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Rubach, S., and I. F. Saur. "Onshore testing of produced water by electroflocculation." Filtration & Separation 34, no. 8 (October 1997): 877–82. http://dx.doi.org/10.1016/s0015-1882(97)81411-5.
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Wilson, Adam. "Produced-Water Reinjection - Case Study From Onshore Abu Dhabi." Journal of Petroleum Technology 68, no. 12 (December 1, 2016): 72–73. http://dx.doi.org/10.2118/1216-0072-jpt.
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Liu, Zhong Min, Yong Qing Jin, Guo Qing Yuan, and Malcolm J. Law. "The Treatment and Disposal of Produced Water from Onshore Oilfields." Applied Mechanics and Materials 361-363 (August 2013): 567–73. http://dx.doi.org/10.4028/www.scientific.net/amm.361-363.567.
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As the worldwide demand for crude oil and gas increases and the oilfields age, the annual production of produced water is rising dramatically. Environmental restrictions on the disposal of this waste water have become more stringent in recent years with the result that disposal costs are also raising rapidly. This paper examines the various options for the treatment of this produced water prior to its disposal together with the possible consequences of getting it wrong, such as corrosion and scaling of process piping and equipment, together with fouling of the oilfield rock formation and disposal wells.
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Feder, Judy. "Reuse of Produced Water Grows in the Oil and Gas Industry." Journal of Petroleum Technology 72, no. 12 (December 1, 2020): 60–61. http://dx.doi.org/10.2118/1220-0060-jpt.
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This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199498, “Reuse of Produced Water in the Oil and Gas Industry,” by Madeleine Gray, International Petroleum Industry Environmental Conservation Association, prepared for the 2020 SPE International Conference and Exhibition on Health, Safety, Environment, and Sustainability, originally scheduled to be held in Bogota, Colombia, 28-30 July. The paper has not been peer reviewed. The onshore oil and gas industry investigates new and improved ways to manage the supply and disposal of produced water continually. Within oil and gas operations, produced water increasingly is being recycled and reused for enhanced oil recovery, drilling, and well stimulation. The growing global demand for water resources also is creating interest in reusing produced water outside oil and gas operations. The complete paper focuses on sources of produced water from conventional and unconventional onshore oil and gas operations and addresses the challenges and opportunities associated with reusing the produced water. Introduction Produced water is water that is brought to surface during oil and natural-gas production. It includes formation, flowback, and condensation water. Produced water varies in composition and volume from one formation to another and is often managed as a waste material requiring disposal. In recent years, increased demand for, and regional variability of, available water resources, along with sustainable water-supply planning, have driven interest in reusing produced water with or without treatment to meet requirements within the industry or by external users. Reuse of produced water can provide important economic, social, and environmental benefits, particularly in water-scarce regions. It can be used for hydraulic fracturing, waterflooding, and enhanced oil recovery, decreasing the demand for other sources of water. However, reuse for offsite, non-oilfield applications such as crop irrigation, wildlife and livestock consumption, industrial processes, and power generation, is subject to a variety of constraints and risks. Practical considerations for offsite reuse include supply and demand and regulatory, infrastructural, economic, legal, social, and environmental factors. Sources, Chemical Properties, and Management of Produced Water The information contained in the paper is based on an internal survey conducted by the International Petroleum Industry Environmental Conservation Association (IPIECA) of 14 of its member companies, interviews with selected external stakeholders covering a range of sectors and geographic regions, and a literature review of readily available information. The external stakeholders were identified from the membership survey as well as from IPIECA and consultant experience. Sources and Volumes. Onshore oil and gas operations generate millions of barrels of produced water each day world-wide. The composition and flow of produced water can differ dramatically from one source to another.
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Edalat, Arian, and Eric M. V. Hoek. "Techno-Economic Analysis of RO Desalination of Produced Water for Beneficial Reuse in California." Water 12, no. 7 (June 28, 2020): 1850. http://dx.doi.org/10.3390/w12071850.
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There is approximately 508.7 million cubic meters (3.2 million barrels) of oilfield-produced water generated per year across the oil fields of California. While less than 2% of this produced water receives advanced treatment for beneficial reuse, changing regulations and increasing scarcity of freshwater resources is expected to increase the demand for beneficial reuse. This paper reviews onshore-produced water quality across California, relevant standards and treatment objectives for beneficial reuse, identifies contaminants of concern, and treatment process design considerations. Lastly, we evaluate the capital and operating costs of an integrated membrane system for treating produced water based on data from a field pilot conducted in the coastal region of California.
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Bilstad, T., and E. Espedal. "Membrane separation of produced water." Water Science and Technology 34, no. 9 (November 1, 1996): 239–46. http://dx.doi.org/10.2166/wst.1996.0221.
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Each time regulatory agencies initiate more stringent environmental controls, treatment technologies are refined to meet the updated standards. Centrifuges and hydrocyclones are, by and large, producing satisfactory effluents for meeting current quality requirements for the offshore petroleum industries. The European standard for effluent from onshore petroleum activities, however, requires less than 5 mg/l total hydrocarbons (HC) and less than 10 mg/l suspended solids. Such low concentrations are out of reach for the above classical separation processes. The amount of produced water in the North Sea is projected to increase by a factor of 6 from 1990 to the year 2000; from 16 to 90 million cubic meters each year. Produced water is the predominant source for oil discharges. The synergistic effects of chemicals, oil and dissolved components in the produced water effluent are given increased attention, with expectations of tougher effluent criteria. Microfiltration (MF) and ultrafiltration (UF) pilot trials with produced water from the Snorre field in the North Sea showed that UF, but not MF, could meet more stringent effluent standards for total HC, suspended solids and dissolved constituents. Total HC in the produced water was typically 50 mg/l and was reduced to 2 mg/l in the UF permeate (96% removal). The aromatics benzene, toluene and xylene (BTX) were similarly reduced by 54% and the heavy metals copper (Cu) and zinc (Zn) by 95%. UF trials were performed with organic tubular membranes with typical transmembrane pressures between 6 and 10 bars. The feed velocities through the tubes were between 2 and 4 m/s. Flux varied from 140 to 550 l/m2/h (lmh) at a produced water temperature of 60°C and membrane molecular weight cut-off between 100,000 and 200,000 daltons. By recirculating UF retentate as membrane feed, a volume reduction (VR) of 24 was obtained in the trials; i.e., 96% permeate recovery. The limited volume of produced water available in the feed tank negated further volume reduction. Full-scale design is based on permeate recovery of 99%. No irreversible fouling of the membrane surface was experienced. The cleanwater flux was restored after chemical cleaning. The alkaline detergent Ultrasil 11 was chosen as the optimal cleaning agent.
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Dantas de Assunção, Marcus Vinicius, Mariana Almeida, and Prof Dra Marcela Marques Vieira. "Environmental Dynamic Efficiency Of Onshore Oil Fields Located At The Brazilian Coastal Basin." International Journal for Innovation Education and Research 8, no. 7 (July 1, 2020): 135–51. http://dx.doi.org/10.31686/ijier.vol8.iss7.2462.
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One of the main environmental concerns associated with the exploration and production of oil fields is related to the generation of produced water, this is a strategic challenge for companies since is resposible for the largest share of waste genretared by the oil industry. This theme is presented as multidisciplinary since it is a study with dynamic models in an environmental area linked to the oil industry. Thus, the present work aims to evaluate the performance of dynamic environmental sustainability, from the generation of produced water from onshore oil fields located at the coastal basins of Brazil with higher oil production. The data were made available by the ANP (National Petroleum Agency) from its website, totalizing 67 fields during the years 2014, 2015 and 2016. In addition, dynamic Data Envelopment Analysis was used to determine dynamic efficiency. The results showed a positive effect of the variables directional wells, vertical wells and age, the first two variable showed a fundamental role in determining environmental efficiencies. Therefore, the results allowed to state that there is a poor management of the technological resources in onshore fields of the Brazilian coastal basins, generating excessive amounts of produced water.
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Yaqub, Asim, Mohamed Hasnain Isa, Shamsul Rahman Mohamed Kutty, and Huma Ajab. "Kinetic Study of PAHs Degradation in Produced Water Using Ti/RuO2 Anode." Applied Mechanics and Materials 567 (June 2014): 80–85. http://dx.doi.org/10.4028/www.scientific.net/amm.567.80.
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Oil production offshore and onshore results in production of huge amount of water, called produced water (PW). PW is one of source of polycyclic aromatic hydrocarbons PAHs to the aquatic environment. Degradation kinetics of 16 priority PAHs were studied in PW treatment using Ti/RuO2anode in a batch setupat three different current densities 3.33, 6.67 and 10 mA/cm2. GC-MS was used for quantification of each PAH. Kinetics study confirmed that electrochemical degradation of all PAHs had follow first-order kinetic using Ti/ RuO2. Results showed that values of rate constantkwere increase by increasing current density.
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Hampson, Mathew, Heather Martin, Lucy Craddock, Thomas Wood, and Ellie Rylands. "The Elswick Field, Bowland Basin, UK Onshore." Geological Society, London, Memoirs 52, no. 1 (2020): 62–73. http://dx.doi.org/10.1144/m52-2017-29.
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AbstractThe Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.
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Osipi, Sara R., Argimiro R. Secchi, and Cristiano P. Borges. "Cost assessment and retro-techno-economic analysis of desalination technologies in onshore produced water treatment." Desalination 430 (March 2018): 107–19. http://dx.doi.org/10.1016/j.desal.2017.12.015.
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Oliveira, Edkarlla Sousa Dantas de, Roseana Florentino da Costa Pereira, Ivanilda Ramos de Melo, Maria Alice Gomes de Andrade Lima, and Severino Lepoldino Urtiga Filho. "Corrosion Behavior of API 5L X80 Steel in the Produced Water of Onshore Oil Recovery Facilities." Materials Research 20, suppl 2 (October 9, 2017): 432–39. http://dx.doi.org/10.1590/1980-5373-mr-2016-0954.
