing unprecedented levels of energy security for America. Americaโs doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out โdirtierโ forms of energy, such as coal. Energy securityโeconomic growthโreduced GHGs vented to the atmosphere: Thatโs a winning combination. One that America and many other countries have benefitted from immensely. Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all. This oversight caused many companies to wait too long before deciding to pursue unconventional reservoirs and caused several of the โshale gasโ pioneers to be late in recognizing that hydraulically fractured horizontal wells (HFHWs) could also be successfully applied in liquid-rich plays such as the Eagle Ford and Permian Basin. These are plays that today deliver far more value than that derived from the gas-prone reservoirs that comprised the initial suite of targets. And while events have proven beyond a doubt that HFHWs are a powerful tool for economically extracting hydrocarbons from both gas-prone and liquids-rich unconventional reservoirs, it seems likely that many in our industry are overlooking a third significant application of this technology: The use of HFHWs to extract heat from the Earthโs crust that can be utilized to generate electricity. Old Story, New Horizon What makes this third application particularly compelling as an investment opportunity is that the primary physical challenge that needs to be overcome to achieve attractive rates of return is strikingly similar to that which the oil and gas industry had to surmount to make both gas and liquids-rich unconventional reservoirs economic. The key to success in all of these cases boils down to an ability to create via hydraulic stimulation a sufficiently large amount of conductive, connected, fracture surface area. With this, one can reliably expect per-well production rates to be economic given the extremely slow rate at which hydrocarbonsโand heatโmove through unconventional reservoirs and the hot, dry, basement rocks that contain the bulk of the worldโs geothermal resources. That converting from vertical to horizontal well geometries was critical for unlocking the potential of unconventional hydrocarbon reservoirs is now obvious, with this switch having allowed petroleum engineers to increase per-well fracture surface areas by several orders of magnitude. This move increased per-well flow rates by similar amounts (i.e., from subeconomic flow rates from hydraulically fractured vertical wells (HFVWs) to flow rates of thousands of BOE/D from HFHWs.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- Energy > Renewable > Geothermal > Geothermal Resource (0.35)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.89)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.89)
- (25 more...)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212615, โReservoir Modeling To Predict the Effect of Cold-Water Injection in Geothermal Pressure Transient Analysis,โ by Purnayan Mitra, SPE, University of Petroleum and Energy Studies, and Nihal Mounir Darraj, SPE, Imperial College London. The paper has not been peer reviewed. _ Geothermal reservoirs are one of the cleanest renewable sources of energy poised to address the global energy challenge. A major issue in the exploitation of geothermal reservoirs, however, is to find best-fit analytical methods for pressure transient analysis (PTA). This is because the assumptions made to predict PTA in hydrocarbon reservoirs are not satisfied by geothermal reservoirs. In the complete paper, the effect of cold-water injection on PTA of geothermal reservoirs is studied by varying the temperature of the injected cold water from room temperature to reservoir temperature. Introduction A major method of extracting heat energy from the Earth is the injection of water. Cold water is injected deep into geothermal reservoirs at a depth of 2โ4.5 km. In this environment, cold water is essentially heated by the hot granite rock. Hydraulic fracturing is used to produce a large crack within the geothermal reservoir. Two boreholes intercept the crack. These boreholes are used for passing the cold fluid stream and the hot stream, respectively. In many scenarios, the gradient within the geothermal reservoir is so strong that a dry stream is produced. The greater the temperature difference between the injected fluid and the interior of the Earth, the greater the heat transfer. Therefore, it is always desirable to inject cold water inside geothermal reservoirs to maximize heat transfer and extract more heat. The steam coming out from the reservoir after heat transfer is used to run turbines to generate electricity. The steam also is used for a variety of other purposes. However, instances exist in which the temperature gradient is not as high, and it is difficult to produce a sufficiently heated dry stream. In such cases, an organic Rankine cycle is used for heating the steam on the surface. In such a case, the hot water or steam mixture is passed through a heat exchanger for heating the fluid to a desired temperature. When cold water is injected into the reservoir, a need exists to analyze the pressure transience throughout the reservoir. Different formations affect PTA in different ways. PTA across the geothermal reservoir currently is performed using the empirical correlations available for hydrocarbon reservoirs. Although the method is not 100% effective because of differences in reservoir parameters, PTA provides an idea about reservoir conditions. To reduce imperfection, it is often preferred to use reservoir parameters rather than injectate properties. In the complete paper, the authors study the effect of injected water on geothermal reservoirs while varying temperature from 14 to 312ยฐC.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215454, โEnhancing Well-Control Safety With Dynamic Well-Control Cloud Solutions: Case Studies of Successful Deep Transient Tests in Southeast Asia,โ by M. Ashraf Abu Talib, SPE, M. Shahril Ahmad Kassim, and Izral Izarruddin Marzuki, SPE, Petronas, et al. The paper has not been peer reviewed. _ The complete paper addresses challenges related to well control and highlights the successful implementation of deep transient tests (DTT) in an offshore well performed with the help of a dynamic well-control simulation platform. The paper aims to provide insights into the prejob simulation process, which ensured a safer operation from a well-control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation is presented. DTT DTT is a formation-testing (FT) method that allows pressure transient tests that reach deeper into the formation compared with conventional interval pressure transient tests (IPTT). DTT enables the testing of formations with higher permeability, greater thickness, and lower viscosity and real-time measurement of crucial parameters. During a DTT, formation fluid is pumped from the reservoir; upon stopping the pump, the formation pressure begins to recover as fluid further from the wellbore replaces the extracted fluid. By analyzing the resulting pressure transient, properties such as formation permeability, permeability anisotropy, and other characteristics can be determined. DTT allows for a better understanding of reservoir characteristics and rock heterogeneity. When properly designed and executed, DTT can reveal potential baffles and boundaries within the radius of investigation. A further advantage of DTT over drillstem tests (DST) is its minimal fluid flow, which allows for the attainment of objectives while contributing to the United Nations sustainable development goals. In DTT operations, the FT tool is connected to the drillpipe through a circulating sub and a slip joint. The circulating sub plays a critical role in DTT operations because it enables the continuous mixing of pumped formation fluid with circulated mud and facilitates its transportation to the surface (Fig. 1). Typically, a constant circulation rate ranging from 100 to 250 gal/min is maintained. During circulation, the annular preventer is closed and the mud/hydrocarbon mixture is directed through the choke line to the mud/gas separator (MGS) once it reaches the surface. No formation fluids are flared during DTT operations. Instead, the circulated oil is retained in the mud and only small amounts of gas are vented. By use of a slip joint, the FT remains anchored to the borehole wall. A high-resolution pressure gauge is used to capture and interpret even minor pressure fluctuations during the pressure transient buildup.
