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Collaborating Authors
production shut-in
Another potential hurricane in the Gulf of Mexico (GOM) is on a path toward Louisiana this week, leading oil and gas operators to evacuate offshore facilities and shut in production. Tropical Storm Zeta hit Mexico's Yucatan Peninsula on Monday as a Category 1 hurricane before it weakened. Zeta is expected to hit Louisiana at or near hurricane strength on Wednesday. The Bureau of Safety and Environmental Enforcement (BSEE) activated its hurricane response team in response to the severe weather. Based on operator reports, BSEE said personnel was evacuated from 154 production platforms (24% of 643 manned GOM platforms) and three nondynamically positioned rigs (30% of 10).
- North America > Mexico (1.00)
- North America > United States > Louisiana (0.58)
Abstract Separate handling of fluids following a remediation/workover job or treating of slop oil emulsions has become a good practice to reduce upsets in oil and water treating facilities and to avoid production shut-in. This paper demonstrates that the use of high-speed disc-stack centrifuges can be a cost-effective process for handling these fluids, treating difficult emulsions, and generating little or no waste. The physical operation of these centrifuges as dehydrators (purifiers) and/or as deoilers (clarifiers) and their performance in various field applications are presented. Introduction Frequent upsets can occur in the water treating facilities due to the commingling of main production streams with the so-called non-produced fluids resulting in an increase of oil content in the discharged water quality and/or an increase BS&W in dehydrated crude. These non-produced fluids include slop oil from the Wet Oil Tank, fluids produced following unloading of wells after acid stimulation or completion/workover operation, platform deck drains, and residuals of cleaning chemicals from deck and facilities washing. Generally, production facilities use gravity separation vessels and gas flotation cells enhanced by chemical addition to separate the dispersed oil from water to meet the produced water discharge oil and grease limits (NPDS monthly average of 29 mg/L). While these systems have provided reasonable oil/water separation under "Normal Operating Conditions," they are generally unable to handle stable emulsions that are difficult to treat chemically and require long residence time to separate. The oil/water emulsions are stabilized by a blend of oil-wet solids (corrosion and scale compounds and silt/clay fines) and/or chemical additives such as surfactants corrosion inhibitors, mutual solvents, biocide, and other chemicals depending on the treatment. In the past few years, the industry has realized the impact of these non-produced fluids on offshore discharged water and on potential interruption of production. As a result, several field and laboratory studies were initiated to develop approaches for minimizing their impact. Results suggested that a combination of on-site fluid/chemical compatibility tests, proper selection of stimulation chemicals and/or surface treating chemicals, and separate handling facilities for these fluids would he the best approach. For example, for acid flowbacks and assuming that the proper chemical additives and treatment are used, fluids from a well are generally produced into a test separator or into a holding vessel until the pH approaches 6 before they are commingled with the main production. There are several options to handle these non-produced fluids that are stored in holding tanks or vessels. The cost of each option is site specific and depends on the nature and volume of the fluids/emulsions to be handled. The cost can vary from $1 to more than $15 per barrel. These options include (1) producing the fluids into a tank on the platform or onto a barge and bringing them to shore for subsequent disposal, (2) injecting the fluids above fracture pressure in a permitted disposal well, (3) neutralizing and demulsifying the fluids before introducing them slowly to the production stream, (4) pumping the fluids directly into the production facilities and subsequently to the crude pipelines. Most of these options require dedicated holding tanks to separate the oil from the oily water and can take a few weeks to bring a well to full production without causing facilities upsets or production shut-in. In addition, spacing of well stimulation over time may become necessary to reduce the impact of acid flowbacks. P. 359
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.68)