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Wybrew, Paul. "Zero Waste Well – the beneficial use of produced water from CSG projects." APPEA Journal 59, no. 2 (2019): 756. http://dx.doi.org/10.1071/aj18253.
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Most onshore gas provinces in Australia are in remote locations where it is expensive to bring materials to, and take waste away from, well sites. Importantly, water is not only an input to, and a product of, the drilling, completion, construction and production process, it is also a precious resource. That is why Santos has been working towards the ‘Zero Waste Well’. Historically, separate drilling, completion, construction and operational teams were involved in sourcing and disposing of water without taking a holistic view of the water cycle. By taking a collaborative approach and looking at the complete water cycle, Santos has been able to reduce its water use and eliminate wastewater by reusing all of the produced water in its Queensland coal seam gas upstream activities for beneficial purposes. As part of the Zero Waste Well concept, Santos has identified and implemented a range of initiatives for beneficially reusing produced water. These include stock watering, construction, dust suppression, rehabilitation, and drilling and completion activities. One of the most exciting innovations is to beneficially reuse produced water for localised irrigation. This avoids or minimises the need for large centralised water gathering systems and large static centralised water storages and treatment plants. This also minimises the environmental footprint, energy intensity, carbon emissions and brine wastes from Santos’ activities. Localised irrigation not only reduces construction and operating costs, and engineering design and construction timeframes for Santos, it provides a valuable pasture irrigation source for local landholders.
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Salahel Din, Khaled, and Wafaa Rashed. "ASSESSMENT OF NORM LEVELS AND RADIOLOGICAL HAZARDS FROM PETROLEUM EXTRACTION IN THE ONSHORE OIL FIELDS, EGYPT." Radiation Protection Dosimetry 194, no. 4 (May 2021): 223–32. http://dx.doi.org/10.1093/rpd/ncab099.
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Abstract Forty-nine different samples (crude oil, surface soil, produced water and sludge) from onshore oil fields in the Western Desert of Egypt were assessed for naturally occurring radioactive material (NORM) levels using HPGe gamma-ray spectrometer. The average activity concentrations of 226Ra, 232Th and 40K were 25 ± 1.3, 26 ± 1.0 and 21 ± 1.5; 9.8 ± 0.50, 11 ± 0.40 and 94 ± 6.9; 130 ± 6.6, 91 ± 3.4 and 41 ± 3.0; and 180 ± 16, 70 ± 6.9 and 1300 ± 110 Bq kg−1 for crude oil, surface soil, produced water and sludge, respectively. The obtained NORM levels are much below the International Atomic Energy Agency NORM clearance levels. Radiological parameters (radium equivalent activity, absorbed dose rate and annual effective dose) were calculated and compared with the international acceptable limits. The annual effective doses are below 1 and 20 mSv, the ICRP safety limits for the public and workers, respectively. Consequently, insignificant radiological hazards could present for the workers and surrounding environment from petroleum extraction activities in the studied area.
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Torres, Luisa, Om Prakash Yadav, and Eakalak Khan. "A review on risk assessment techniques for hydraulic fracturing water and produced water management implemented in onshore unconventional oil and gas production." Science of The Total Environment 539 (January 2016): 478–93. http://dx.doi.org/10.1016/j.scitotenv.2015.09.030.
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Webster, Brian D., Holly Churman, Chris Benjamin, Julian Long, and Brett M. Goebel. "From the Beetaloo to West Texas: similarities, differences and lessons learned from water management in coal seam and shale field developments on either side of the Pacific." APPEA Journal 59, no. 2 (2019): 827. http://dx.doi.org/10.1071/aj18144.
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Water management presents a host of challenges and opportunities for operators developing unconventional onshore gas fields. Water supply, recycling and disposal issues affect each stage of field development and operation. Sourcing water and production of produced and flow back water has important implications for water availability and management of the unique environmental risks. All water source and produced water decisions come with costs. From the treatment and reuse of coal seam gas (CSG) produced water, through to the storage and ultimate disposal of water containing elevated salinity and organic loads in shale fields, the costs for water management fundamentally contribute to the economics of unconventional gas developments. In this paper, we will draw on experience in both CSG and shale field water management to compare the respective water management challenges and opportunities faced by operators in these industries. A series of case studies will be used to highlight the differences between the CSG and shale fields. This will include assessment of a West Texas shale field development, where field specific data, such as well-to-well distance and travel time between them, has been used to identify and compare produced water management options. We will use these indicators to demonstrate how alternative ways to assess produced water options, based on economics, can reveal creative management strategies that achieve a variety of goals at every stage of field development, including maximising reuse and minimising disposal.
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Hayes, John J. "BASS STRAIT WATER HANDLING DEVELOPMENTS." APPEA Journal 25, no. 1 (1985): 114. http://dx.doi.org/10.1071/aj84009.
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Esso Australia Ltd operates, on behalf of Esso/BHP, a crude oil and natural gas producing and processing facility in the Gippsland Basin, Victoria. Saline formation water produced with the oil is treated and discharged overboard from offshore platforms wherever possible to limit the volume of saline water in the pipeline system and avoid onshore disposal of saline water. Esso has developed oily water treatment and continuous oil-in- water monitoring beyond conventional technology and operates within stringent overboard water discharge regulations. Initial oily water treating installations were Cross Flow Interceptors, a corrugated plate gravity separator. Unsatisfactory performance prompted investigations leading to development of the Dissolved Gas Flotation unit using evolved gas to lift oil droplets to the surface. These units operate successfully offshore today. The most recent developments have been associated with a liquid-liquid hydrocyclone trade named 'Vortoil'. This has been tested offshore with an 'Purometer' continuous oil-in-water monitor. The Vortoil and Purometer have both performed favourably and proven a compact, low cost combination for future water treating installations.
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Robertson, Tim, Peter Young, Andrew Driscoll, Jason Antenucci, Travis Elsdon, and Paul de Lestang. "Verifying the extent of plumes from produced formation water: a Wheatstone case study." APPEA Journal 60, no. 2 (2020): 518. http://dx.doi.org/10.1071/aj19056.
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Chevron Australia Pty Ltd operates the Wheatstone liquefied natural gas facility in Western Australia under a Joint Operating agreement. Hydrocarbons from Wheatstone, Iago and Julimar-Brunello fields are sent to the Wheatstone Platform (the Platform), located ~50 km north of the Montebello Islands, for dewatering and dehydration before being transported onshore for final processing. Produced formation water (PW) is processed (treated) and, once criteria are met, discharged overboard. PW at Wheatstone is predicted to rapidly dilute in the receiving ocean to concentrations below water quality criteria (Australian and New Zealand Environment Conservation Council guidelines and ecotoxicology), though empirical evidence is needed to verify the actual discharge risk. Seawater (i.e. cooling water, CW) is also abstracted for cooling duty on the Platform, chlorinated and discharged. This paper describes a field verification campaign aimed at understanding PW and CW behaviour in the water column post-discharge, dilution with distance and whether numerical modelling of dilutions is accurate. The campaign was designed to evaluate plume characteristics by monitoring both entrained PW constituents (i.e. hydrocarbons and metals) and using a Rhodamine WT tracer dye. Monitoring of these constituents was done using an array of sampling techniques, including fluorometry, remotely operated vehicles and discrete water samplers. Results indicate rapid dilutions post PW and CW discharge, with dye fluorometry proving a valuable tool for understanding plume characteristics. Water sampling data interpretation indicated dilutions were likely orders of magnitude greater than anticipated, likely due to variable flow effects and turbulence induced by the Platform structure for PW, and the influence of entrained air within the plume for CW.
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Haneef, Tahir, Muhammad Raza Ul Mustafa, Khamaruzaman Wan Yusof, Mohamed Hasnain Isa, Mohammed J. K. Bashir, Mushtaq Ahmad, and Muhammad Zafar. "Removal of Polycyclic Aromatic Hydrocarbons (PAHs) from Produced Water by Ferrate (VI) Oxidation." Water 12, no. 11 (November 9, 2020): 3132. http://dx.doi.org/10.3390/w12113132.
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Polycyclic aromatic hydrocarbons (PAHs) are mutagenic and carcinogenic contaminants made up of fused benzene rings. Their presence has been reported in several wastewater streams, including produced water (PW), which is the wastewater obtained during oil and gas extraction from onshore or offshore installations. In this study, ferrate (VI) oxidation was used for the first time for the treatment of 15 PAHs, with the total concentration of 1249.11 μg/L in the produced water sample. The operating parameters viz., ferrate (VI) dosage, pH, and contact time were optimized for maximum removal of PAHs and chemical oxygen demand (COD). Central composite design (CCD) based on response surface methodology (RSM) was used for optimization and modeling to evaluate the optimal values of operating parameters. PAH and COD removal percentages were selected as the dependent variables. The study showed that 89.73% of PAHs and 73.41% of COD were removed from PW at the optimal conditions of independent variables, i.e., ferrate (VI) concentration (19.35 mg/L), pH (7.1), and contact time (68.34 min). The high values of the coefficient of determination (R2) for PAH (96.50%) and COD (98.05%) removals show the accuracy and the suitability of the models. The results showed that ferrate (VI) oxidation was an efficient treatment method for the successful removal of PAHs and COD from PW. The study also revealed that RSM is an effective tool for the optimization of operating variables, which could significantly help to reduce the time and cost of experimentation.
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Danforth, Cloelle, Weihsueh A. Chiu, Ivan Rusyn, Kim Schultz, Ashley Bolden, Carol Kwiatkowski, and Elena Craft. "An integrative method for identification and prioritization of constituents of concern in produced water from onshore oil and gas extraction." Environment International 134 (January 2020): 105280. http://dx.doi.org/10.1016/j.envint.2019.105280.
