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The objective of this study is to design and optimize the layout of the offshore wind farms to maximize the power at a specific location. The energy production of the downstream wind turbines decreases because of the reduced wind speed and increased level of turbulence caused by the wakes formed by the upstream wind turbines. Therefore, the overall power efficiency is lowered due to the wake interference among wind turbines. This paper focuses on using the application of a Gaussian-based wake model and different optimization algorithms like the differential evolution particle swarm optimization (DPSO). The Gaussian wake model uses an exponential function to evaluate the velocity deficit, in contrast to the Jensen wake model that assumes a uniform velocity profile inside the wake. The layout optimization framework has been created for the energy production in order to provide reference for specific conditions and constraints at the Gulf of Maine and other typical projects in the future.
With the growing requirement of energy and environmental protection, the sustainable energy like wind energy has been significantly concerned in recent years. In this case, the investigations about wind farm optimization have been concerned by lots of researchers. In wind farms, one of the most critical power reduction is caused by the wake and turbulence from the blades of previous turbines. Generally, this phenomenon would drop the power production and mechanical performance of turbines. The layout optimization of wind farms according to the wake has been an essential concern for both onshore and offshore wind energy applications.
Figure 1 indicates the annual average offshore wind speeds (m/s) in the United States. From this diagram, the Gulf of Maine have one of the greatest wind energy potential on the east coast. The Gulf of Maine locates very close to the cities such as Portland and Boston with magnificent electricity requirement. So, it is considerably valuable to investigate how to develop wind power in the Gulf of Maine.
Pragma is bringing the industry’s first 3D metal printed, ultrahigh expansion bridge plug to market, the Aberdeen-based company said in a press release. Its patented M-Bubble bridge plug has successfully completed final lab testing and is due to begin field trials by the end of 2020. Initially targeted at both the plug-and-abandonment (P&A) sector and water shutoff applications, the first M-Bubble addresses a gap in the market for a lower-cost, fast-turnaround, permanent plugging solution, with a high pressure differential (3,000 psi) capability, the company said. The plug can be set without additional cement to save rig time and “waiting-on-cement” time, which can accumulate significant savings for the operator, especially in deeper, extended-reach wells. It also provides barrier-integrity reassurance when there is the possibility of a poor cement bond or cement channeling occurring on the high side of deviated wells, the company added.
Yusuf, Mukminin (Mubadala Petroleum Thailand) | Prasongtham, Pattarapong (Mubadala Petroleum Thailand) | Limniyakul, Theeranun (Mubadala Petroleum Thailand) | Nuada, I Nengah (Mubadala Petroleum Thailand) | Kulchanyavivat, Sawin (Mubadala Petroleum Thailand) | Laoroongroj, Ajana (Mubadala Petroleum Thailand) | Dachanuwattana, Silpakorn (Mubadala Petroleum Thailand) | Watcharanantakul, Rattana (Mubadala Petroleum Thailand)
The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential.
Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform.
One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development.
Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges.
In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough.
In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids.
The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.
Teeratananon, Wirot (Mubadala Petroleum, Thailand Ltd.) | Thurawat, Chaiyos (Mubadala Petroleum, Thailand Ltd.) | Phaophongklai, Wattanaporn (Mubadala Petroleum, Thailand Ltd.) | Ampaiwan, Tianpan (Mubadala Petroleum, Thailand Ltd.) | Carter, Raweewan M (Mubadala Petroleum, Thailand Ltd.) | Vimolsubsin, Pojana (Mubadala Petroleum, Thailand Ltd.) | Wasanapradit, Tawan (Mubadala Petroleum, Thailand Ltd.) | Khunmek, Thanudcha (Mubadala Petroleum, Thailand Ltd.) | Tongkum, Tossapol (Mubadala Petroleum, Thailand Ltd.)
The Nong Yao field is a marginal oil field that presents many challenges, both geological (thin hydrocarbon column and structural uncertainty due to shallow gas effects) and with well design (shallow depth and unconsolidated reservoirs). The field has been on production for almost five years with water cut in most wells now over 90%. The key to extending field life is identifying new infill locations, with advanced technology required to identify and drill these targets.
To improve seismic image and structural definition, the seismic data was reprocessed in 2016, utilizing the latest technologies including Broadband Processing and Full Waveform Inversion. This detected local unswept structures and thin reservoirs allowing for identification of infill targets. New generation hydrocarbon saturation cased hole logs were run in wells to identify swept versus bypassed oil areas. Many infill opportunities required complex 3-D well trajectories and innovative completions. To achieve these objectives, technology such as high build rate rotary steerable systems, advanced real time survey corrections, a multilayer bed boundary detection tool, rotational friction transducer and inflow control devices were implemented.
After four years of production, a key well exhibited significantly more production than expected, indicating a much larger reservoir than modelled. However, water cut in this well had reached 98%, so infill wells were required in order to extend production. The reprocessed seismic indicated that the structure extended further to the east of the existing producer than initially modelled. A cased hole saturation log was acquired in an existing well drilled near the planned landing location, which showed that the reservoir was actually swept in this area. Instead, the infill well was landed and drilled in the opposite direction in this eastern part of the structure, keeping the heel away from the water, but providing a much more challenging well path. A high-build rate rotary steerable system, advanced real time survey correction and rotational friction transducer were used to safely deliver this complex 3-D well profile and avoid collision risk from offset wells. The multilayer bed boundary detection tool was then used to ensure the horizontal well stayed as high as possible whilst remaining within the reservoir. Lastly, an inflow control device was installed in the horizontal section to delay water production. The well came online with 0% water cut and is an excellent producer.
