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TCP is a strong, noncorrosive, spoolable, lightweight technology which is delivered in long lengths, resulting in a reduction of transportation and installation costs. TCP is installed using small vessels or subsea pallets, significantly reducing CO2 emissions. It is also 100% recyclable. Strohm secured a contract with Total and ExxonMobil for a qualification-testing program for a high-pressure, high-temperature (HP/HT) thermoplastic composite pipe (TCP). The qualification project will create a foundation for further development of this TCP technology for riser applications.
Production has started on the Mahani field in Concession Area B of the Sharjah Emirate, the first startup from a new discovery onshore Sharjah in 37 years. Italian energy major Eni and the Sharjah National Oil Corporation (SNOC) made the announcement on 4 January, less than 2 years from contract signature and 1 year since announcing the partnership’s first onshore discovery. Eni said it will continue its commitment on Sharjah exploration in operated area A and underexplored area C, with the aim of securing further resources for the Sharjah Emirate. Field production is expected to increase progressively with the connection of wells to be drilled this year and next. A strategy update from Eni said the Mahani would produce 18,000 BOED gross in 2022, giving it an equity share of 9,000 BOED.
ExxonMobil announced today a list of new steps it will take to lower the oil and gas company’s emissions footprint in support of the climate goals established in the Paris Agreement. By 2025, the Irving, Texas-based company’s aim is to slash methane emissions by up to half while curbing overall upstream greenhouse-gas (GHG) emissions by up to 20%. ExxonMobil also expects to cut its flaring intensity by 35 to 45% during this same timeframe before falling in line with the World Bank initiative that has called for the elimination of routine flaring by 2030. These goals involve Scope 1 and Scope 2 emissions from the company’s operated assets. ExxonMobil said it will begin reporting its Scope 3 emissions, those stemming from the combustion of its products, each year starting in 2021, but cautioned that the newly shared figures “does not ultimately incentivize reductions by the actual emitters.”
Occidental Petroleum’s (Oxy) footprint in the UAE will almost double after the Houston-based oil producer won concession rights this week to explore an onshore area covering more than 4,200 km2 (~1625 sq mi). Oxy will assume a 100% stake in the exploration program located in the southeastern section of the emirate. Terms include a financial commitment of at least $140 million to support the program, a sum that includes a participation fee. If commercial production is achieved, the Abu Dhabi National Oil Company (ADNOC) will have the option to claim a 60% stake of the concession which expires 35 years after exploration activities begin. The award was signed off by Abu Dhabi’s Supreme Petroleum Council (SPC) following an open bidding round for Block 5.
Unconventional and mature field cementing operations in Argentina present challenges through intermediate and production sections. Typically, challenges are associated with specific formation geologic properties, e.g., naturally fractured rock combined with high-reservoir pressure and depleted sandstones. The formation gradients require better control over equivalent-circulation densities (ECD) during cementing to mitigate risk of lost circulation (LC). Such issues can lead to poor zonal isolation, sustained-casing pressure (SCP), and increased costs. Described herein is a new tailored spacer system engineered to mitigate LC during cementing and its use in a field application to reduce risks of LC and improve zonal isolation in a loss-prone formation.
Lost circulation (LC) is one of the largest contributors to non-productive time (NPT) and overall cost of well construction operations. Fluid losses may occur via natural formation thief zones, e.g. permeable, fractured, or vugular sections, through unconsolidated or highly depleted wells. LC thief zones may also be encountered when induced by exceeding fracture gradients of the formation during operations, thus breaking down the wellbore. When risks of inducing fractures are present, careful management of fluid properties and equivalent circulating density (ECD) are necessary. LC may occur under a range of conditions and loss rates, including seepage (up to 10 bbl/hr), partial (10- 100 bbl/hr), severe (100–500 bbl/hr), and total (no returns) (Nayberg, 1987; Nelson, 2006).