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Jurnal, Redaksi Tim. "PERANCANGAN SISTEM KONTROL GLYCOL REGENERATION UNIT DENGAN DCS DeltaV DI ONSHORE GAS PLANT." Sutet 7, no. 2 (November 27, 2018): 102–10. http://dx.doi.org/10.33322/sutet.v7i2.82.
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The glycol regeneration process is an integrated part of the glycol dehydration unit (GDU) system. Each plant has a customized configuration to the needs of the process, for the case in this onshore field because the gas produced from the well is good enough with a fairly low water content, then does not use Glycol Contactor. Instead used low temperature separator and glycol generation unit. DCS DeltaV is used to operate, documentation and optimization of gas processes. By using oscillation method and closed loop system obtained PID tuning result with parameter P = 387, I = 57 and D = 53. The response of the control system is conditioned overshoot from its setpoint to accelerate the rise of the temperature plant. When the temperature of glycol regeneration is at 2620 F, the alarm will light Hi limit and Hi Hi limit at 2900 F, while at 2450F the alarm will light low limit and Low Low limit at temperature 00 F.
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Soldo, Elena, Claudio Alimonti, and Davide Scrocca. "Geothermal Repurposing of Depleted Oil and Gas Wells in Italy." Proceedings 58, no. 1 (September 11, 2020): 9. http://dx.doi.org/10.3390/wef-06907.
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The decarbonisation of the energy sector is probably one of the main worldwide challenges of the future. Global changes urge a radical transformation and improvement of the energy-producing systems to meet the decarbonisation targets and a reduction of greenhouse gas emissions. The hydrocarbon industry also contributes to this transition path. In a mature stage of oil and gas fields, the production of hydrocarbons is associated with formation waters. The volume of produced water increases with the maturity of the assets and the geothermal repurposing of depleted oil and gas wells could be an alternative to the mining closure. In the described transition scenario, the geothermal energy seems very promising because of its wide range of applications depending on the temperature of extracted fluids. This flexibility enables us to propose projects inspired by a circular economic vision considering the integration in the territory and social acceptance issues. In Italy, since 1985, 7246 wells have been drilled for hydrocarbon, of which 898 are located onshore with a productive or potentially productive operational status. This paper presents a preliminary investigation of oil and gas fields located onshore in Italian territory based on the available information on temperature distribution at different depths. Then, taking into account the local energy demand, existing infrastructure, and land use of the territory, a conversion strategy for the producing wells is proposed for three case studies.
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Martin, Joseph P., and Kenneth J. Zitomer. "Onsite Wastewater Treatment and Disposal for Coastal Resort Businesses." Water Science and Technology 21, no. 2 (February 1, 1989): 199–204. http://dx.doi.org/10.2166/wst.1989.0050.
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Onshore commercial or institutional services for the New Jersey barrier island resorts frequently dispose of wastewater onsite, by percolating septic system effluent to the underlying aquifers. However, to protect the groundwater supplying potable water and brackish wetlands, larger onsite systems must now include advanced treatment to remove nitrates. Effluent produced by a mechanical treatment plant at a new nursing home was improved by percolation through a zoned sand mound disposal bed, but operation of the small but complex plant is expensive. Therefore, another system to remove organics and nitrogen was developed for a shopping center, which was expected to have severe seasonal variations in wastewater quality and quantity. Treatment in a series of in-ground and mounded aerobic and anoxic units provides operational economy and flexibility appropriate to resort area commercial establishments.
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Ou, Shan-Hwei, Tai-Wen Hsu, Jian-Feng Lin, Jian-Wu Lai, Shih-Hsiang Lin, Chen-Chen Chang, and Yuan-Jyh Lan. "EXPERIMENTAL AND NUMERICAL STUDIES ON WAVE TRANSFORMATION OVER ARTIFICIAL REEFS." Coastal Engineering Proceedings 1, no. 32 (January 25, 2011): 17. http://dx.doi.org/10.9753/icce.v32.waves.17.
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A laboratory measurement on the flow field, turbulence and wave energy of spilling breakers over artificial reefs is presented. Instantaneous velocity fields of propagating breaking waves on artificial reefs were measured using Particle Image Velocimeter (PIV) and Bubble Image Velocimeter (BIV). Variations of water surface elevation were observed by using Charge Coupled Device (CCD) cameras with horizontal posture. The experimental results showed that the initial bubble velocity in the aerated region is faster than phase speed with a factor of 1.26. The velocity profiles are identical to the shallow water theory. It is found that a low flow velocity exists due to an opposite but equal onshore and offshore velocity. Significant turbulent kinetic energy and turbulent Reynolds stress are produced by breaking waves in the front of aerated region, then move offshore and decay. The calculated total energy dissipation rate was compared to that based on a bore approximation.
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Steventon, James, and Mike Bowman. "An assessment of the Upper Succession and the related secondary reservoirs in the Welton Field, onshore UK." Geological Society, London, Petroleum Geology Conference series 8, no. 1 (December 15, 2016): 595–609. http://dx.doi.org/10.1144/pgc8.22.
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AbstractThe Welton oil field has produced nearly 20 MMBO (million barrels of oil) since discovery in 1981. Now in post-plateau decline, there is increasing reliance on a series of secondary reservoirs. Production has been from a suite of stacked reservoirs deposited by large-scale prograding delta-plain systems of early Westphalian age. Whilst the bulk of production has been from the Basal Succession, a considerable upside is considered to exist in the less well-studied Upper Succession that comprises predominantly distributary channel and crevasse splay deposits which have produced in excess of 3 MMBO. These accumulations occur within the Deep Soft Rock, Deep Hard Rock and Tupton reservoirs.This paper focuses on a sedimentological analysis of cored intervals, integrated with petrophysical logs and detailed production data to enable further recommendations to identify areas of undrained pay, along with identifying additional reservoir management activities that could optimize future offtake from the field. These reservoirs consist predominantly of very fine-grained sandstone, with permeability values rarely attaining 100 mD and average porosity values of 10–12%.Recommendations include executing tracer communication tests and building a detailed field model, as well as a pilot water-injection scheme to increase production from some of Welton's secondary reservoirs.Supplementary material: A full set of detailed sedimentological logs for each of the cored wells in this study is available at https://doi.org/10.6084/m9.figshare.c.3593984
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Syah, Rahmad, Alireza Heidary, Hossein Rajabi, Marischa Elveny, Ali Akbar Shayesteh, Dadan Ramdan, and Afshin Davarpanah. "Current Challenges and Advancements on the Management of Water Retreatment in Different Production Operations of Shale Reservoirs." Water 13, no. 15 (August 2, 2021): 2131. http://dx.doi.org/10.3390/w13152131.
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Nowadays, water savings on industrial plants have become a significant concern for various plants and sections. It is vitally essential to propose applicable and efficient techniques to retreat produced water from onshore and offshore production units. This paper aimed to implement the PFF (Photo Fenton Flotation) method to optimize the water treatment procedure, as it is a two-stage separation technique. The measurements were recorded for the HF (hydraulic fracturing) and CEOR (chemically enhanced oil recovery) methods separately to compare the results appropriately. To assure the efficiency of this method, we first recorded the measurements for five sequential days. As a result, the total volume of 2372.5 MM m3/year of water can be saved in the HF process during the PFF treatment procedure, and only 20% of this required fresh water should be provided from other resources. On the other hand, the total volume of 7482.5 MM m3/year of water can be saved in CEOR processes during the PFF treatment procedure, and only 38% of this required fresh water should be provided from other resources. Therefore, the total water volume of 9855 MM m3 can be saved each year, indicating the efficiency of this method in supplying and saving the water volume during the production operations from oilfield units.
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Dris, Rachid, Hannes Imhof, Wilfried Sanchez, Johnny Gasperi, François Galgani, Bruno Tassin, and Christian Laforsch. "Beyond the ocean: contamination of freshwater ecosystems with (micro-)plastic particles." Environmental Chemistry 12, no. 5 (2015): 539. http://dx.doi.org/10.1071/en14172.
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Environmental context Microplastics in freshwater ecosystems are an increasingly important environmental issue, with the few available studies suggesting high contamination worldwide. Reliable data on concentrations, fluxes and polymer types in continental aquatic environments, including urban water systems, are needed. High environmental and ecological risk polymers and associated or adsorbed chemicals have to be identified, as well as their effects on both organisms and ecosystems. Abstract Massive accumulation of plastic particles has been reported for marine ecosystems around the world, posing a risk to the biota. Freshwater ecosystems have received less attention despite most plastic litter being produced onshore and introduced into marine environments by rivers. Some studies not only report the presence of microplastics in freshwater ecosystems, but show that contamination is as severe as in the oceans. In continental waters, microplastics have been observed in both sediments (predominantly lake shores but also riverbanks) and water samples (predominantly surface water of lakes and rivers). This review highlights recent findings and discusses open questions, focussing on the methodology of assessing this contaminant in freshwater ecosystems. In this context, method harmonisation is needed in order to obtain comparable data from different environmental compartments and sites. This includes sampling strategies (at spatial and temporal scales), sample treatment (taking into consideration high levels of organic matter and suspended solids) and reliable analytical methods to identify microplastics.
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Buech, Richard R., David J. Rugg, and Nancy L. Miller. "Temperature in beaver lodges and bank dens in a near-boreal environment." Canadian Journal of Zoology 67, no. 4 (April 1, 1989): 1061–66. http://dx.doi.org/10.1139/z89-147.
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The thermal environment of selected lodges and bank dens of beavers (Castor canadensis) was studied in northeastern Minnesota to evaluate determinants of chamber air temperature. Mean air temperature was higher while the range in mean air temperature was smaller inside the chamber than outside in all months. Seasonal temperature extremes in lodges were generally within the thermoneutral zone of beavers year-round. Thus, shelters allow beavers to exploit environments that would otherwise be physiologically unsuitable to them. Data were consistent with our hypothesis that temperature of the soil or water substrate has a dominant influence on chamber air temperature. Two bank dens were cooler than an open-water lodge; hence onshore shelters may offer better protection against heat stress during hot weather. In winter, it appears that (i) total insulation (lodge walls plus snow) is sufficient to counter the influence of outside air temperature, (ii) temperature of the substrate underlying a lodge largely determines chamber air temperature, and (iii) heat produced by beavers raises the temperature of lodges above that derived from the lodge substrate.
