The Texas Supreme Court ruled late in April that the Railroad Commission of Texas, the state’s oil and gas regulator, does not have exclusive jurisdiction over environmental contamination cases, which can be settled in court. An offshore worker has called for action after he and colleagues were exposed to radiation, BBC Scotland can reveal. The incident happened on EnQuest’s Thistle platform, off Shetland, last December.
While drug use is a problem among industrial workers nationwide, it raises particular concern in the oil patch as US production surges to record levels in what is already one of the nation’s most dangerous sectors. Inhalation of crystalline silica dust is second only to asbestos as a hazard to construction workers. This video discusses important things to know. Evaluation of Occupational Ocular Trauma: Are We Doing Enough To Promote Eye Safety in the Workplace? The use of eye PPE among workers who sustain an eye injury in the workplace remains low.
In both developed and developing countries, noise is regarded as the most common occupational hazard in various industries. The present study aimed to examine the effect of sound pressure level on serum cortisol concentration in three different times during the night shift. An examination of studies on air pollutants associated with oil and gas extraction finds that measurements near operational sites have generally failed to mark levels above standard health benchmarks; yet, many studies find poor health outcomes increasing as distance from these operations decreases. "I have some patients whose symptoms I can’t explain," physician Ulrike Meyer said, describing nosebleeds, rare cancers, and respiratory illness among a dearth of data. A partnership between ConocoPhillips, Marathon Oil, and XTO Energy has resulted in the opening of a new clinic catering to the safety and health of oil and gas employees in Carlsbad, New Mexico.
Hao, Hongda (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Zhao, Fenglan (China University of Petroleum) | Wang, Zhixing (China University of Petroleum) | Fu, Zhongfeng (China University of Petroleum) | Li, Wengfeng (China University of Petroleum) | Wang, Peng (China University of Petroleum) | Zhang, Meng (China University of Petroleum) | Lu, Guoyong (China University of Petroleum) | Zhou, Jian (China University of Petroleum)
As an effective method for resource utilization, CO2 huff-n-puff can be utilized to reduce CO2 emissions and enhance oil recovery in edge-water flock-block reservoir, which was implemented in Jidong Oil Field, China since 2008 with oil production of 6.5×104 bbls by 2015. During operation period, synergetic effect was observed in adjacent wells with water cut drops and oil increments in a horizontal well group. Experimental and numerical simulations were conducted to investigate synergetic mechanisms of CO2 huff-n-puff. 3D physical models with a horizontal well group and edge-water-driving system were established in laboratory to simulate the edge-water fault-block reservoir. The formation mechanisms and influence factors of synergetic CO2 huff-n-puff were studied through laboratory experiments. Base reservoir model was also built to further discuss the synergetic types and injection allocations for CO2 huff-n-puff in horizontal well group.
Synergetic CO2 huff-n-puff is a smart gas cycling strategy for the horizontal well group to balance the formation pressure and replace the interwell oil. Experimental and numerical results showed that after CO2 injected into low tectonic position of the reservoir, synergetic effect could be observed in high position well with water cut drops and oil increments. The mechanisms of synergetic effect can be recognized as formation energy supplement, gas sweeping, gravity segregation and CO2-assisted edge-water driving. The stratigraphic dip and heterogeneity are advantages for the formation of synergetic effect. The synergetic types of CO2 huff-n-puff can be summarized as single-well synergy and multi-well synergy. For single-well synergy, edge-water invasion can be effectively controlled by energy supplement after CO2 injected into relatively low position well. For multi-well synergy, better synergetic effect and remaining oil replacement can be achieved after gas injected through different positions of the well group. The development efficiency of synergetic CO2 huff-n-puff can be enlarged with 700t CO2 injected into low position well + 100t CO2 into high position well, and about 5767.9 bbls oil of the well group could be recovered with the soaking time of 50d.
Enhanced oil recovery (EOR) is a general application used in mature oil fields to generate additional reserve growth. Several types of EOR applications are implemented in the oil industry. One such application is the injection of gas into a reservoir as a gas displacement recovery (GDR) mechanism to induce additional reserve growth. A specific type of GDR application is the immiscible water-alternating-gas (IWAG) displacement process. In this application a slug of water is put into an injection well, followed by gas, which exists as a separate phase from the water and oil. Water and gas injection slugs are alternated until the designed amount of gas has been injected, or as field production dictates. Continuous water (case water) is typically injected after the IWAG process.
Herein, the state-of-art of IWAG EOR is described from an extensive literature review. First, the theories of the recovery mechanisms that cause IWAG to produce incremental oil are described. These mechanisms include viscosity reduction, 3-phase relative permeability, oil swelling, and oil film flow, all of which are a function of fluid and rock-fluid interactions. Next, salient laboratory studies are summarized, including micromodel and core floods. These studies test pore-level characteristics, displaying ranges of residual non-wetting phase saturations (hydrocarbons) down to 0.13 to 0.25 and incremental oil recovery ranging from 14% to 20% of OOIP. Some experiments isolate a specific recovery mechanism in order to determine its validity and contribution to recovery. Studies generally point to the conclusion that the gas type shows no discernable difference in recovery character.
The paper concludes with a synopsis of results from small-scale field trials and field-scale projects in both heavy and light oil. Both simulation modeling and field trials are summarized. Projects have been implemented with varying types of gases, WAG ratios, and gas slug sizes, resulting in incremental reserve growth being reported in the range of 2 to 9%. The fundamental immiscible recovery mechanisms in IWAG can produce lower cost and faster response EOR projects, with moderate recovery efficiency gains.