In drilling and cementing operations, LC is commonly encountered, and can be particularly harmful to zonal isolation. Efforts should be made to arrest LC during the drilling phase, prior to cementing; however, losses may persist. When LC is experienced during primary cementing and left untreated, zonal isolation may be compromised, and cementing objectives may not be met, including the inability to achieve planned top of cement (TOC). Not achieving TOC in cementing potentially results in a failure to isolate critical sections and/or meet regulatory specifications, leading to added operational time and cost to remediate.
Cementing slurry designs are subjected to hydraulic simulations to optimize pump rates with minimized ECD; however, additional mitigations may be necessary to reduce risks of LC during cementing. Like drilling practices, these may include use of LC materials exhibiting various sizes and morphologies, amongst other properties in fluid formulations, to plug or bridge thief zones and stop fluid losses.
The Abu Dhabi National Oil Company (ADNOC) completed the first phase of its large-scale multiyear predictive maintenance project to improve asset efficiency and integrity across its upstream and downstream operations. Announced in November 2019, the project is being implemented over four phases as part of the company’s digital acceleration program to embed advanced digital technologies across its operations. Phase 1 covers the modeling and monitoring of 160 turbines, motors, centrifugal pumps, and compressors across six ADNOC Group companies. All phases of the project are expected to be completed by 2022 and will enable monitoring of up to 2,500 critical machines. Using artificial intelligence (AI) technologies including machine learning and digital twins, the company’s predictive maintenance platform helps with equipment stoppages, reduces unplanned equipment maintenance and downtime, increases reliability and safety, and is expected to deliver maintenance savings up to 20%.
UAE Has Become World's Newest Producer Of Unconventional Gas The United Arab Emirates (UAE) has become the latest country to prove that the unconventional oil and gas sector is becoming firmly an international one. This comes as the Abu Dhabi National Oil Company (ADNOC) and its French partner Total announced today the first delivery of unconventional gas from a jointly operated onshore field in the UAE. ADNOC said the gas delivery represents a major advance toward the company’s goal of producing 1 Bcf/D by 2030, enough to meet all the UAE’s domestic natural-gas demand. The shale-gas field where ADNOC and Total hope to accomplish this is known as the Ruwais Diyab Unconventional Gas Concession and is located almost 125 miles from Abu Dhabi. The companies said they used a fast-track approach to expedite the midstream components needed to move the gas from the greenfield to existing processing facilities.
Mubashir Ahmad, Mubashir (ADNOC Onshore) | Zain Yousfi, Fawad (ADNOC Onshore) | Albadi, Mohamed (ADNOC Onshore) | Baslaib, Mohamed (ADNOC Onshore) | Alhouqani, Shamsa (ADNOC Onshore) | Olatunbosun, Ibukun (ADNOC Onshore) | Agarwal, Anubhav (ADNOC Onshore) | Ahmad, Zeeshan (ADNOC Onshore) | Al Hosani, Abdulla (ADNOC Onshore) | Pendyala, Viswasri (ADNOC Onshore) | Mandal, Chandra (ADNOC Onshore) | Gadelhak, Abdelrahman (ADNOC Onshore) | Shaker, Ashraf (ADNOC Onshore) | Alsaeedi, Ayesha (ADNOC Onshore) | Elabrashy, Manar (ADNOC Onshore) | Alzeyoudi, Mohamed (ADNOC Onshore) | Alsenaidi, Shemaisa (ADNOC Onshore) | Al Muhairi, Bakheeta (ADNOC Onshore) | Al Bairaq, Ahmed (ADNOC Onshore) | Yugay, Andrey (ADNOC Onshore) | Pimenta, Gervasio (ADNOC Onshore) | Al Jeelani, Omar (ADNOC Onshore) | A Basioni, Mahmoud (ADNOC-Upstream) | Sayed, Sohdy (ADNOC-Upstream) | Yahya Al Blooshi, Ahmed (ADNOC-Upstream) | Mahmoud Elmahdi, Ahmed (ADNOC-Upstream) | Edouard Maktouf, Soufiene (ADNOC-Upstream) | Al Mansoori, Ali (ADNOC-Upstream) | Ali Alloghani, Jasim (ADNOC-Upstream)
ADNOC onshore recently tested HPHT sour gas reservoirs with +30% H2S, +10% CO2 to evaluate the reservoirs and well potential as part of the efforts in supplying additional gas for meeting country's growing energy needs. Developing these massive HPHT sour gas reservoirs is essential for providing a sustainable source of energy for years to come.