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Jamal, Mohamad Hidayat, David J. Simmonds, and Vanesa Magar. "GRAVEL BEACH PROFILE EVOLUTION IN WAVE AND TIDAL ENVIRONMENTS." Coastal Engineering Proceedings 1, no. 33 (December 15, 2012): 15. http://dx.doi.org/10.9753/icce.v33.sediment.15.
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This paper reports progress made in modifying and applying the X-Beach code to predict and explain the observed behaviour of coarse grained beaches. In a previous study a comparison of beach profile evolution measured during large scale experiments under constant water level with numerical model simulations was made. This placed particular emphasis on the tendency for onshore transport and profile steepening during calm conditions (Jamal et al., 2010). The present paper extends that investigation to study the influence of the advection of surf processes induced by tidal water level variations effects, on gravel beach profile evolution. The parameter values and numerical model used in the simulation is similar to that presented previously. It is assumed that, to good approximation, the groundwater interface inside the beach follows the tidally modulated water level. The results obtained from the model shows that the model provides reasonable simulations of beach profile change in a tidal environment. In comparison with simulations under stationary water levels, a larger berm is produced in agreement with literature. Finally, good agreement is obtained between the model simulations and an example of field observations from a beach at Milford on Sea, UK. Further developments are outlined for future work.
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Shi, Yi, Jiaqing Chen, and Zehao Pan. "Experimental Study on the Performance of a Novel Compact Electrostatic Coalescer with Helical Electrodes." Energies 14, no. 6 (March 20, 2021): 1733. http://dx.doi.org/10.3390/en14061733.
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As most of the light and easy oil fields have been produced or are nearing their end-life, the emulsion stability is enhanced and water cut is increasing in produced fluid which have brought challenges to oil–water separation in onshore and offshore production trains. The conventional solution to these challenges includes a combination of higher chemical dosages, larger vessels and more separation stages, which often demands increased energy consumption, higher operating costs and larger space for the production facility. It is not always feasible to address the issues by conventional means, especially for the separation process on offshore platforms. Electrostatic coalescence is an effective method to achieve demulsification and accelerate the oil–water separation process. In this paper, a novel compact electrostatic coalescer with helical electrodes was developed and its performance on treatment of water-in-oil emulsions was investigated by experiments. Focused beam reflectance measurement (FBRM) was used to make real-time online measurements of water droplet sizes in the emulsion. The average water droplet diameters and number of droplets within a certain size range are set as indicators for evaluating the effect of coalescence. We investigated the effect of electric field strength, frequency, water content and fluid velocity on the performance of coalescence. The experimental results showed that increasing the electric field strength could obviously contribute to the growth of small water droplets and coalescence. The extreme value of electric field strength achieved in the high-frequency electric field was much higher than that in the power-frequency (50 Hz) electric field, which can better promote the growth of water droplets. The initial average diameters of water droplets increase with higher water content. The rate of increment in the electric field was also increased. Its performance was compared with that of the plate electrodes to further verify the advantages of enhancing electrostatic coalescence and demulsification with helical electrodes. The research results can provide guidance for the optimization and performance improvement of a compact electrocoalescer.
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Liu, Yang, Zhi Hua Wang, Li Xin Wei, and Ren Shan Pang. "A Case Study in Oil-Gas Transportation through Subsea Pipeline in Liaohe Tanhai Oilfield." Advanced Materials Research 317-319 (August 2011): 2239–43. http://dx.doi.org/10.4028/www.scientific.net/amr.317-319.2239.
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The crude oil in Kuidong region of Liaohe Tanhai Oilfield is characterized by high oil viscosity, high density, high content of colloid asphalt, low content of wax and low freezing point. In the shallow region, the large current, high content of silt, long-distance subsea buried pipeline and drift ice in winter have brought great challenge to offshore construction and oil-gas transportation. In this paper, the investigations of offshore construction project and platform process are shown. Based on the well production rate, gas-oil ratio, water cut, wellhead back pressure and outlet temperature, the range of daily transportation volume was acquired, as well as the maximum inlet pressure and pressure difference of the pump. The paper also selected technically and economically feasible pumps, then designed the public projects, corresponding electric power and self-control facilities. The selected skidded twin screw multiphase pump system can smoothly transport produced liquid to the terminal systems onshore without any effect on the daily output.
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Brooks, Steven, Christopher Harman, Beñat Zaldibar, Urtzi Izagirre, Tormod Glette, and Ionan Marigómez. "Integrated biomarker assessment of the effects exerted by treated produced water from an onshore natural gas processing plant in the North Sea on the mussel Mytilus edulis." Marine Pollution Bulletin 62, no. 2 (February 2011): 327–39. http://dx.doi.org/10.1016/j.marpolbul.2010.10.007.
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Ab Rashid, Siti Rafidah, and Adil Rahman Nor Azmi. "Quantitative risk analysis on an FSO crude oil storage tank." Malaysian Journal of Chemical Engineering and Technology (MJCET) 3, no. 1 (November 30, 2020): 29. http://dx.doi.org/10.24191/mjcet.v3i1.11074.
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The industry of oil and gas are blooming in a rapid rate as time goes by because of the massive use of fuel oil and natural gas in this age of time. However, as more fuel oil are produced the industry is moving away from onshore to offshore and towards the ultra-deep-water region, where vessel like FSOs are introduced. FSO are short for Floating Storage and Offloading which are vessels used in deep water operation. The FSO plays an important role in the business where a single disastrous incident will affect the industry and the company. The focus of the research will be on the FSO that holds million barrels of crude oil. In this work, fire risk analysis is used to assess the crude oil storage tank on a typical FSO as this is a relatively new mode in exploration and production (E&P) activity. By calculating the individual risk per annum (IRPA) and potential loss of life (PLL), methods are introduced to mitigate fire risk on FSOs. The results show that the level of failure is low and requires less action for the FSO crude oil storage tank to stay safe during operation in the offshore environment.
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Salathé, Eric P., Richard Steed, Clifford F. Mass, and Patrick H. Zahn. "A High-Resolution Climate Model for the U.S. Pacific Northwest: Mesoscale Feedbacks and Local Responses to Climate Change*." Journal of Climate 21, no. 21 (November 1, 2008): 5708–26. http://dx.doi.org/10.1175/2008jcli2090.1.
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Abstract Simulations of future climate scenarios produced with a high-resolution climate model show markedly different trends in temperature and precipitation over the Pacific Northwest than in the global model in which it is nested, apparently because of mesoscale processes not being resolved at coarse resolution. Present-day (1990–99) and future (2020–29, 2045–54, and 2090–99) conditions are simulated at high resolution (15-km grid spacing) using the fifth-generation Pennsylvania State University–NCAR Mesoscale Model (MM5) system and forced by ECHAM5 global simulations. Simulations use the Intergovernmental Panel on Climate Change (IPCC) Special Report on Emissions Scenarios (SRES) A2 emissions scenario, which assumes a rapid increase in greenhouse gas concentrations. The mesoscale simulations produce regional alterations in snow cover, cloudiness, and circulation patterns associated with interactions between the large-scale climate change and the regional topography and land–water contrasts. These changes substantially alter the temperature and precipitation trends over the region relative to the global model result or statistical downscaling. Warming is significantly amplified through snow–albedo feedback in regions where snow cover is lost. Increased onshore flow in the spring reduces the daytime warming along the coast. Precipitation increases in autumn are amplified over topography because of changes in the large-scale circulation and its interaction with the terrain. The robustness of the modeling results is established through comparisons with the observed and simulated seasonal variability and with statistical downscaling results.
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Hall, Lisa S., Meredith L. Orr, Megan E. Lech, Steven Lewis, Adam H. E. Bailey, Ryan Owens, Barry E. Bradshaw, and George Bernardel. "Geological and Bioregional Assessments: assessing the prospectivity for tight, shale and deep-coal resources in the Cooper Basin, Beetaloo Subbasin and Isa Superbasin." APPEA Journal 61, no. 2 (2021): 477. http://dx.doi.org/10.1071/aj20035.
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The Geological and Bioregional Assessment Program is a series of independent scientific studies undertaken by Geoscience Australia and the CSIRO, supported by the Bureau of Meteorology, and managed by the Department of Agriculture, Water and the Environment. The program consists of three stages across three regions with potential to deliver gas to the East Coast Gas Market. Stage 1 was a rapid regional prioritisation conducted by Geoscience Australia, to identify those sedimentary basins with the greatest potential to deliver shale and/or tight gas to the East Coast Gas Market within the next 5–10 years. This prioritisation process assessed 27 onshore eastern and northern Australian basins with shale and/or tight gas potential. Further screening reduced this to a shortlist of nine basins where exploration was underway. The shortlisted basins were ranked on a number of criteria. The Cooper Basin, the Beetaloo Subbasin and the Isa Superbasin were selected for more detailed assessment. Stage 2 of the program involved establishing a baseline understanding of the identified regions. Geoscience Australia produced regional geological evaluations and conceptualisations that informed the assessment of shale and/or tight gas prospectivity, ground- and surface-water impacts and hydraulic fracturing models. Geoscience Australia’s relative prospectivity assessments provide an indication of where viable petroleum plays are most likely to be present. These data indicate areal and stratigraphic constraints that support the program’s further work in Stage 3, on understanding likely development scenarios, impact assessments and causal pathways.
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Wang, Ping, and Jun Cheng. "Mega-Ship-Generated Tsunami: A Field Observation in Tampa Bay, Florida." Journal of Marine Science and Engineering 9, no. 4 (April 18, 2021): 437. http://dx.doi.org/10.3390/jmse9040437.
