This paper describes laboratory experiments involving waterflooding atelevated temperatures using two refined oils and two crudes. The test core andinjection water were both held at test temperatures for the duration of theflood, thus eliminating the problem of thermal fronts. The findings reportedhere apply to waterflooding in general and thermal recovery in particular, asmost thermal recovery methods include a phase where "hot" water displaces "hot"oil. Waterflood tests were conducted at 75°F, 100°F, 150° F, 200°F, 300°F, 400°Fand 500°F using two refined oils: No. 5 white oil and No. 15 white oil. Twocrude oils were used in waterflooding at 75°F, 150°F and 300°F. The results show that residual oil saturation decreases with increasing temperature. Consequently, ultimate oil recovery increases with increasingtemperature and the relative permeability ratio is different for differenttemperatures. The magnitude of the temperature effect varies, but in most casesit is appreciable, especially for the crude oils. Crude oil waterfloodbehaviour in the laboratory tests differs significantly from refined oilbehaviour, because in crude oil waterfloods water breakthrough is earlier andsubordinate production is much higher. Consequently, predictions of field hotwaterfloods require displacement data at the actual field flood temperature, using reservoir materials. Introduction There is a great deal of current interest in thermal methods for recoveringcrude oil, especially the heavy viscous crudes. Many forms of thermal recoveryinclude a phase where hot water displaces oil. In such a process, two frontswill form a leading cold-water front and a hot-water front. Oil and waterviscosities decrease and the liquids swell as the temperature increases. These effects may influence fluid flow in a way not described by simple relativepermeability concepts. However, all processes involved in hot waterfloodingoccur slowly, and thermal equilibrium may be considered to prevail at everyspace-time point during the flood. Consequently, the relative flow rates of oiland water are determined by relative permeability ratios and viscosities, despite the complicating thermal effects mentioned above.

The Bay Marchand Pressure Maintenance Project Unique Challenges of an Offshore, Project Unique Challenges of an Offshore, Sea-Water Injection System Extreme formation damage caused by the injection fluid; reservoir sands that broke down under injection; severe corrosion; and mechanical problems all spelled trouble in this large pressure maintenance project. Changes, based on test results, have turned it into a successful sea-water injection system. Introduction In the Bay Marchand Pressure Maintenance Project, one of the largest offshore injection systems in the U.S., sea water is injected at high pressures into deep Miocene sands. The need for pressure maintenance in this field off the coast of Louisiana was first recognized in the early 1960's. Six major reservoirs on the prolific east flank of this large salt-dome field exhibited only limited natural water influx after a period of rapid initial development. The early design of the injection system indicated large basic requirements. Injection volume exceeded 50,000 BWPD and injection pressures were anticipated to be as high as 3,650 psig. The injection wells were 11,000 to 12,000 ft deep. A series of unexpected problems developed soon after pressure maintenance began in 1963. First, reservoir sands, which had been sufficiently competent during the early production life of the field, broke down under injection. production life of the field, broke down under injection. In addition, corrosion and the pronounced pressure-rate effects on down-hole equipment were more pressure-rate effects on down-hole equipment were more severe than had been anticipated. Finally, there was severe formation damage, which later was found to be related directly to the use of sea water as an injection fluid. Description of Reservoirs The six major reservoirs under injection in Bay Marchand represent typical Miocene sand development along the flanks of a piercement-type salt dome (Fig. 1). The reservoirs overlie each other at depths between 8,300 ft subsea and 11,400 ft subsea. They are on the east flank of the structure and have an area ranging from 1,300 to 2,300 acres. Structural dip ranges from 24 degrees near the salt dome to 8 degrees at the original oil-water contact. Average net sand thicknesses range from 6 to 36 ft. Initial reservoir pressures varied from 4,600 to 5,291 psig. All but one reservoir were undersaturated initially. Reservoir temperatures vary from 182 to 197F. While initial GOR's averaged 450 scf/STB, oil gravities were between 21 and 30 degrees API. Since PVT properties varied with depth, small primary gas caps PVT properties varied with depth, small primary gas caps existed and the oil columns were undersaturated at their volumetric midpoints. Oil viscosities ranged from 1.1 to 1.9 cp, indicating favorable mobility ratios. Porosities were uniform and averaged 29 percent. However, permeabilities exhibited wide variations; three reservoirs had geometric-mean air permeabilities of less than 100 md, while the remaining sands had values up to 2,000 md. Initial water saturations exhibited a corresponding variation from 40 to 15 percent. percent. Drilling and Production History Initial development of the project sands began in Sept., 1958, with the completion of S. L. 1424 OCS-0387 S-9. Fig. 1 illustrates placement of the completions in a typical project reservoir. The U, W, X, BB and AA structures are 12-well units. JPT P. 389