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Day R.H.,Abr Incenvironmental Research And Services | Rose J.R.,Abr Incenvironmental Research And Services | Prichard A.K.,Abr Incenvironmental Research And Services | Streever B.,BP Exploration Alaska Inc.
Arctic | Year: 2015

We studied movement rates and the general flight behavior of bird flocks seen on radar and recorded visually at Northstar Island, Arctic Alaska, from 13 to 27 September 2002. Most of this period (13 - 19 and 21 - 27 September) had no gas-flaring events, but a major gas-flaring event occurred on the night of 20 September. Movement rates of targets on radar and of bird flocks recorded visually in the first ~50%-60% of the night were much lower during the non-flaring period than during the night of flaring, whereas rates in the last ~40%-50% of the night were similar in all periods. The general flight behavior of birds also differed significantly, with higher percentages of both radar targets and bird flocks exhibiting straight-line (directional) flight behaviors during the non-flaring periods and higher percentages of radar targets and bird flocks exhibiting non-straight-line (erratic and circling) flight behaviors during the gas-flaring period. During the night of gas flaring, the bright illumination appeared to have an effect only after sunset, when flocks of birds circled the island after being drawn in from what appeared to be a substantial distance from the island. On both radar and visual sampling, the number of bird flocks approaching the island declined over the evening, and the attractiveness of the light from flaring appeared to decline. The visibility of the moon appeared to have little effect on the behavior of birds. Because illumination from extensive gas-flaring is such a strong attractant to migrating birds and because most bird flocks fly at low altitudes over the water, flaring booms on coastal and offshore oil-production platforms in Arctic Alaska should be positioned higher than the mean flight altitudes of migrating birds to reduce the chances of incineration. © The Arctic Institute of North America.

Wood A.,BP Exploration Alaska Inc. | Renouf G.,Saskatchewan Research Council
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2014 | Year: 2014

Heavy oil waterfloods have been operating in the petroleum industry for more than fifty years. Over this time, many researchers have tried to identify flood management practices that would optimize recovery from these waterfloods. This multidisciplinary work tics simulation with the evaluation of field statistical results to determine the best operating practices for heavy oil reservoirs that have high permeability thief zones. The particular type of thief zone of concern in Alaskan heavy oil waterfloods is called a Matrix Bypass Event, or MBE. An MBE is a dramatic water breakthrough event in the form of a direct connection between the injector and producer whereby the waterflood process ceases and the injection water cycles directly to the producer without sweeping the matrix. This study evaluates operating strategics for reservoirs where MBEs have developed, taking into account the effects and interdependencies of pre-production, Voidage Replacement Ratio (VRR), and oil viscosity. Statistics from 30 Canadian heavy oil waterfloods were evaluated according to whether the VRR declined or rose compared to the previous month. Those that declined showed better oil recovery, particularly for the heavier oils. This finding laid the foundation showing that an operational practice called Cyclic Injection/Production would be beneficial, especially for heavy oil waterfloods. Cyclic Injcction-Production alternates active injection while production is shut in. followed by active production while injection is shut in. Simulation was performed with a 3-D compositional finite difference reservoir model based on a heavy oil reservoir in Alaska's North Slope. The simulation confirmed that optimal waterflooding practices for heavy oils are significantly different from optimal practiccs for light oil waterfloods. The best practices also varied according to whether the waterflood had developed an MBE. As long as no MBEs arc present and the producers are not bottomhole pressure limited, VRR of less than 1.0 and continuous injection arc recommended. For heavy waterfloods that have high perm thief zones, however, Cyclic Injection'Production and a VRR of less than 1.0 improve recovery.