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The displacement of a large amount of water in a moderate-sized estuary by a fast-moving mega-ship can generate tsunami-like waves. Such waves, generated by cruise ships, were observed in Tampa Bay, Florida, USA. Two distinct, long tsunami-like waves were measured, which were associated with the passage of a large cruise ship. The first wave had a period of 5.4 min and a height of 0.40 m near the shoreline. The second wave had a period of 2.5 min and was 0.23 m high. The peak velocity of the onshore flow during the second wave reached 0.65 m/s. The shorter, second wave propagated considerably faster than the first wave in the breaking zone. The measured wave celerity was less than 50% of the calculated values, using the shallow water approximation of the dispersion equation, suggesting that nonlinear effects play an important role. A fundamental similarity among the generation of tsunamis, as induced by mega-ships, landslides or earthquakes, is a process that causes a vertical velocity at the sea surface, where a freely propagating wave is produced. This mega-ship-generated tsunami provides a prototype field laboratory for systematically studying tsunami dynamics, particularly the strong turbulent flows associated with the breaking of a tsunami wave in the nearshore, and tsunami–land interactions. It also provides a realistic demonstration for public education, which is essential for the preparation and management of this unpreventable hazard.
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F-Pedrera Balsells, Marta, Manel Grifoll, Margarita Fernández-Tejedor, and Manuel Espino. "Short-Term Response of Chlorophyll a Concentration Due to Intense Wind and Freshwater Peak Episodes in Estuaries: The Case of Fangar Bay (Ebro Delta)." Water 13, no. 5 (March 5, 2021): 701. http://dx.doi.org/10.3390/w13050701.
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Estuaries and coastal bays are areas of large spatio-temporal variability in physical and biological variables due to environmental factors such as local wind, light availability, freshwater inputs or tides. This study focuses on the effect of strong wind events and freshwater peaks on short-term chlorophyll a (Chl a) concentration distribution in the small-scale and microtidal, Fangar Bay (Ebro Delta, northwestern Mediterranean). The hydrodynamics of this bay are primarily driven by local wind episodes modulated by stratification in the water column. Results based on field-campaign observations and Sentinel-2 images revealed that intense wind episodes from both NW (offshore) and NE-E (onshore) caused an increase in the concentration of surface Chl a. The mechanisms responsible were horizontal mixing and the bottom resuspension (also linked to the breakage of the stratification) that presumably resuspended Chl a containing biomass (i.e., micropyhtobentos) and/or incorporated nutrients into the water column. On the other hand, sea-breeze was not capable of breaking up the stratification, so the chlorophyll a concentration did not change significantly during these episodes. It was concluded that the mixing produced by the strong winds favoured an accumulation of Chl a concentration, while the stratification that causes a positive estuarine circulation reduced this accumulation. However, the spatial-temporal variability of the Chl a concentration in small-scale estuaries and coastal bays is quite complex due to the many factors involved and deserve further intensive field campaigns and additional numerical modelling efforts.
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Hartanto, Lina, Wisnu Widjanarko, and Diala Muna. "The success story of Windalia waterflood optimisation through integrated asset management in a mature field." APPEA Journal 51, no. 2 (2011): 726. http://dx.doi.org/10.1071/aj10106.
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Australia’s Barrow Island Windalia reservoir—the nation’s largest onshore waterflood—was developed in the late 1960s. The Barrow Island oilfield is Chevron Australia’s only mature waterflood, comprising more than 220 active injectors. The injectors pressurise and increase oil recovery from the geologically complex, low-permeable and heterogeneous Windalia Sand Member. To date it is estimated that the value of waterflooding has effectively reduced the field decline rate from approximately 18 % per annum to less than 2 %—adding millions of barrels in recovery and years on to productive field life. In September of 2008, the Windalia Waterflood achieved full field restitution. This involved the replacement and commissioning of glass-reinforced epoxy injection flow lines, a ring-main network and produced water re-injection facilities. Significant challenges were overcome in the process of realising the restitution’s full potential. Several waterflood optimisation activities have now been executed to achieve oil uplift and to capitalise on Chevron Australia’s investment. Compounded with restitution, the activities have successfully achieved the asset objective of arresting field production decline. This paper highlights the challenges encountered by the waterflood team, providing insights and lessons learned in the dynamic and holistic nature of waterflood management. It also highlights the interplay of considerations and what is crucial to achieving optimum sweep efficiency and pressurisation.
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Nwachukwu, C. M., Z. Barnett, and J. G. Gluyas. "The Breagh Field, Blocks 42/12a, 42/13a and 42/8a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 109–18. http://dx.doi.org/10.1144/m52-2019-15.
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AbstractThe Breagh Field is in UK Blocks 42/12a, 42/13a and 42/8a. It is a gas field with multiple reservoir intervals within sandstones of the Early Carboniferous Yoredale Formation (equivalent to the Middle Limestone Formation within the Yoredale Group onshore). It was the first and is presently the only field developed within these sandstones, offshore UK. Breagh was discovered in 1997 by well 42/13-2 and proved by development well 42/13a-A1. Its crest is at 7110 ft TVDSS (true vertical depth subsea), marked by the unconformity between the base Zechstein and the subcropping Yoredale Formation. It has a free water level at 7690 ft TVDSS, a maximum column height of 510 ft and a field extent of 94 km2. Breagh was developed using ten wells from a 12 slot normally unattended platform; five of the wells have been stimulated by hydraulic fractures with proppant injection. The unprocessed gas flows through a 110 km 20-inch diameter pipeline to the Teesside Gas Processing Plant. Production started in 2013, reached a peak rate of 150 MMscfgd in 2014 and, by the end of 2018, had produced 140 bcf. The field is operated by INEOS Oil and Gas UK Ltd (70%) with partner ONE-Dyas B.V. (30%).
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Onyekperem Cyprian Chigozirim, Ademiluyi Taiwo, and Joseph Atubokiki Ajienka. "Potency of starch in hydrate inhibition in a field within Gulf of Guinea Using Aspen Hysys." Global Journal of Engineering and Technology Advances 7, no. 1 (April 30, 2021): 091–102. http://dx.doi.org/10.30574/gjeta.2021.7.1.0049.
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Hydrocarbon industry is now moving from onshore to offshore environments in search of black gold, since the world’s energy demand is growing astronomically. Exploitation of this black gold in an offshore environment is quite very capital intensive but not exonerated from flow assurance and intervention challenges. This is due to the fact that the black gold is produced alongside with BSW, associated gas, without which the black gold will be termed dead oil; also, there is restricted accessibility in an offshore environment. The result of hydrate formation includes blockage of flow lines, plaguing downstream equipment and flow line’s appurtenances such as Valves, Tees, Elbows. The current methods of preventing hydrate formation by the industry are highly limited and the chemicals used are harsh to the ecosystem. This study investigated the potency of Starch from Manihot Esculenta in hydrate inhibition using Aspen Hysys V11.0. The performances of considered hydrate inhibitors in a modeled flow line system with diameter355.6mm, length of 12.095 km in deep water hydrocarbon field within the Gulf of Guinea, were based on actual condition and production data. The simulation results at 40% and 80% water cuts were plotted for both steady state and dynamic state using Mat lab. At steady state, simulation results disclosed that there will be no hydrate formation. However, at dynamic state, simulation results disclosed that hydrates will form. HCF’s pressure declines from 61bar to 40.52bar, 32.43bar respectively, for the different water cuts, in induction time of 240 minutes. Likewise, HCF’s temperature declined suddenly and sharply rose again indicating hydrate formations. Starch at 0.05, 0.1, 0.15, 0.2 mole fractions prevented hydrates from forming but best at 0.2 mole fractions. Starch was therefore, recommended for field-pilot test and further developed, utilized as an ecofriendly hydrate inhibitor.
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Hala, Yusafir, Syahruddin udin Kasim, and Indah Raya. "FORMULASI PAKAN UNGGUL BERBASIS BIOTEKNOLOGI LIMBAH ORGANIK LOKAL UNTUK IKAN LELE ORGANIK KUALITAS EKSPOR." KOVALEN: Jurnal Riset Kimia 5, no. 2 (August 31, 2019): 197–206. http://dx.doi.org/10.22487/kovalen.2019.v5.i2.12926.
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Research on Superior Feed Formulations Based on Local Organic waste Biotechnology for Export quality organic Catfish. Research Objective: The discovery of feed types of tilapia and organic catfish that have export quality nutritional content based on the best quality local marine organic waste through a touch of biotechnology. Furthermore, the complete chemical composition of the waste used and feed components is obtained. Research Methods: Determine the best composition of biomass of marine organic waste and local onshore organic wastes with the highest levels of protein and carbohydrates and integrated with other wastes. The nutritional content is analyzed, namely: Carbohydrates, fats, proteins, and supporting minerals, namely: Fe, K and Ca. Instrumentation used to support the research objectives is AAS and HPLC. Research Results: Export quality organic catfish pellet feed in the form of waste: marine fish, sea shrimp waste, sea crab waste, rice bran waste, corn waste, mixed organic waste, golden snail waste, seaweed waste and coconut water waste respectively (27; 15; 7.5; 33; 3; 2.5; 5; 2.5 and 2) %b/ b, starch 2% b/b and marine phytoplankton biomass 0.5% b/b. The nutritional content of organic catfish pellets that have been produced, namely: 51% protein b/b, 24% carbohydrate b/b, 9% fat b/b, crude fiber 8%b/b, water content 2 - 2.5%b/b, mineral Fe 1% b/b, mineral K 1% b/b, mineral Ca 1%b/b, ash content 2 - 2.5%b/b. Feed packing for export quality organic catfish pellets is given the "SANTARI-KU" label.
Keywords: Superior feed, local organic waste biotechnology, export quality organic catfish, Santari-ku.