- Energy > Oil & Gas > Upstream (0.63)
- Government > Regional Government (0.39)
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin (0.99)
The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Figure 1), thereby providing unprecedented levels of energy security for America. America's doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out "dirtier" forms of energy, such as coal. Energy security--economic growth--reduced GHGs vented to the atmosphere: That's a winning combination. One that America and many other countries have benefitted from immensely. Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.89)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.89)
- (25 more...)
Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed. For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess. From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the country's offshore oil and gas footprint has grown significantly, with today's production from the preโsalt Campos and Santos basins--located farther from shore and in much deeper water--launching state-run oil company Petrobras to a top spot among the ranks of global producers. The ongoing development of its offshore fields will continue to boost the country's oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output.
- South America > Brazil > Sergipe > South Atlantic Ocean (0.48)
- South America > Brazil > Alagoas > South Atlantic Ocean (0.48)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.33)
- South America > Brazil > Brazil > South Atlantic Ocean (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.32)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Libra Block > Mero Field (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- South America > Brazil > Alagoas > South Atlantic Ocean > South Atlantic Ocean > Sergipe-Alagoas Basin (0.99)
- South America > Brazil > Alagoas > Sergipe > South Atlantic Ocean > Sergipe-Alagoas Basin (0.99)
- North America > United States > Oklahoma (0.19)
- North America > United States > Illinois (0.19)
- Africa > Middle East > Egypt (0.19)
- North America > United States > Oklahoma > Arkoma Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > Kentucky > Illinois Basin (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.62)
- Well Drilling > Pressure Management > Well control (0.39)
Machine-learning application to assess occurrence and saturations of methane hydrate in marine deposits offshore India
Chong, Leebyn (National Energy Technology Laboratory, NETL Support Contractor) | Collett, Timothy S. (U.S. Geological Survey) | Creason, C. Gabriel (National Energy Technology Laboratory) | Seol, Yongkoo (National Energy Technology Laboratory) | Myshakin, Evgeniy M. (National Energy Technology Laboratory, NETL Support Contractor)
Abstract Artificial neural networks (ANN) were used to assess methane hydrate occurrence and saturation in marine sediments offshore India. The ANN analysis classifies the gas hydrate occurrence into three types: methane hydrate in pore space, methane hydrate in fractures, or no methane hydrate. Further, predicted saturation characterizes the volume of gas hydrate with respect to the available void volume. Log data collected at six wells, which were drilled during the India National Gas Hydrate Program Expedition 02 (NGHP-02), provided a combination of well-log measurements that were used as input for machine-learning (ML) models. Well-log measurements included density, porosity, electrical resistivity, natural gamma radiation, and acoustic wave velocity. Combinations of well logs used in the ML models provide good overall balanced accuracy (0.79 to 0.86) for the prediction of the gas hydrate occurrence and good accuracy (0.68 to 0.92) for methane hydrate saturation prediction in the marine accumulations against reference data. The accuracy scores indicate that the ML models can successfully predict reservoir characteristics for marine methane hydrate deposits. The results indicate that the ML models can either augment physics-driven methods for assessing the occurrence and saturation of methane hydrate deposits or serve as an independent predictive tool for those characteristics.
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin (0.99)
- North America > United States > Alaska (0.89)
- North America > Canada (0.89)
Oil and gas reserves are so far the world's most dominant energy sources. Production is predominantly coming from mid- and late-life fields, and this trend will continue well over the next decade. As mature field contribution increases, oil and gas operators and oilfield services (OFS) companies are relying even more on stimulation treatments to meet the global energy demand. However, reservoir performance is a major challenge, with one in three remedial operations failing to meet the objectives of incremental barrels. This creates a double jeopardy in which both the expected returns on the stimulation investment and reservoir production do not fulfill the projected potential.