The use of vibration to improve oil recovery has long been investigated. The background for this novel technology is reviewed along with the project rationalizations, designs considerations, and measurements performed in advance of a downhole vibration stimulation field test. This field demonstration will pilot test the potential of downhole vibration to enhance oil recovery from a shallow oilfield in Osage County, Oklahoma. The project is supported by the Department of Energy (DOE), Seismic Recovery LLC, Phillips Petroleum Co., and Grand Resources, Inc. Recent literature has reported successful vibration stimulation in shallow reservoirs with high water oil ratios (WOR). Osage County has, like many areas of the United States, numerous old fields under waterflood, with many wells producing marginal oil with substantial water production. Introduction When wells in waterflooded fields are abandoned due to high water-cut, often there are still significant amounts of oil trapped in the formation, although production is not economical. Vibration stimulation is a possible method for improving oil production and increasing ultimate economic recovery in these situations. The vibration force introduced in the reservoir is thought to facilitate the movement of oil in one or more ways: by diminishing capillary forces; reducing adhesion between the rock and fluids; or causing oil droplets to cluster into "streams" that flow with the waterflood. Significance of Vibration Stimulation. The ability to generate sufficient downhole vibration energy to improve flow characteristics is a very intriguing concept. The economic potential for vibration stimulation for enhanced oil recovery is truly staggering. The Interstate Oil and Gas Compact Commission reported in 1995, "immobile oil is held in reservoirs by viscous and capillary forces&. Only a small amount of immobile oil can be recovered by conventional primary and secondary techniques. Instead, the 238 billion -bbls immobile oil reserve (U.S.) is the target for enhanced oil recovery techniques."1 Vibration stimulation has the capability to shift the relative permeability curve and, as an enhanced oil recovery technology, increase recovery of "immobile oil reserves." Vibration Stimulation Historical Background Russian Investigations. The interest in elastic-wave vibration stimulation (as opposed to non-elastic vibration, such as explosions) goes back to the 1950s. This interest is well documented in the paper by Beresnev and Johnson, in which the authors reported on the full spectrum of investigative work in both the USSR and USA.2 They review the efforts of over a hundred researchers probing the effects of man-made vibrations from the ultra sound range of 5 MHz to barely audible, low end of 1 Hz including traffic induced seismic stimulation. The effects of earthquakes on oil production were also reviewed, however the results of conventional and nuclear explosions were not.

Drilling for oil and gas in the Overthrust and Disturbed belts of the Rocky Mountains has received considerable attention in recent years. Zones having low pressure gradients are frequently encountered, when drilling in the mountains. Operating companies and drilling contractors have learned to respect lost circulation problems. This paper discusses Phillips Petroleum Company's approach for controlling this problem in a well drilled in Gallatin County, Montana. Using compressed air down the drill pipe to lighten the drilling mud's hydrostatic pressure is an accepted method of combating lost circulation. A parasite aerating string is a tubing string attached to the outside of the surface or intermediate casing and is used to inject air into the casing-drill pipe annul us. Reduction in hydrostatic pressure to effective mud weights of 6 ppg (719 kg/m2) or less can be obtained with the proper air/mud ratios and the correct setting depth of the air injection point. A parasite aerating string offers several advantages over using an air-mud mixture down the drill pipe: Ease of operation, no special procedure needed for making connections or trips. No changes in downhole equipment are required. Conventional bit hydraulics can be used. Air does not contact the open hole. Corrosion is limited to the coolest section of the hole and only above the injection point.

