MICROBIAL OPTIONS FOR INCREASING OIL RECOVERY

Based on workshops sponsored by PTTC's Eastern Gulf Region, Nov. 4, 1998 in Jackson, MS; Texas Region, June 3, 1999 in Midland, TX; and Appalachian Region, June 21, 1999 in Zanesville, OH

BOTTOM LINE

Microbial technologies are a lower-cost option for operators to consider as they address well productivity, injectivity/ disposal, or improved oil recovery in mature oil leases. When properly tailored to the problem, microbial solutions can be a profitable option.

PROBLEM ADDRESSED

Operators of mature oil leases need low cost, affordable solutions to improve oil productivity in often marginally economic properties. There, operators typically encounter problems of well damage with associated low productivity, water treating with injectivity/ disposal problems, or poor waterflood recovery due to either poor sweep efficiency and/ or displacement efficiency. Microbial processes can be used for well stimulation/ wellbore cleanup in producing wells and in water injection/ disposal systems. Microbes can also improve displacement and sweep efficiency in waterfloods, at costs among the lowest for improved oil recovery processes.

KEY WORDS:

Improved oil recovery, Microbial, Microbial permeability profile modification, Well cleanup, Well stimulation

SPEAKERS

Lewis Brown, Mississippi State University

Rebecca Bryant, Bio-Engineering International

Cliff Mark, Micro-Bac International Inc.

James Stephens, Hughes Eastern Corporation

Alex Vadie, Mississippi State University

Larry Zickefoose, Petroleum Production Services, LLC

TECHNOLOGY OVERVIEW

Several factors make microorganisms attractive for improved oil recovery. They are self-replicating and relatively inexpensive to produce. The nutrients required to sustain their growth are economically priced. Microorganisms produce many of the chemicals, such as gases, surfactants, acids, solvents, and polymers/ biomass involved in improving oil recovery. At its simplest, to be successful, microbes must be able to live in the reservoir environment. General screening criteria (for which there are known exceptions) are: (1) salinity less than 15% NaCl; (2) temperature less than 180 o F; (3) depth less than 8,000 ft; (4) trace elements (As, Se, Ni, Hg) less than 10-15 ppm; (5) permeability greater than 50 md; (6) oil gravity greater than 15 o API; and (7) residual oil saturation greater than 25%.

Microbial options fall into three basic categories-well stimulation, wellbore cleanup, and improved waterflooding. Wellbore cleanup treatments can mitigate paraffin and/ or scale problems, typically at lower cost than chemical treatments. Microbes can also be used to clean up water injection or disposal systems. Conventional microbial waterflooding involves injecting microbes in the reservoir, then stimulating their growth by injection of nutrients.

Alternatively, growth of in situ microbes can be stimulated as with the microbial permeability profile modification (MPPM) process developed at Mississippi State University. In the MPPM process, fluid diversion with improved sweep efficiency is primarily responsible for improved recovery. Laboratory screening of deposits and well fluids is important for tailored microbial solutions to be effective. Application of microbial technologies are best illustrated through reference to field examples, many of which were shared in the three PTTC workshops.

Paraffin Control in West Virginia.
Petroleum Production Services, employed microbial products developed by Micro-Bac International to treat three wells in West Virginia, all of which were experiencing paraffin problems. They included an Injun well at 2100 ft, a Weir sand well at 2400 ft, and a Devonian shale well at 5700 ft. Two of the three wells had been previously treated with solvents with varying cost effectiveness. Surface equipment for the Injun well is now reported free of paraffin. Both oil and gas production in the Weir sand well increased about 50%, but the well's marginal productivity (even when cleaned up) leaves doubt whether the microbial treatments will be economical. In the Devonian Shale well, production is up 60% compared to that experienced when solvents were used. There, costs are about equal for the microbial and solvent treatments.

Experience with Microbial Wellbore
Cleanup/ Stimulation.
Within the U. S. Department of Energy's (DOE) Technology Development with Independents program, there were three projects by independents that fieldtested microbial wellbore cleanup/ stimulation treatments. In Kansas, Edmiston Oil Co. injected microbial oil components into a low gravity McLouth Sand oil reservoir to remove scale, paraffin, and/ or asphaltenes. Twenty-four wells on eight leases were treated periodically with matrix squeeze treatments. Oil production increased from 4 BOPD to 20 BOPD within one year, but admittedly part of the increase could be from increased injection. Improved oil flowability reduced operating costs.