- Water & Waste Management > Water Management > Lifecycle > Discharge (0.54)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Abstract A case history of the Hemlock Reservoir of the McArthur River Field in Cook Inlet, Alaska demonstrates continued water injection during an extended production shut-in resulted in higher oil rates once production was resumed. With volcanic eruptions of Mt. Redoubt, located 30 miles to the south, production was shut-in for over three months during 1990 due to interruption of oil shipping and storage operations. This paper describes the results of effective waterflood management and the benefits of data gathering through pressure mapping and static tracer surveys during the production shut-in. Maintaining water injection during the 1990 shut-in raised the average reservoir pressure by 230 psig and resulted in higher oil rates upon the resumption of production. Previous extended production shut-ins during 1976 and 1985 were followed by oil rate declines of up to 25%. Reservoir pressures were monitored during continued water injection while the production was shut-in to define areas of lower pressure and poor reservoir conformance. Pressure mapping and static tracer surveys significantly improved the Hemlock reservoir description. Based on this data, infill drilling and waterflood conformance projects are being designed to increase recovery through improved vertical and areal sweep efficiency. The waterflood management decisions and reservoir analysis techniques discussed in this paper provide useful insights to increase oil rate and reserves in future waterflood applications. This case history describes waterflood surveillance and analysis which may be implemented during extended production shut-ins to improve reservoir description and define recovery enhancement projects. Introduction The McArthur River Field is located approximately 65 miles southwest of Anchorage, Alaska in the Cook Inlet (Figure 1). The main oil productive horizon is the Hemlock Reservoir, a north-south trending asymmetrical structure with the top location approximately 9,000 feet subsea. P. 129^
- North America > United States > Alaska > Kenai Peninsula Borough > Cook Inlet (0.94)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.84)
- Geology > Geological Subdiscipline > Volcanology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
- North America > United States > Alaska > Cook Inlet Basin > Mcarthur River Field > Hemlock Formation (0.99)
- North America > United States > Alaska > Cook Inlet Basin > Hemlock Formation (0.99)
- North America > United States > Alaska > Cook Inlet Basin > Granite Point Field > Hemlock Field > Middle Kenai Formation (0.98)
- (2 more...)
ABSTRACT This paper discusses the advantages and disadvantages of semisubmersibles and large tankers (150,000 to 250,000 DWT) when used as floating production and storage systems. Primary technical considerations which are discussed include:Mooring Loads Production Risers Vessel Motions Crude Storage and Offloading System Reliability Field Shut-In Parameters Capital Expenditures Lead Times The data included is based on computer simulation, model tests, and industry successes in meeting similar challenges. INTRODUCTION In the past decade several fields have been produced in the North Sea with semi submersible drilling units which were converted to production units. As a result of the proven suitability of semi submersible production units in hostile environments (Argyle & Buchan Fields), many people believe that only semi submersibles are suitable for those locations. With the increasing use of converted tankers as floating production, storage and offloading units, it is appropriate to evaluate their suitability for more hostile environments. SYSTEMS EVALUATED Five basic configurations which are considered in this paper are: This includes a semisubmersible drilling unit (modified with production equipment), with continual offloading to dedicated shuttle tankers. This includes a semi submersible drilling unit (modified with production equipment), a permanently moored storage tanker, and periodic offloading with shuttle tankers. This includes special design and construction of a large semisubmersible, with periodic offloading with shuttle tankers. This includes a very large crude carrier (VLCC), or a converted tanker (150,000 to 250,000 DWT), permanently moored with an articulated tower or single anchor 1eg mooring (SALM) with a rigid yoke, and periodic offloading with shuttle tankers. This includes a converter a tanker or VLCC permanently moored with a turret mooring system, and periodic offloading with shuttle tankers. For each case, it was assumed that major pipe1ines are not in place, necessitating the use of shuttle tankers. MOORING LOADS Typical mooring loads (without shuttle tanker attached) are shown on Figure 1. The mooring forces are significantly lower for the tanker based unit which weathervanes than for a semi submersible exposed to beam seas. Therefore, a much greater factor of safety can be maintained with similar mooring systems, or the size of the tanker-based mooring can be reduced in order to minimize capital expenditures. The mooring loads for the tanker may be slightly larger than shown when the wind, waves and currents are not collinear.
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/16 > Fulmar Field > Fulmar Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/11b > Fulmar Field > Fulmar Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > P 2170 > Block 21/1a > Greater Buchan Field (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > P 2170 > Block 20/5a > Greater Buchan Field (0.98)