Summary Tubing failures caused by CO2 corrosion and erosion are examined. Corrosion inhibitors were used for batch treatments, formation squeezing and continuous injection downhole through the annulus. Plastic-coated tubing also was used. Evaluation was by surface corrosion monitoring, tubing caliper surveys and inspection of recovered tubing. Economics were reviewed. Introduction The Ekofisk field was discovered in the Norwegian sector of the North Sea in late 1969 by the Phillips Norway Group. This group is composed of Phillips Petroleum Co. Norway (37%), Norske Fina A/S (30%), Norske Agip A/S (13%), and the Petronord Group (20%). Seven geologically separate Fields have been developed with eleven producing platforms. Phase 1 of development was the completion of four subsea wells tied into a converted jackup with tanker loading using single-point mooring buoys. Phase 2 was the installation of three production platforms, subsea pipelines, and a million-bbl (159 000-m3) concrete storage tank. Phase 3 was in two parts. First, three production platforms, an oil line to Teesside, England, and a gas line to Emden, Germany, were installed. Finally, five more production platforms were brought on stream in 1979, resulting in platforms were brought on stream in 1979, resulting in the seven-field Greater Ekofisk development. There are 120 wells completed with most using 4 1/2-in. OD, 12.6-lbm/ft (114-mm OD, 18.8-kg/m) N-80 (after 1979, L-80 was used) tubing inside 7-in., 29-lbm/ft (178-mm. 43.2-kg/m) N-80 casing. Most wells are deviated, with a maximum deviation of 55 degrees. In a few of the higher-volume wells, a 5 1/2- × 5- × 4 1/2-in. (140- × 127- × 114-mm) tapered tubine string was selected. Except for the 5 1/2-in. (140-mm)completions, a 3.81-in. (96.8-mm) seating nipple was set at 550 ft (168 m) to locate wireline retrievable safety valves. The larger completions have 4.56-in. (115.8-mm) seating nipples. The production rates varied considerably both within and between fields. The low water-cut production was coupled with a CO2 content of 1.5 to 3 mol% in the gas phase (Table 1). phase (Table 1). Corrosion was found first in the surface flow lines and downhole safety valves in 1976. The first tubing failures occurred in 1978. A corrosion task force including personnel from. operations, corrosion, reservoir, process, personnel from. operations, corrosion, reservoir, process, and drilling engineering was established to recommend and to coordinate projects for combating the downhole corrosion. Three tubing failure case histories are reviewed in the First section of the paper, then control methods used and the results are described. Case History 1 Table 1 summarizes the flowing conditions for Well 1. This 10.500-ft (3200-m) total depth (TD) oil well was in service for only 309 days with 68 days downtime before the tubing was perforated because of erosion/corrosion. The tubing pared at a depth of 1,400 ft (427 m) during the work over to replace it. Parting was caused by severe circumferential wall thinning. The well was deviated 7 degrees at this point. The flowing velocity ranged from 21 to 61 ft/sec (6.4 to 7.9 m/s) from the bottom to the top of the tubing. Fig. 1 shows a perforated tubing length from a depth of 5,700 ft (1740 m). The corrosion attack is concentrated in one quadrant of the tubing. The deviation at this depth was 35 degrees. The CO2 partial pressure was 90 psi (620 kPa), and the well tests had shown negligible free water at the separator. Subsequent testing indicated water production as a tight emulsion of approximately 1%. The estimated corrosion rate for the failure is more than 400 mil/yr (10.2 mm/a). JPT P. 239

This paper provides details of a project to test horizontal waterflooding as a means of improved oil recovery in Osage County, OK. Supported by a grant from the Department of Energy (DOE), an independent operator, Grand Resources, Inc., has developed a process for selecting and developing candidate reservoirs for horizontal waterflooding. Reservoir screening is the first step in the process and then rock mechanics are used to predict wellbore stability for determining the most efficient completion method. Geologic and reservoir parameters are considered when selecting the radius of curvature for the horizontal well to be drilled and the air/foam drilling fluids to be utilized to avoid formation damage. The final step is to run a comprehensive set of logs through the curve and out into the reservoir allowing for petrophysical evaluation. To accomplish an economically successful project, given the basic assumption of an existing field infrastructure having an adequate water supply well available, the following three goals must be met:demonstrate that horizontal waterflooding is technically and economically feasible for recovering additional oil in shallow low permeability reservoirs;demonstrate that open hole completions are a viable technique based on wellbore stability considerations;demonstrate that short radius rotary steerable technology can drill horizontal wells at low cost and without reservoir damage. Introduction It is solidly established that significant amounts of oil are still trapped in the producing formations when wells in waterflooded fields are abandoned due to high water-oil ratio (WOR) causing production to be uneconomical. Many techniques have been developed with a goal of economically recovering this bypassed oil. This paper discusses the technique of using parallel horizontal water injection and production wells as a method of enhanced oil recovery. Background Historical Waterflooding in Osage County The Bartlesville reservoir in northeastern Oklahoma has been one of the most prolific oil producing formations in the United States. Ye1 reports that 1.5 billion barrels of oil have been produced from the Bartlesville formation through the 1960s. The Bartlesville formation remains an important producing horizon even though it is considered to be in a mature stage of depletion. In spite of the large cumulative production from the Bartlesville, the recovery efficiency has been low, usually less than 20% of the original oil in place(OOIP). Recovery during primary production operations is low due to:a solution gas-drive mechanism, which results in rapid pressure depletion andlow initial reservoir pressure which is a consequence of the shallow depth. The remaining 80% of the OOIP has attracted many secondary and tertiary recovery techniques to be attempted. Secondary recovery operations are often not effective or economic due to shallow depth, existence of natural fractures and low permeability. The Bartlesville sandstone across Osage County ranges in depth from 1,000' to 3,000' is known to be naturally fractured2 and typically has permeability values less than 50 millidarcies (md). In an attempt to improve the economics of Bartlesville waterfloods, operators frequently inject water above the fracture-parting pressure to achieve better injectivity. The result is often unfavorable since the water tends to channel through the fractures bypassing much of the remaining oil in the matrix. Development of small patterns with closer well spacing can lead to improved recovery, however, the economics are impacted negatively because of the number of wells required.

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