Surat Basin, Southern Queensland, Australia
Abstract from Society of Petroleum Engineers, Department of Energy (SPE/DOE), Seventh Symposium on Enhanced Oil Recovery, Tulsa, Oklahoma. Field Studies of Microbial EOR, SPE/DOE 20254; A.J. Sheehy.
A field assessment of the new technology in the Alton field is described. Twelve months after treatment an approximate 40% increase in net oil production continues. The test is unique because of the stringent controls applied during the assessment.
The application of MEOR in these trials has resulted in a substantial and sustained increase in production compared to control operations on the same reservoir. Increased production has been sustained from a single treatment.
“There is an approximate 40% increase in production...the oil flow recommenced after the introduction of the microbial system at a relatively constant rate.”
—Alton Field Study, Society of Petroleum Engineers Abstract SPE/DOE 20254, A.J. Sheehy, Ph.D.
The Alton Field is located 370 km (230 miles) west-southwest of Brisbane in the Surat Basin, Queensland, Australia. The Alton Field produces from Lower Jurassic, Boxvale Sandstone which is part of the Evergreen formation. The trap is structural-stratigraphic; small anticlinal closure with reservoir zones controlled by permeability barriers and edge-water contacts. The reservoir temperature is 76° C (169° F). Production commences in January 1966 and at present the field is producing on beam pump from five wells.
The individual sands in Alton tend to be thin with a permeability of 11 to 884 md (average 260 md) and porosity of 15.4 to 19.8% (average 17.2%). The permeability and porosity decrease from east to west. The hydrocarbon areal extent is 1840 acres. The original oil in place has been estimated at between 6.6 million STB and 13.6 million STB. Oil produced is medium light on a paraffin base. Residual oil concentration is about 50%. The pressure and production history indicates the presence of a weak water drive which is supplemented by fluid expansion.
The Alton Reservoir commenced production at a rate of 1000 STB/day. Field production started a slow decline in 1969 and there has been a roughly exponential decline since. In recent years that decline has been measured at approximately 15 percent per annum and the reservoir is close to its economic limit of 15 STB/day.
The low primary recovery and high residual oil saturation make Alton a prime candidate for enhanced oil recovery. After initial evaluation it was considered that a waterflood would be too expensive and the stratified nature of the sands at Alton were considered to militate against its likely success.
A decision to stimulate the well biologically was made on the basis that microbial biotechnology was likely to achieve increased production via the simultaneous application of (i) profile improvement of aquifer sweeping (ii) increased pressurization and (iii) surfactant, at a cost consistent with the economic potential of the reservoir. The stimulation was conducted by injection into the producing well.
The aims of the field trial were to determine and document the effectiveness of the new biological process, and to assess the validity of laboratory studies and models. A series of controls was included in the field trial to make the assessment of the process scientifically valid (Graph 1). The controls included:
(A) a trial shut-in period to log post shut-in production and document the natural baseline.
(B) injection of production water, followed by well shut-in, to log hydrodynamic changes in the well caused by the work over programme and document an injection baseline.
All evaluations of the effectiveness of the Microbial EOR system are determined against these controls.
Work Over Programme
A standard work over programme was conducted on Alton #3 to set a packet to ensure that the microbial mixture entered the formation. Plug Back Total Depth was 6109 ft RKB.
Fluid injection of 0.5 bbl/min. at 2200 PSIG was maintained during pumping. A total of 86 bbls of microbial solution was injected. All fluid injected into the formation was filtered through 28 and 10 micron filters. 35 bbls of produced water was used to displace the microbial solution. The total cost of the microbial injection was $A3850. The work over programme was completed on Thursday 26 January (Australia Day) and the well put back on production Thursday 16 February 1989.
The graph shows oil production on a daily basis for the microbial system (Test) referenced against the injection baseline (Control). There is an approximate 40% increase in production. It should be noted that the oil flow recommenced after the introduction of the microbial system at a relatively constant rate where the flow of the control was quite erratic. Oil production figures combined with geochemical data (not presented) clearly shows that oil previously trapped has been released from the formation.
The level of base sediment and water (BS&W or water cut) was reduced after the microbial process was applied to the well. Clearly, the water cut has decreased and the percentage of oil contained in the total fluid produced has risen.
Other significant findings were:
(i) An increase in annulus pressure shown both chemically and by gas analysis to be predominantly the result of biological activity. The major components in the increased gas pressure have been contributed by carbon dioxide and methane production.
(ii) Chemical analysis of the production water before the programme began, after nutrient medium injection and after the introduction of the microbial system shows that the production water after the microbial injection contains levels of Na+, HCO3– and C1– greater than those in the initial production water and support medium. Peak levels of these ions were associated with maximum oil production. This is consistent with the release of connate water and associated oil as a result of an improved sweep efficiency.
(iii) Microbial numbers increased from less than 1,000/ml in the pre-injection production water to greater than 100,000/ml after the microbial injection. Sulphate reducing bacteria were not stimulated and H2S was not detected.
(iv) No changes occurred in the composition or physical characteristics of the oil.
(v) The interfacial tension of the production water/oil interface was significantly decreased (10-25%) compared with that prevailing before the microbial injection.
(vi) The field trial results and laboratory core flood experiments have similar production patterns.
This field trial has shown not only the feasibility of stimulating oil production biologically but the capability of this process to operate at temperatures above those traditionally associated with biological processes. It is clear from the field trial that a biological system can be introduced and dispersed over a significant portion of a reservoir even when only a small volume is introduced into a producing well.
The process used in this field trial is based on an ecological solution to the problems which have plagued oil production. The process relies on inducing desirable metabolic activity in a biological system rather than attempting to inject microorganisms which already produce desirable metabolites. Thus, the patented process has the unique property of flexibility e.g. it has been shown to be equally effective at 40°C and 76°C over a variety of ionic strengths and brine and oil compositions. It has the added advantage that the stimulation can achieve increased production over a period of time.