Svedeman S.J.,Southwest Research Institute | Brady J.L.,BP Exploration Alaska Inc.
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2013

Laboratory tests were conducted to evaluate the effectiveness of oil/water separation in a deviated well casing that is located below the perforation intervals. Downhole water separation and reinjection is needed to reduce well operating costs associated with producing large amounts of water to the surface. In the casing separator, produced water flows downward from the well perforations with entrained oil buoyantly separated to the topside of the casing. A dip tube, running to the bottom of the casing, feeds a downhole pump that pumps the water into another level in the reservoir. A test facility was constructed to test the casing separator performance at a variety of well inclination angles, production flow rates, water cuts, and reinjection water flow rates. At each operating condition, the amount of oil entrained in the reinjection water was measured to determine the maximum amount of water that could be separated and still provide "clean" water to the downhole pump. Tests were conducted over well inclination angles from 18° to 75°. The maximum water velocity in the casing separator, for clean water, varied from 0.2 ft/sec to 0.4 ft/sec. The test results provided the information needed to determine how much water could be separated in the casing separator. With the separator performance data, the economics of reinjecting water with a downhole pump could be evaluated. Copyright 2013, Society of Petroleum Engineers.

Cater T.C.,Inc. Environmental Research and Services | Hopson C.,UMIAQ | Streever B.,BP Exploration Alaska Inc.
Arctic | Year: 2015

Tundra sodding, a new technique available to rehabilitate disturbed wetlands in the Arctic, is based on Iñupiaq traditional knowledge. C. Hopson, an Iñupiaq elder from Barrow and author of this paper, guided the development and field application of this new technique by providing traditional knowledge he learned as a youth from his elders. Tundra sodding has several advantages over other land rehabilitation techniques, the most important being that it can establish a mature plant community of indigenous species in a single growing season. In all sampling years, the plant communities at sodded sites were dominated by two rhizomatous graminoids, Eriophorum angustifolium and Carex aquatilis. These sedges also were dominant in all years in reference tundra. Also common to the plant communities in both reference tundra and sodded sites were 18 other vascular species (grasses, evergreen and deciduous shrubs, and forbs). Results from two to five growing seasons indicate that tundra sod can reduce the overall subsidence due to thawing of shallow permafrost. We harvested sod on three occasions from an area slated for gravel mining. In the summers of 2007 and 2008, we transplanted 334 m2 of tundra sod to portions of three sites to test the feasibility of the method. In summer 2010, we used the experience gained from that work to rehabilitate an entire site (1114 m2). This tundra sodding technique is labor intensive and costly compared to other rehabilitation techniques, but it offers advantages that justify its use when rapid rehabilitation of a disturbed site is needed. © The Arctic Institute of North America.

Johnson M.O.,BP Exploration Alaska Inc. | Milne J.R.,Baker Hughes Inc.
SPE/IADC Drilling Conference, Proceedings | Year: 2012

Since 1994 Coiled Tubing Drilling (CTD) has completed over 650 sidetracks on the North Slope of Alaska. In many aspects the window milling and drilling phase can be considered a mature technology. However, recent developments in the completion phase namely with the generation II side exhaust liner running tool (Gen II SELRT) have further increased job reliability, safety, and efficiency for the liner cementing completion phase. This paper will begin with a brief update on the status of CTD on the North Slope (3 rigs drilling on a daily basis) and discuss how many of the challenges with drilling through/below the production tubing have been dealt with. The cost for a CTD sidetrack with an equivalent amount of reservoir exposure and zonal isolation is about one half that of a rotary sidetrack on the North Slope. This is due to efficiencies in leaving the production tubing in place (dominant savings) and less consumables. In addition, CTD's enhanced capability for underbalanced drilling (UBD) and managed pressure drilling (MPD) make it attractive for some North Slope fields. While the electronically controlled drilling bottomhole assembly (BHA) has improved drilling performance, the electric line (EL) inside the CT has challenged the completion phase. CT wiper darts for separating cement from displacement fluid can no longer be used. The CT wiper dart would be damaged by the EL and visa versa. Instead, the new liner running tool discussed in this paper exhausts the contaminated cement/mud interface to the annulus at top of liner before launching the liner wiper plug (LWP). Over 76 liners have been cemented with the side exhaust technique. The last 34 jobs have been done with the Gen II SELRT that uses mechanical dogs to close the path through the LWP, side exhaust, and launch the LWP when desired. This new tool increases job efficiency over the first generation tool and continues to provide reliable liner cementing with EL in the coil. Copyright 2012, IADC/SPE Drilling Conference and Exhibition.

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