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Pope, Pamela, Al Allen, and William G. Nelson. "ASSESSMENT OF THREE SURFACE COLLECTING AGENTS DURING TEMPERATE AND ARCTIC CONDITIONS." International Oil Spill Conference Proceedings 1985, no. 1 (February 1, 1985): 199–201. http://dx.doi.org/10.7901/2169-3358-1985-1-199.
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ABSTRACT Laboratory and field tests were conducted to evaluate the effectiveness of using surface collecting agents in cold weather oil recovery and in situ burning operations. In a small laboratory test tank, the surface areas and equilibrium thicknesses of three Alaskan North Slope crude oils were observed before and after the application of three different surface collecting agents to each oil. Numerous small bench-top tests also were conducted to further support the observations made in the test tank. Ambient air temperatures were varied from 23° C to −17° C, while the temperatures of fresh water and laboratory-prepared sea water were varied from 15° C to 0° C. The three surface collecting agents used (Corexit OC-5, Nalco 3WP-086, Shell Oil Herder) were equally effective in concentrating the areas of thin films by as much as 95 percent within a minute or less. The efficiencies of the surface collecting agents were observed to decrease only slightly with air temperatures below 0° C. Equilibrium thicknesses and areas before and after collectant application were determined using standard photometric techniques. In addition, two field tests were conducted to evaluate the effectiveness of collecting agents on large experimental oil slicks in an onshore pit at Prudhoe Bay. In each test, approximately 1 m3 of fresh Prudhoe Bay crude oil was released and allowed to come to an equilibrium thickness. In each test, the oil was concentrated with Corexit OC-5 and Shell Oil Herder and then ignited. Winds of 4-to-6 knots (2-to-3 m/s) herded the slicks into one corner of the pit and produced an average slick thickness of 9.5 mm. The use of collectants resulted in a 5 percent reduction of the wind-herded slick areas, thus increasing the thicknesses to approximately 10 mm.
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Ramp, Steven R., and Frederick L. Bahr. "Seasonal Evolution of the Upwelling Process South of Cape Blanco*." Journal of Physical Oceanography 38, no. 1 (January 1, 2008): 3–28. http://dx.doi.org/10.1175/2007jpo3345.1.
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Abstract Bursts of upwelling-favorable winds lasting 4–20 days occur year-round south of Cape Blanco, a major headland on the Oregon coast. The ocean’s response to these events was studied using moored current, temperature, and salinity data; satellite SST data; and a few across-shelf sections near the mooring site. The mooring was located at 42°26.49′N, 124°34.47′W, 6 n mi off Gold Beach, Oregon, from May 2000 to October 2003. After the spring transition but before upwelling jet separation, equatorward wind stress produced a steady upwelling response much the same as a long, straight coast. Currents and winds had similar spectral characteristics with a peak near 15 days. After jet separation, upwelling-favorable winds forced a much more variable current consisting of a series of thin equatorward jets that evolved and moved offshore across the mooring, with shorter time scales than the wind stress forcing. During autumn, the equatorward wind stress weakened slightly and a transition period occurred, with the flow often poleward along the bottom. During winter, the water column was unstratified during poleward winds and currents with little variation in SST across the shelf. Winter upwelling restratified the water column from the bottom up by drawing cold, salty water onshore along the bottom, with little or no change in SST. This scenario was modulated by strong intraseasonal and interannual variability in the ocean and atmosphere. A wavelet transform analysis of alongshore wind stress and the first empirical orthogonal mode of the alongshore currents revealed strong energy peaks in the 30–70-day band. These signals were particularly clear in the ocean and were not coherent with the local wind stress, suggesting they were due to Kelvin waves of equatorial origin. The shift toward longer (40–45–60 days) periods from 2000 to 2003 was consistent with decreasing (warming) northern oscillation index, suggesting that the period as well as the energy of the intraseasonal waves may be important in transmitting heat poleward during warm years.
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Reijmer, John J. G., Johan H. ten Veen, Bastiaan Jaarsma, and Roy Boots. "Seismic stratigraphy of Dinantian carbonates in the southern Netherlands and northern Belgium." Netherlands Journal of Geosciences 96, no. 4 (November 8, 2017): 353–79. http://dx.doi.org/10.1017/njg.2017.33.
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AbstractDue to their potential as a petroleum or geothermal system, the Dinantian carbonates of the Netherlands have recently attracted renewed interest because of the identified presence of excellent reservoir properties. This notion contrasts with the general assumption that these carbonates are tight. Therefore, in order to give the current knowledge state, this paper re-examines the sparse publicly available well and seismic data and literature to assess the distribution and reservoir properties of the Dinantian carbonates.Dinantian carbonate deposition occurred throughout the study area (southern onshore and offshore of the Netherlands and northern Belgium), which is situated on the northern margin of the London–Brabant Massif, progressively onlapping the latter structure. This study confirms the presence of three carbonate facies types in the study area: a Tournaisian low-gradient carbonate ramp system, succeeded by a succession in which the carbonate ramp system evolved to a rimmed shelf setting. Subsidence of the northern margin of the London–Brabant Massif resulted in a landward shift of the shallow-marine facies belts, while the formation of normal faults resulted in a ‘staircase’-shaped shallow-water platform–slope–basin profile, associated with large-scale resedimentation processes. After deposition, the limestone deposits were frequently exhumed and reburied. A first period of regional exhumation occurred at the end of the Dinantian, which seems to be associated with porosity-enhancing meteoric karstification, possibly limited to the palaeo-shelf edge. The most intense alterations seem to be present as a deep leached horizon below the Cretaceous unconformity at the top of the Dinantian sequences. In addition, clear evidence for hydrothermal fluid migration is found locally, enhancing reservoir properties at some places while occluding porosity at others. The timing of these phases of hydrothermal fluid circulation is poorly understood.Whereas in the United Kingdom hydrocarbons have been produced from karstified Dinantian carbonates, this petroleum play has received little attention in the Netherlands. This paper shows that, also for the Netherlands, a karstic reservoir probably existed before the start of hydrocarbon generation from the onlapping basal Namurian shales. The hydrocarbon prospectivity of these sediments, however, is primarily controlled by the presence of both a karst-related reservoir and migration routes from a decent-quality source rock. Two geothermal projects producing from this reservoir in the southern onshore Netherlands have shown the potential of the Dinantian carbonates for ultra-deep geothermal projects. To conclude, the findings presented herein are relevant for studies of the hydrocarbon prospectivity and studies of the geothermal potential of Dinantian carbonates in the Dutch on- and offshore.
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Trachte, Katja. "Atmospheric Moisture Pathways to the Highlands of the Tropical Andes: Analyzing the Effects of Spectral Nudging on Different Driving Fields for Regional Climate Modeling." Atmosphere 9, no. 11 (November 19, 2018): 456. http://dx.doi.org/10.3390/atmos9110456.
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Atmospheric moisture pathways to the highlands of the tropical Andes Mountains were investigated using the Weather Research and Forecasting (WRF) model, as well as back-trajectory analysis. To assess model uncertainties according to the initial and lateral boundary conditions (ILBCs), the effects of spectral nudging and different driving fields on regional climate modeling were tested. Based on the spatio-temporal patterns of the large-scale atmospheric features over South America, the results demonstrated that spectral nudging compared to traditional long-term integration generally produced greater consistency with the reference data (ERA5). These WRF simulations further revealed that the location of the inter-tropical convergence zone (ITCZ), as well as the precipitation over the Andes Mountains were better reproduced. To investigate the air mass pathways, the most accurate WRF simulation was used as atmospheric conditions for the back-trajectory calculations. Three subregions along the tropical Andean chain were considered. Based on mean cluster trajectories and the water vapor mixing ratio along the pathways, the contributions of eastern and western water sources were analyzed. In particular, the southernmost subregion illustrated a clear frequency of occurrences of Pacific trajectories mostly during September–November (40%) when the ITCZ is shifted to the Northern Hemisphere and the Bolivian high pressure system is weakened. In the northernmost subregion, Pacific air masses as well reached the Andes highlands with rather low frequencies regardless of the season (2–12%), but with a moisture contribution comparable to the eastern trajectories. Cross-sections of the equivalent-potential temperature as an indicator of the moisture and energy content of the atmosphere revealed a downward mixing of the moisture aloft, which was stronger in the southern subregion. Additionally, low-level onshore breezes, which developed in both subregions, indicated the transport of warm-moist marine air masses to the highlands, highlighting the importance of the representation of the terrain and, thus, the application of dynamical downscaling using regional climate models.
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MARAVELIS, A., G. MAKRODIMITRAS, N. PASADAKIS, and A. ZELILIDIS. "Stratigraphic evolution and source rock potential of a Lower Oligocene to Lower–Middle Miocene continental slope system, Hellenic Fold and Thrust Belt, Ionian Sea, northwest Greece." Geological Magazine 151, no. 3 (July 9, 2013): 394–413. http://dx.doi.org/10.1017/s0016756813000289.
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AbstractThe Western flanks of the Hellenic Fold and Thrust Belt are similar to the nearby prolific Albanian oil and gas provinces, where commercial volumes of oil have been produced. The Lower Oligocene to Lower–Middle Miocene slope series at this part of the Hellenic Fold and Thrust Belt provides a unique opportunity to evaluate the anatomy and source rock potential of such a system from an outcrop perspective. Slope progradation is manifested as a vertical pattern exhibiting an increasing amount of sediment bypass upwards, which is interpreted as reflecting increasing gradient conditions. The palaeoflow trend exhibits a western direction during the Late Oligocene but since the Early Miocene has shifted to the East. The occurrence of reliable index species allowed us to recognize several nannoplankton biozones (NP23 to NN5). Organic geochemical data indicate that the containing organic matter is present in sufficient abundance and with good enough quality to be regarded as potential source rocks. The present Rock-Eval II pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is of type III kerogen. A terrestrial origin is suggested and is attributed to short transportation distance and accumulation at rather low water depth. The succession is immature with respect to oil generation and has not experienced high temperature during burial. However, its eastern down-slope equivalent deep-sea mudstone facies should be considered as good gas-prone source rocks onshore since they may have experienced higher thermal evolution. In addition, they may have improved organic geochemical parameters because there is no oxidization of the organic matter.