In West Virginia, Rock Island Service Company Inc. treated five Salt Sand wells. Because the wells had been shutin since 1984, they had to be re-equipped with pumping units prior to testing— so field test costs were high. Wells were treated with 1 to 2 gal. of microbes, 2.5 to 5 gals. of surfactant, 5 to 10 lbs. of nutrient, and 400 gals. of water. Following treatment, wells were shutin for a week before being returned to production. Production increases were noted, but with the cost to re-equip the wells, which would not be experienced in many applications, and the need for periodic retreatment, this microbial program proved uneconomical.

In Indiana, Speir Operating Co. was experiencing reduced productivity and injectivity due to paraffin and sulfide scale. After initially cleaning the wells with acid, they injected a solution of microbes and nutrients, followed by a warm water flush, into nine producing wells and two injection wells. Wells were treated monthly for six months. Oil production initially increased from 4 to 21 BOPD, but later stabilized at 14 BOPD. Five months after the final treatment, production had declined to 6 BOPD, indicating the treatments need to be repeated at periodic intervals for continued improvement to be realized. Monthly electric bills were reduced by about a third due to lowered injection pressures with the treatments.

MPPM Process at Hughes Eastern's North Blowhorn Creek Unit.
Production in the North Blowhorn Creek Unit (NBCU), Lamar County, Alabama, is from the Mississippian-age Carter Sandstone at a depth of about 2300 ft. Discovered in 1979, the field was initially developed on 80-acre spacing. Waterflooding began in 1983. Production peaked at about 3000 BOPD in 1985, declining steadily to about 290 BOPD in April 1994, at the start of the project. Cumulative oil recovery at that time was about 5.3 million barrels, or 33% of the 16 million barrels original oil-in-place. Analysis indicated that ultimate recovery with conventional waterflooding would still leave 10 million bbl. in the reservoir at abandonment, which was projected to occur early in 2003, using $15 per bbl. oil prices.

The MPPM process involves adding nitrogen-and phosphorus-containing microbial nutrients to the injection water of a conventional waterflooding operation. The nutrients stimulate growth of in situ microbes, not injected microbes, diverting water flow from more porous zones to unswept zones. It is a reservoir process, not just treatment of individual wells. Since the nutrients are commonly used plant fertilizers and only microbes already present in the reservoir are involved, it is a very environmentally-friendly process. Compared to other improved oil recovery processes, it is a relatively low cost method.

Four injectors (patterns) were selected to receive microbial nutrients and four other injectors (patterns) were selected as control injectors. With this plan, production data from producing wells surrounding test injectors could be compared both with similar wells not influenced by nutrient injection and with their own historical data. Two wells were drilled in late spring 1994 and core obtained from one for flood testing. Based on core flood experiments, Hughes made the decision to inject potassium nitrate (KNO3) and sodium dihydrogen phosphate (NaH2PO4) in two injectors, and KNO3, NaH2PO4 plus molasses in the remaining two injectors. Using a design injection rate of 500BWPD, injection skids with the capibility to mix and pump 100-300 gals. of water containing 50-400 lbs. of chemicals per day at a pressure of 1200 psi were placed at individual injectors. Dry mixing was an important aspect of skid design.

Microorganisms were shown to be present in cores from three wells drilled in the fall of 1996. There were considerably more microorganisms than observed in the 1994 (pre-nutrient) core. Fluid from all three cores also contained nitrate and phosphate ions, demonstrating that the nutrients were being widely distributed. Yet another indicator of microbial growth was a noticeable reduction in sulfide content in produced fluids that began about six months after nutrient injection started. Nitrates are known to inhibit sulfate-reducing bacteria activity. The produced fluids themselves never exhibited significant change in microbial populations, but that is not surprising knowing that microbes prefer to grow attached to a substrata rather than suspended in a medium.