Similar methods have been adopted at other locations to identify and drill infill targets with great success. Collaboration across disciplines is key, as input is required from the geologist, geophysicist, petrophysicist, reservoir engineer, drilling engineer and completion engineer to identify, drill and produce these infill targets. Implementation of this approach continues to add new volumes and extend field life.
A new play concept is presented for the prospectivity of the Miocene of the Gulf of Hammamet (Central Mediterranean Pelagian Basin, offshore Tunisia), built upon three new elements: the role of the Langhian unconformity, the specific type of migration model, and the mechanism of tectonic inversion, based on an extensive subsurface mapping of the area, on vintage 2d and 3d and newly acquired and processed 3d seismic data using available well logs.
The sandstone reservoirs are part of the Oum Douil Group (Serravallian-Tortonian; e.g. Saouaf, Birsa, Zelfa, Somoaa, Beglia Fm’s), and are deposited in the Miocene foreland Basin which developed on the African continental margin, on top of the Langhian unconformity which shows substantial erosion of the Cretaceous-Paleocene sequences, and angular relationships as evident in seismic. We interpret this as related to a foreland bulge connected to the Early Miocene approaching of the Maghrebian (Atlas) mountain front from the North which culminated in the Late Burdigalian shortening pulse and Langhian transgression, a front that moved to the South during the Mio-Pliocene up to the Present position (Sicily-Tunisian Atlas).
Our analyses showed that important thickness variations occur in the Miocene deposits; Most of the discovered fields are related to older structural highs showing relatively thin reservoirs. Major burial occurred during the Pliocene deposition in the Jirba trough. All traps (fault bounded structures with sealing faults that in many cases reach the seafloor) are related to the Late Plio–Pleistocene tectonic pulse which inverted the thicker portion of the Miocene sediments which have become structurally higher and constitute the new prospects we identified (e.g. the Houta Prospect).
Source rocks are the Fahdene shales (Albian), deposited upon the Mesozoic rifted continental margin, and subcropping below the Langhian unconformity. Important reservoirs and regional seals exist between Fadhene Fm and Birsa Fm, making direct vertical hydrocarbon charge unlikely. Moreover, several fields show an effective regional vertical seal (Paleocene El Haria shale) between Birsa Fm and in the underlying producing Abiod limestones Fm (Upper Cretaceous). We postulate that hydrocarbons migrated through sub-cropping windows in the Langhian unconformity within the Ain Grab bioclastic limestones (deposited on top of it) as carrier beds, and that further migration occurred through juxtapositions on existing fault surfaces. This concept, new for the Miocene play in the Pelagian Basin, explains in a satisfactory way the hydrocarbon occurrences in the discovered fields.
The new play concept, which has been overlooked previously because the main exploration objectives were the deeper Mesozoic and Paleogene sequences in the structural highs, is a typical example of a New Play in an Old basin, which opens-up new hydrocarbon exploration opportunities in the Tunisian offshore area.
Ford Brett, SPE, was recognized with the 2020 American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) Presidential Citation. The award recognizes extraordinary and dedicated service to further the goals, purposes, and traditions of AIME. Brett is the CEO of PetroSkills and has consulted in more than 45 countries in petroleum process and project management. Before joining PetroSkills, he was with Amoco Production Company where he worked on drilling projects in the Bering Sea, the North Slope of Alaska, the Gulf of Mexico, offshore Trinidad, and Wyoming and led a project that first identified drill-bit whirl, which is considered as one of the 100 most significant developments in the history of the petroleum industry. In 2010, he advised the US Department of Interior as one of seven reviewers of the “30-Day Report” immediately following the BP Macondo tragedy in the Gulf of Mexico.
Offshore Gulf of Mexico (GOM) facilities remain evacuated on Thursday following the aftermath of Hurricane Zeta, while more oil and gas production has been shut in. Based on operator reports from the Bureau of Safety and Environmental Enforcement (BSEE), 228 production platforms (36% of 643 manned platforms in the GOM) remain evacuated. Personnel from two nondynamically positioned rigs remain evacuated (20% of 10), and four dynamically positioned rigs (25% of 16) remain off location. Approximately 85% of oil production and 58% of natural gas production in the Gulf is shut in, up from Wednesday’s levels of 67% and 45%, respectively.
Hurricane Zeta is intensifying as it approaches the US Gulf of Mexico coast of southeastern Louisiana, where it is expected to make landfall around 4 p.m. CST today. At 3 p.m., the National Hurricane Center reported maximum sustained winds of 110 mph with higher gusts. Today’s BSEE release based on operator reports said personnel have been evacuated from a total of 228 production platforms, 35.5% of the 643 manned platforms in the Gulf of Mexico. Personnel have been evacuated from three nondynamically positioned rigs, and six dynamically positioned rigs have been moved off location out of the hurricane’s projected path as a precaution. Approximately 66.6% of the gulf’s oil production and 44.5% of the natural gas production has been shut in.
The US Bureau of Ocean Energy Management (BOEM) has issued a final environmental impact statement (PEIS) for proposed geological and geophysical surveys of the Gulf of Mexico regarding possible oil and gas development. Because marine seismic surveys are critical in finding offshore oil and gas, The International Association of Oil and Gas Producers and the International Association of Geophysical Contractors have collaborated on a position paper that assesses the effect of such work on marine mammals.
Appomattox begins production below cost and ahead of schedule in another optimistic sign of the offshore sector’s rebound. Shell made its sixth discovery from the Norphlet formation in the deepwater Gulf of Mexico, where the firm’s newly arrived Appomattox platform just 13 miles away presents a tieback opportunity.