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Veeken, Paul C., Peter J. Legeydo, Yuri A. Davidenko, Elena O. Kudryavceva, Sergei A. Ivanov, and Anton Chuvaev. "Benefits of the induced polarization geoelectric method to hydrocarbon exploration." GEOPHYSICS 74, no. 2 (March 2009): B47—B59. http://dx.doi.org/10.1190/1.3076607.
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Delineation of hydrocarbon prospective areas is an important issue in petroleum exploration. The geoelectric method helps to identify attractive areas and reduces the overall drilling risk. For this purpose, induced polarization (IP) effects are mapped caused by the presence of epigenetic pyrite microcrystals in sedimentary rocks. These crystals occur in a shallow halo-shaped mineralogical alteration zone, often overlying a deeper-seated hydrocarbon accumulation. Local enrichment in pyrite results from reducing geochemical conditions below an impermeable layer. The imperfect top seal of the accumulation permits minor amounts of hydrocarbons to escape and migrate through the overlying rocks to shallower levels. During migration, hydro-carbons encounter an impermeable barrier, forming an altera-tion zone. Induced polarization logging and coring in wells confirm this working model. Geoelectric surveying visual-izes anomalies in electric potential difference measured be-tween receiver electrodes. The differentially normalized method (DNME) inverts the registered decay in potential differences, establishing a depth model constrained by seismic and petro-physical data. Diagnostic geoelectric attributes are proposed, giving a better grip on chargeability and resistivity distribution. Acquisition and processing parameters are adjusted to the target depth. Encouraging results are obtained in deeper [Formula: see text] as well as in very shallow water. Onshore, a grounded current transmitter is used. Geoelectric surveys cover different geologic settings with varying target depths. The success ratio for predicting hydrocarbon occurrences is high. So far, 40 successful wells have been drilled in Russia on mapped geoelectric anomalies. Out of 126 wells, the method produced satisfactory results in all but two cases. The technique reduces the risk attached to new hydrocarbon prospects and allows better ranking at a reasonable cost.
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Christensen, J. R., E. H. Stenby, and A. Skauge. "Review of WAG Field Experience." SPE Reservoir Evaluation & Engineering 4, no. 02 (April 1, 2001): 97–106. http://dx.doi.org/10.2118/71203-pa.
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Summary In recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been reinjected in water-injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG injection has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or the accumulating of water toward the bottom. Because the residual oil after gasflooding is normally lower than the residual oil after waterflooding, and three-phase zones may obtain lower remaining oil saturation, WAG injection has the potential for increased microscopic displacement efficiency. Thus, WAG injection can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and by leading to improved microscopic displacement. This study is a review of the WAG field experience as it is found in the literature today,1–108 from the first reported WAG injection in 1957 in Canada to the new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG injections with hydrocarbon or nonhydrocarbon gases. Well spacing is very different from onshore projects, where fine patterns often are applied, to offshore projects, where well spacing is in the order of 1000 m. For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5 to 10% of the oil initially in place (OIIP). Very few field trials have been reported as unsuccessful, but operational problems are often noted. Though the injectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). Improved oil recovery by WAG injection is discussed as influenced by rock type, injection strategy, miscible/immiscible gas, and well spacing. Introduction The WAG injection was originally proposed as a method to improve sweep of gas injection, mainly by using the water to control the mobility of the displacement and to stabilize the front. Because the microscopic displacement of the oil by gas is normally better than by water, the WAG injection combines the improved displacement efficiency of the gas flooding with an improved macroscopic sweep by water injection. This has resulted in improved recovery (compared to a pure water injection) for almost all of the field cases reviewed in this work. Although mobility control is an important issue, other advantages of the WAG injection should be noticed as well. Compositional exchanges may give some additional recovery and may influence the fluid densities and viscosities. Reinjection of gas is favorable owing to environmental concerns, enforced restrictions on flaring, and - in some areas - CO2 taxes. The WAG injection results in a complex saturation pattern because two saturations (gas and water) will increase and decrease alternately. This gives special demands for the relative permeability description for the three phases (oil, gas, and water). There are several correlations for calculating three-phase relative permeability in the literature,95 but only recently has an approach been designed for WAG injection using cycle-dependent relative permeability.95 WAG injection has been applied with success in most field trials. The majority of the fields are located in Canada and the U.S., but there are also some fields in the former USSR. WAG injection has been applied since the early 1960's. Both miscible and immiscible injections have been applied, and many different types of gas have been used. This work gives a review of the WAG injection as it is found in the open literature today. Unfortunately, not all field trials are adequately described, and this overview is limited to the publicly accessible data. We have chosen to use an inclusive definition of WAG injection that covers all cases where both gas and water are injected in the same well. A process where one gas slug is followed by a water slug is, by definition, considered a WAG process. In the literature, WAG injection processes are also referred to as combined water/gas injection (CGW).100 Classification of the WAG Process. WAG processes can be grouped in many ways. The most common is to distinguish between miscible and immiscible displacements as a first classification. Miscible WAG Injection. It is difficult to distinguish between miscible and immiscible WAG injections. In many cases a multicontact gas/oil miscibility may have been obtained, but much uncertainty remains about the actual displacement process. In this paper, we have used only the information from the literature and find that most cases have been defined as miscible. It has not been possible to isolate the degree of compositional effect on oil recovery by WAG injection. Miscible projects are mostly found onshore, and the early cases used expensive solvents like propane, which seem to be a less economically favorable process at present. Most of the miscible projects reviewed are repressurized in order to bring the reservoir pressure above the minimum miscibility pressure (MMP) of the fluids. Because of failure to maintain sufficient pressure, meaning loss of miscibility, real field cases may oscillate between miscible and immiscible gas during the life of the oil production. Most miscible WAG injections have been performed on a close well spacing, but recently miscible processes have also been attempted even at offshore-type well spacing.86–90 Immiscible WAG Injection. This type of WAG process has been applied with the aim of improving frontal stability or contacting unswept zones. Applications have been in reservoirs where gravity-stable gas injection cannot be applied because of limited gas resources or reservoir properties like low dip or strong heterogeneity. In addition to sweep, the microscopic displacement efficiency may be improved. Residual oil saturations are generally lower for WAG injection than for a waterflood and sometimes even lower than a gasflood, owing to the effect of three-phase and cycle-dependent relative permeability.96,97 Sometimes the first gas slug dissolves to some degree into the oil. This can cause mass exchange (swelling and stripping) and a favorable change in the fluid viscosity/density relations at the displacement front. The displacement can then become near-miscible. Hybrid WAG Injection. When a large slug of gas is injected, followed by a number of small slugs of water and gas, the process is referred to as hybrid WAG injection.38–42 Others. A process where water and gas are injected simultaneously (SWAG injection) has been tested in a few reservoirs.37,106–108 Although this process is not the main scope of the paper, a few comments are given at the end. A final version of the cyclic injection is in the literature presented as Water Alternating Steam Process (WASP).102 Reviews of field cases will not be included in this paper.
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JPT staff, _. "E&P Notes (June 2021)." Journal of Petroleum Technology 73, no. 06 (June 1, 2021): 14–19. http://dx.doi.org/10.2118/0621-0014-jpt.