Saradva, Harshil (Sharjah National Oil Corporation) | Jain, Siddharth (Sharjah National Oil Corporation) | Golaco, Christna (Sharjah National Oil Corporation) | Su, Shi (Schlumberger) | Amtereg, Ahmed (Schlumberger Overseas S.A) | Mustapha, Hussein (Schlumberger)
Sharjah National Oil Corporation (SNOC) operates three onshore reservoirs in the Emirate of Sharjah. The reservoir simulation models use compositional modelling to capture the fluid dynamics in mature, low porosity highly fractured gas condensate fields. The scope of this project was to improve the reservoir characterization by investigating and overcoming lack of water production in compositional models for effective EOR and gas storage strategies. Water cut of 30%+ comprised of a combination of produced and condensed water in a reservoir with no active aquifer, thus posing a modelling challenge combined with a lack of comprehensive historical PVT data.
All existing PVT reports in the database were retrieved and a comprehensive quality check was performed. The best possible PVT results for each field were short-listed and taken as reference datasets for validating the compositional EoS in a depleted field. A new EOS was generated for these fields based on legacy PVT data combined with 38+ years of production data. A shortfall of this new EOS was the inability to produce condensed water as observed in the field with Chloride counts less than 1500 ppm. To rectify this low water production mismatch, a blind test was conducted introducing water as a component in the EoS in the simulation model to see the effect. Moreover, extensive scale problems in any of the wells of 30-year-old mature assets leading to regular interventions never occurred in the asset's operational history.
As expected, mobility of the fluids in the system had changed and low salinity condensed water was seen to have a good match. Liberated water was traced at the surface to confirm water production rate of the same order of magnitude as observed in production data. Due to overwhelming water production rates from the trial test, SNOC decided to perform a comprehensive extended PVT study. The naturally fractured carbonates were subjected to geological and material balance study and the data indicated an absence of active aquifers, which made it difficult to match observed water production in simulation models. To effectively plan future EOR projects like gas storage, it was necessary to model the effects of water and its interaction with injected fluids in the reservoir while honouring low water movement in the subsurface.
The paper provides a novel workflow for generation of the compositional equation of state with water as a component in retrograde condensate fields. The workflow followed the lumping of hydrocarbon components to minimise runtime and capture maximum possible fluid dynamics in the reservoir without compromising the fluid properties observed in the PVT lab. It was also vital for the simulation model to honour the production history spanning over three decades. It also highlights the ability and importance of including water as an EOS component to effectively capture the condensed water in the reservoirs that many works of literature and simulators are unable to provide insight on.
The Jurassic stratigraphy of the Middle East includes the world's most economically significant petroleum systems, containing multiple world-class source, reservoir and seal packages. Yet in a regional context, these depositional systems are still not fully understood, leading to inconsistencies in lithostratigraphic nomenclature across international boundaries and misconceptions in the stratigraphic architecture limiting exploration and production success. We have applied sequence stratigraphic principles across the Jurassic strata of the eastern Arabian Plate to increase stratigraphic understanding and resolve some of the common misconceptions. This provides a robust age-based framework to reduce lithostratigraphic uncertainty across international boundaries and provides predictive capabilities into the temporal and spatial distribution of source, reservoir, and seal facies.
Herein, we focus on one of these stratigraphic misconceptions, which deals with the development and sedimentary infill of the Late Jurassic Gotnia Basin, and its relationship with the aggrading platform of the Rimthan Arch. Our literature based re-interpretation proposes a mostly eustatically driven control, whereby the shallow water platform of the Rimthan Arch followed sea level rise, and the Gotnia Basin became a starved intra shelf basin. This revised stratigraphic interpretation has important consequences for the lateral facies relationships, and overall tectono-sedimentary understanding of the area, as well as for the petroleum habitat.