Well 2-13 No. 1 showed production response with a concurrent reduction in the rate of increase in the water-oil ratio within seven months. By the end of 1996, about two years after nutrient injection began, eight of the 15 production wells in the test patterns showed a positive response. In contrast, two of the production wells in the control (non-nutrient) patterns had been abandoned due to uneconomical production, and five other wells continued their natural decline. One well in the control patterns had experienced increased production, attributed to increased injection support, not microbes. Thirty months after the first nutrient injection, there were still no changes in production in the control patterns, while three more wells in the test patterns had shown evidence of response.

Based on this overall positive indication, Hughes Eastern expanded the nutrient injection program, making 10 injectors total. One year after this expansion, 13 of 19 producers had responded positively, and two were considered possibly responding. Of the 13 responding wells, nine were confirmed as producing "new or bypassed" oil. The new oil determination was based on gas chromatograph analysis of produced oil that indicated higher concentrations of lighter fractions as would be expected in bypassed oil. Higher gas production in some wells also pointed toward oil recovery from previously unswept areas.

Overall production performance in NBCU reveals the flattening of decline in the original wells and the contribution from the new wells. With low oil prices during 1998-1999, Hughes Eastern stopped nutrient injection. Although holding flat for a period of time, some dropoff in production occurred. Injection was re-started in November 1999. Expectations are that production will once again increase. Considering only nutrient costs and incremental costs (beyond what would normally be incurred) for operating, engineering, field equipment, and field labor, the ultimate project cost is estimated at $658,000. This translates to $1.32 per barrel of incremental oil from the MPPM process— certainly one of the lowest for improved oil recovery operations.

ADDITIONAL RESOURCES:

“Program Supports New Technologies,”
J. P. Brashear, A. B. Becker, and D. D. Faulder,
American Oil and Gas Reporter, February 2000, p. 109-117.

"Slowing Production Decline and Extending the Economic Life of an Oil Field: New MEOR Technology,"
L. R. Brown, A. A. Vadie, and J. O. Stephens;
SPE 59306, presented at SPE/ DOE Twelfth Improved Oil Recovery Symposium, April 3-5, 2000, Tulsa, Oklahoma.

CONNECTIONS:

James Stephens
Hughes Eastern Corporation
403 Towne Center Blvd, Suite 103, Ridgeland, MS 39157
Phone 601-898-0051, Fax: 601-898-0233

Lewis Brown
Mississippi State University
PO Drawer GY, Mississippi State, MS 39762
Phone 662-325-7593, Fax 662-325-7939, E-mail lrbsr@ra.msstate.edu

Alex Vadie
Mississippi State University
PO Box 5423, Mississippi State, MS 39762
Phone 662-325-7224, Fax 662-325-0656, E-mail vadie@ra.msstate.edu

Rebecca Bryant
Bio-Engineering International Inc.
925 S. Mason Road, Suite 252,
Katy, TX 77450
Phone 918-335-3371, Fax 918-335-3371, E-mail bryant5@ionet.net

Cliff Mark
Micro-Bac International Inc.
3200 N. IH 35,
Round Rock, TX 78681-2410
Phone 512-310-9000, Fax 512-310-8800, E-mail cliffm@prismnet.com

For information on PTTC’s regional activities contact:

Appalachian
Douglas G. Patchen, Program Director Appalachian Oil & Natural Gas Research Consortium,
West Virginia University,
NRCCE -P. O. Box 6064, Evansdale Drive, Morgantown, WV 26506-6064
Phone 304-293-2867 x 5443, Fax 304-293-7822, E-mail dpatch@wvunrcce.nrcce.wvu.edu

Eastern Gulf
Ernest A. Mancini, Professor of Geology University of Alabama
Box 870338, 202 Bevill Bldg., Tuscaloosa, AL 35487 Phone 205-348-4319, Fax 205-348-0818, E-mail emancini@wgs.geo.ua.edu

Texas
Scott Tinker, Bureau of Economic Geology, University of Texas at Austin,
University Station, Box X, Austin, TX 78713-2924
Phone 512-471-0209, Fax 512-471-0140, E-mail Scott.Tinker@beg.utexas.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org