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Angola Opens Congo, Kwanza Blocks in Ongoing Bid Round Angola’s National Oil, Gas, and Biofuel’s Agency has opened blocks for licensing in the Onshore Lower Congo Basin and the Onshore Kwanza Basin as part of its 2020 oil and gas licensing round. This latest call to tender is part of the agency’s ongoing 2019–2025 hydrocarbons licensing strategy. The Onshore Lower Congo Basin Blocks include CON1, CON5, and CON6; while the Onshore Kwanza Basin Blocks comprise KON5, KON6, KON8, KON9, KON17, and KON20. The round aims to expand research and evaluation activities across sedimentary basins, increase geological knowledge of Angola’s hydrocarbon potential, and invite a new wave of explorers to yield new discoveries. Raven Field Startup for BP in Egypt Natural gas has begun flowing from the BP-operated Raven field, the third stage of the company’s major West Nile Delta (WND) development off the Mediterranean coast in Egypt. The $9-billion WND development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. Raven is currently producing approximately 600 MMcf/D with a peak potential of 900 MMcf/D and 30,000 B/D of condensate. Raven follows the Taurus/Libra and Giza/Fayoum projects, which started production in 2017 and 2019, respectively. It produces gas to a new onshore processing facility, alongside the existing WND onshore processing plant. In total, the WND development includes 25 wells producing gas to the onshore processing plant via three long-distance subsea tiebacks. The onshore facilities—including the new Raven facility—now have a total gas processing capacity of around 1.4 Bcf/D of gas. All gas produced is fed into Egypt’s national grid. BP is the operator and has an 82.75% stake in the WND development, with Wintershall Dea holding the remaining 17.25% interest. CGX Secures Rig for Kawa-1 Well off Guyana CGX Energy and Frontera Energy, joint venture partners in the Petroleum Prospecting License for the Corentyne block offshore Guyana, have secured semisubmersible Maersk Discoverer to drill the Kawa-1 well. An early third quarter spud for the exploration well is targeting a Santonian age, stratigraphic trap, interpreted to be analogous to the discoveries immediately to the east on Block 58 in Suriname. The well is anticipated to be drilled to a total depth of approximately 6500 m in a water depth of approximately 370 m. The contract has an estimated duration of 75–85 days and has a one-well option attached. If exercised, that probe would spud in the nearby Demerara Block and take an estimated 40 days to reach its target. Talos’ Bulleit Reservoir in US Gulf Smaller Than Expected A technical assessment of the main producing sand performance at Talos Energy’s Green Canyon Block 21 Bulleit field in the US Gulf has indicated a smaller reservoir than originally anticipated. Project partner Otto Energy said the assessment included detailed bottomhole pressure and reservoir performance data collected after hookup and first production. The Block 21 field is flowing via a single subsea well tied back to a platform in nearby Green Canyon Block 18. While additional technical work is ongoing, the currently favored path forward is to move away from the current sand and execute a recompletion of the well in the shallower DTR-10 sand. A DTR-10 recompletion will require the procurement of long-lead items from manufacturers, which are expected to cost $3.5 million with payment expected in mid-2021. The recompletion is expected to begin in mid-2022, with production from the DTR-10 immediately following in mid-to late 2022. Captain Field EOR Stage 2 Project a Go Ithaca Energy, operator of the Captain field, has sanctioned the Captain Enhanced Oil Recovery (EOR) Stage 2 project in the UK Central North Sea after receiving Field Development Plan Addendum consent from the Oil and Gas Authority. EOR Stage 2 is designed to significantly increase hydrocarbon recovery by injecting polymerized water into the reservoir through additional subsea wells, subsea infrastructure, and new topsides facilities. Stage 1 of the project demonstrated that polymer EOR technology can work, with the production response in line with or better than expected across all injection patterns, helping maximize economic recovery. The Captain field was discovered in 1977, in Block 13/22a located on the edge of the outer Moray Firth. The billion-barrel field achieved first production in March 1997—over 24 years ago. Ithaca Energy holds 85% working interest, while partner Dana Petroleum holds the remaining 15%. Equinor Touts new Tyrihans Field Discovery Equinor and partners Total E&P Norge AS and Vår Energi AS have struck oil and gas in a new segment belonging to the Tyrihans field in the Norwegian Sea. Exploration well 6407/1-A-3 BH in production license 073 was drilled from sub-sea template A at Tyrihans North. The well was drilled to a measured depth of 5332 m by semisubmersible drilling rig Transocean Norge and struck a gas column of about 43 m and an oil column of about 15 m in the Ile formation, including about 76 m of moderate to good reservoir quality sandstone. In the Tilje formation, moderate to good quality water-bearing reservoir was struck. The Tyrihans field is in the middle of the Norwegian Sea, some 25 km southeast of the Åsgard field and 220 km northwest of Trondheim. The licensees consider the discovery commercial and intend to start production immediately. Recoverable resources are so far estimated at between 19 and 26 million BOE. Maersk Awarded Intervention Work off Brazil Maersk Drilling has been awarded a contract with Karoon Energy Ltd. for the semisubmersible rig Maersk Developer to perform well intervention on four wells at the Baúna field offshore Brazil. The contract is expected to begin in the first half of 2022, with a firm duration of 110 days. The value of the contract is $34 million, including rig modifications and a mobilization fee. The contract contains options to add up to 150 days of drilling work at the Patola and Neon fields. Carnarvon Completes Farmout of Buffalo Project Carnarvon Petroleum has completed the farmout of 50% of the Buffalo project to Advance Energy PLC. On 17 December 2020, Carnarvon announced that Advance Energy would acquire 50% of the Buffalo project off the west coast of Australia by funding the drilling of the Buffalo-10 well up to $20 million on a free carry basis. Advance met this funding requirement and now has a 50% interest in the project. The well is on track to be drilled in late 2021, subject to securing a drilling rig, where the tendering process is already underway. Following the well, the joint venture will acquire development funding from third-party lenders and any additional funding will be provided by Advance as an interest-free loan. The current plan is to suspend a successful well as a future producer and begin early development studies during 2021. Shell Hires Seadrill Rig for Brazilian Campaign Shell has contracted Seadrill’s drillship West Tellus for a new drilling campaign offshore Brazil this year. The program is expected to start in BC-10 of the Campos Basin, where Shell operates the Parque das Conchas made up of the Abalone, Argonauta, and Ostra fields. BC-10 has produced more than 100 million bbl since oil first started flowing from the block in 2009. The drillship will be used on the third phase of BC-10 activity, which includes five additional production wells and two water-injection wells at the Massa and Argonauta O-Sul fields, with the wells connected to the Espirito Santo FPSO. Shell owns a 50% operating stake in BC-10. India’s ONGC retains a 27% minority share and Qatar Petroleum the remaining 23%. Following the BC-10 work, the operator is expected to drill the first wells in the Campos Basin’s C-M-791 block, which was acquired during the 15th bid round held in 2017. Shell owns a 40% operating stake in the block, with Chevron retaining a 40% interest and Portugal’s Galp Energia the remaining 20%. Panoro Energy Kicks Off 2021 Drilling Campaign Offshore Gabon Panoro Energy has initiated its 2021 Gabon drilling campaign with the spudding of the Hibiscus Extension well on the Dussafu Marin Permit. That well will be followed by drilling at Tortue and Hibiscus North. Hibiscus and Tortue are two out of a total of six discovered fields within the Dussafu Permit offshore Gabon. Panoro currently holds a 7.5% interest in the license and has entered into an agreement to acquire an additional 10% working interest in the Dussafu Permit, bringing its total ownership to 17.5% following completion of the transaction. The Extension well is being drilled with the jackup Borr Norve and is the first well in a three-well campaign planned on Dussafu during 2021. The well is planned as a vertical well to test structure, oil, and reservoir presence in what is believed to be a possible northerly extension of the Gamba reservoir in the Hibiscus field. The well is positioned about 3 km northwest of the Hibiscus discovery well drilled by the joint venture in 2019. The initial well and its appraisal sidetrack established a 2P gross recoverable reserves of just over 46 million bbl at the Hibiscus field. The Extension well is expected to take around 30 days to drill and log to a total depth of 3500 m. Success at the probe could prompt one or two appraisal side-tracks to further delineate the field. Following the Hibiscus Extension, the rig will move to drill a horizontal production well, DTM-7H, at the Tortue field. This will complete the Phase 2 development of Tortue and, along with DTM-6H, will bring the total number of production wells at Tortue up to six. An exploration well at the Hibiscus North prospect, located approximately 6 km north-northeast of the initial Hibiscus well is also scheduled. Hibiscus North is a separate 10–40 million bbl prospect that could be tied into the Hibiscus/Ruche development project. Puma West Strike for BP in the US Gulf An exploration well at the Puma West prospect in the deepwater US Gulf has yielded a significant oil discovery for operator BP. The well, on Green Canyon Block 821, was drilled using Seadrill drillship West Auriga to a total depth of 23,530 ft and encountered oil pay in a high-quality Miocene reservoir with fluid properties like productive Miocene reservoirs in the area. Preliminary data supports the potential for a commercial volume of hydrocarbons. The Puma West partners will begin planning an appraisal program to better define the discovered resource. The discovery well has been suspended as a keeper well to preserve future utility. Puma West is located west of the BP-operated Mad Dog field and is approximately 131 miles off the coast of Louisiana in 4,108 ft of water. The Puma West is operated by BP with a 50% working interest. Partners include Chevron with 25% and Talos Energy with the remaining 25%. Petrobras Pushes First Oil at Mero Into 2022 Petrobras has postponed first oil from its Mero 1 field via the FPSO Guanabara in the Santos Basin offshore Brazil due to delays with the production system. Startup at Mero 1 was originally expected in the fourth quarter of this year and is now expected to begin flowing during the first quarter of 2022 due to COVID-19 pandemic-related delays with the buildout of the production system in China. The FPSO will be installed in the Mero field, which belongs to the Libra Block, in the Santos Basin pre-salt area, with a processing capacity of 180,000 OPD. The field is operated by Petrobras (40%) in partnership with Shell Brasil Petróleo (20%), Total E&P (20%), CNODC Brasil Petróleo e Gás (10%), CNOOC Petroleum Brasil (10%), and Pré-Sal Petróleo, which is the contract manager.
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Luo, Erhui, Zifei Fan, Yongle Hu, Lun Zhao, and Jianjun Wang. "An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 59. http://dx.doi.org/10.2516/ogst/2019018.
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Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.
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Cook, Richard A. "Interpretation of the Geochemistry of Oils of Taranaki and West Coast Region, Western New Zealand." Energy Exploration & Exploitation 6, no. 3 (June 1988): 201–12. http://dx.doi.org/10.1177/014459878800600303.
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The predominant hydrocarbons produced in the Taranaki Basin are gas condensates, although oil has been discovered at several widespread locations and therefore remains a priority exploration objective. Study of the oil geochemistry by means of bulk chemical characteristics, isotope and biomarker content improves our understanding of their source rocks and maturation histories. Results show that the oils and condensates throughout the region are similar in their bulk chemical character, source environment and levels of maturation suggesting a common source for all the hydrocarbons. The source environments as indicated by biomarkers were terrestrial fresh water swamps with low bacterial anoxic conditions. The primary plant material deposited was vascular plant debris, and onshore in northern Taranaki and in the Murchison Basin, angiosperm debris was an important additional component. These angiosperm indicators are absent from the West Coast and southeastern Taranaki oils and condenstates. The overall environment of the oil sources rocks is similar to that which formed the high volatile coals of the West Coast. These coals, on source rock analyses, also reveal a perhydrous character equivalent to the high hydrogen index normally associated with marine oil source rocks. Maturation levels of the oils, equivalent to a vitrinite reflectance level of Ro 1.0% are indicated by biomarkers. The highest maturation levels reached by drilling so far are 0.9%. suggesting that oil source rocks in Taranaki Basin are at or below the maximum drilled depth of 5.5 km. After generation, the oils of the West Coast were slightly biodegraded as suggested by their low paraffin wax content. However, valid biomarker interpretations for source and maturation conditions are still possible. The widespread occurrences of oil and the consistent nature of the detailed chemistry of the oils suggest that in addition to gas condensate there is a reasonable prospectivity for oil especially in and adjacent to the Central Graben are of the Taranaki Basin and in parts of the West Coast.