For the majority of older oil and gas facilities, the production and processing environment has changed significantly since its early days, with increasing operational and maintenance overheads and obsolete control technology often threatening to bring lift costs above production revenues. As a result, Production and Operational Efficiency has significantly worsened in recent years with many of these assets performing well below optimum production, equating to approximately 500,000 barrels of lost production per day in the UKCS or £10bn/annum (based on Oil and Gas UK production availability figures) Enquest's Thistle platform was one of these assets and was due to be decommissioned until the brave decision was taken to extend its life by putting in place the Late Life Extension Program (LLX). Using groundbreaking Asset Life Extension techniques and methodologies, this old facility is in the process of being redesigned by simplifying the topsides which in turn, is leading to improved availability, increased production and reduced operating costs. A simplified, safer process in a controlled environment has been created whilst balancing the requirements of a capital budget, against reduced OPEX and process risk. It is estimated that the modifications have added at least 15 years of safe, viable, profitable production to the Thistle's lifespan, a great example of deferring decommissioning and Maximising Economic Recovery.
Continuous surveillance of production and injection well flow rates throughout field life is essential for well performance monitoring, reservoir management and to meet operational targets. Ideally, surveillance would be achieved using multiphase flow meters on each well, but frequently this is not economically feasible. As an alternative to providing continuous flow rate surveillance, several real-time rate estimation methods can be implemented using existing surface/subsea & sub-surface measured variables, and obtain Best Real Time Estimations (BRTEs) based on the confidence in each method. BRTEs at well level can be added to provide Aggregated Real Time Estimations (ARTEs) at both field and facility levels. Where physical meters exist, a direct comparison and cross validation can be made with the relevant ARTEs, ensuring accuracy and confidence in ongoing well and field surveillance.
The above BRTEs/ARTEs approach has been deployed on a well performance monitoring system in the Petrofac operated Don Fields Development (North Sea UKCS), centred on real-time surveillance and advanced data processing & visualisation. Estimations were implemented based on first principle equations validated with integrated models of reservoir, well and subsea/surface networks, providing Liquid Rate, Oil Rate/Water Rate, Gas Rate and Gas Lift Rate estimations on the production wells, and Water Injection Rate estimations on injection wells. Deployment included user interfaces to allow BRTEs configuration and updating, as well as Aggregate Tables to compare ARTEs with physical field and facility flow meters.
In summary, BRTEs/ARTEs successfully achieved the concept of virtual flow metering on the Don Development, providing the means for continuous well, field and facility surveillance. This enhanced surveillance experience is enabling unique optimization opportunities, allowing engineers to determine optimum settings for maximizing asset production and associated revenue.
McElhiney, John E. (Pratt Technology Management) | Burger, Edward D. (EB Technologies Inc.) | Maxwell, Stephen (Commercial Microbiology Ltd.) | Davis, Roy A. (Sulfate Removal Systems) | Walsh, John Michael (Petroleum Development Oman)
A comprehensive evaluation of the potential for preventing reservoir souring through the use of Sulphate Rejection Membranes (SRM) was made for the Ursa-Princess Waterflood (UPWF), deepwater Gulf of Mexico. The operator, Shell Exploration and Production Company (SEPCO) has long believed that injection of seawater is a precursor to souring; the question is not 'if' but 'when' souring would occur.1 Metallurgy of the producer well tubing, casing, safety valves and topsides is not consistently sour safe and retrofitting would have rendered the waterflood project economics unviable. Therefore, prevention of souring by SRM was investigated, evaluated and adopted in order to avoid retrofitting the metallurgy. This is the first time that an SRM has been selected by a major operator for a seawater waterflood project based primarily on prevention of souring, while accepting SRM as proven for scale control.
The Ursa Tension Leg Platform (TLP) produces from the Ursa and Princess Fields in the Mississippi Canyon area of the Gulf of Mexico, roughly 150 miles southeast of New Orleans. These fields comprise eight offshore continental shelf (OCS) blocks.
The Ursa field was discovered in 1990. First oil through the Ursa platform was in 1999. The Princess Field was discovered in 2000. First oil from Princess, through a subsea tieback to the Ursa platform, was in December 2003. Total production from the Ursa platform peaked in the 2004 period at close to 150,000 BOPD. This phase of production was based on primary depletion driven by fluid expansion and natural compaction of the sedimentary rock with no appreciable aquifer support. Such compaction creates stability problems, including potential sand failures, and a range of drilling challenges. Following several years of primary production from these two fields, it was decided to install a seawater waterflood.
The decision to waterflood was based on a number of factors including improving sand stability, maintaining reservoir pressure, improving the long-term sustainability of the production drive, and improving the long term economic benefits associated with increased ultimate recovery.
The Ursa and Princess Fields have their main reservoirs in common and are in pressure communication. The Yellow reservoir is the largest and most productive. Waterflood is targeted exclusively for the Yellow reservoir which does not have natural aquifer support. It is an Upper Miocene turbidite reservoir of some 12,000 acres. Produced fluids are sweet and relatively light (average 27°API), with a bubble-point pressure of 5,900 psi at a reservoir temperature of 175 °F. Reservoir pressure had dropped significantly from an initial value of 11,800 psi. At the time that the decision was made to implement a waterflood the flowing bottom hole tubing pressure was already 5,500 psi.
Guest column - No abstract available.