Validation of Incremental Oil Production via Single Well and Reservoir

ABSTRACT

The Department of Energy continues to support stripper well producers by funding projects that involve technologies, methods, and materials capable of producing additional oil through economical, easy to use, and environmentally responsible means. This project involved 19 stripper wells from 3 independent producers; 14 are single wells and 5 wells are divided among 3 small permitted waterfloods. The primary project objective was to validate incremental oil production by analysis and comparison of historical production data with post-treatment production data. Historical production data, well profiles, and post-treatment data were provided by the project's cooperating oil producers.

Single wells were treated with varying amounts of specially prepared proprietary nutrient medium (MEOR fluid) using several application methodologies. One well was used as a control. All project wells are cased completions and all were treated by injecting a pre-flush of fluid followed by low-volume slugs of MEOR fluid, and a post-flush of fluids through the annulus. Off-road diesel was typically injected as the pre-flush ahead of the MEOR fluid, and production fluids (crude oil or lease water) were used to provide a post-treatment flush or a post-treatment fluid squeeze. Following injection, well bore fluids in some project wells were circulated for a period of time and then allowed to soak with the well shut in. In other instances, the amount of post-flush was deemed sufficient to create a static head and these wells were shut in with no circulation. Regardless of whether or not the well bore fluids were circulated, all treated production wells were shut in for one to three days before turning them back into production. Enhanced waterflooding was accomplished using larger slugs of the MEOR fluid which was injected at measured volumes through the existing injection systems. Both single well and enhanced waterflood treatments were intended to stimulate the metabolic activity of indigenous microbial populations and thereby increase oil production. The treatment methodology was designed to be easy to implement as well as cost-effective depending on the volume of additional oil produced.

A necessary prerequisite for initiating validation field trials and major project objective was production of the MEOR treatment fluid. This was accomplished during the first three quarters by re-creating the manufacturing process as set forth in company archival records circa 1987-1992. Raw feedstock consisting of non-hazardous brewing and bottling industry waste were converted into MEOR treatment fluid in multiple step batch operations by a process that can best be characterized as applied industrial microbiology. This manufacturing process proved to be flexible and, with minor adaptations, capable of utilizing and converting readily available raw feed-stocks into a sufficient quantity of MEOR fluid suitable for field validation trials. Another project objective involved a review the microbial enhanced oil recovery literature to assess and expand the applicability of the candidate selection criteria for identifying single wells that can be capably treated with the project's MEOR fluid.

Two of the project's three primary objectives were achieved: 1) a specially prepared MEOR treatment fluid was successfully manufactured from locally available non-hazardous brewing and beverage industry wastes and delivered to the project's cooperating oil producers validation field trials, and 2) a modified screening matrix was created inclusive of previous field trials and used to screen candidate wells and waterfloods. However the project's main objective, validation of incremental oil production, remains inconclusive as of the date of this report. Preliminary results are positive, but there is insufficient verifiable post-treatment production data for conclusive validation. Consequently, field work was continued past the end of the project period in an effort to obtain additional post-treatment data for this final report. The project's overarching long-term goal is the development of a practical, easy to use, and cost-effective Microbial EOR technology capable of producing substantial volumes of stranded oil from stripper wells and enhanced waterfloods with minimal environmental impact.

EXECUTIVE SUMMARY

This project sought to validate incremental oil production from 19 stripper wells and 3 small waterfloods through comparison of pre-treatment historical production data to post-treatment data. The project's overarching long-term goal being the development of a practical, easy to use, and cost effective microbial EOR technology capable of producing substantial volumes of stranded oil from stripper wells and enhanced waterfloods with minimal environmental impact.

Prior MEOR research has determined that microorganisms exist in virtually all oil-bearing formations with the preponderance of metabolic activity believed to take place at the oil-water-rock interface. Further, the nutrient requirements of carbon utilizing and hydrocarbon degrading micro-biota as well as growth limiting factors such as nitrogen and phosphorus are well established. ^{[1] [2] [3]} In order to meet the goals of practicality, ease of use, and cost-effectiveness for stripper well producers, this project assumed that beneficial microbial populations are present in the critical production matrix of all producing wells. Consequently, candidate well production waters were analyzed and evaluated for compatibility with the MEOR fluid and tested for sulfate reducing bacteria (SRB's) that disqualify a candidate well, but they were not cultured to identify indigenous microbial populations. Rather, a shotgun approach with variations in field application methods was utilized. By taking this approach the well's response to treatments; i.e., the volume of additional oil produced vs. treatment cost is the determining factor for continuation or suspension of treatments.

A necessary prerequisite for initiating field trials was production of the project's proprietary nutrient medium (MEOR treatment fluid). This was successfully accomplished by re-creating the manufacturing process as set forth in company archival records and is discussed in the Q1, Q2, and Q3 reports. A consignment of 2,750 gallons of MEOR fluid was shipped to the project's cooperating oil producers in 250-gallon totes on 30 June, 2009. Pilot plant cost figures were developed and bulk shipping costs and approximate application costs were determined. These costs factors were used to establish the per barrel cost for each additional barrel of oil produced by this MEOR technology.

MEOR treatment fluid was manufactured by a process that can best be characterized as applied industrial microbiology implemented in multiple step batch and semi-batch modes. Raw feed-stocks consisting of non-hazardous liquid brewing and beverage industry wastes were accepted 'as is' and adjusted for pH and chemical composition before initiating the conversion process. The ability to adjust raw feed-stocks is significant. It affords process flexibility and greatly increases the volume of wastes that can be utilized. As a consequence, the process proved to be very flexible and, with minor adaptations, capable of utilizing and converting a diverse mixture of raw feed-stocks into a suitable MEOR treatment fluid. The conversion process is designed and staged to produce growth limiting nutrients in bio-available form and minimize sequestration of the nutrient load before delivery. Therefore, the MEOR fluid / nutrient medium operates in a manner of a nutrient delivery system that is intended to increase microbial metabolic activity at the oil-water-rock interface with the resultant in situ production of bio-chemicals and gases beneficial to oil recovery.

The nutrient medium when fully processed was found to have inherent chelating, reducing, acidizing, and surfactant properties similar in some respects to traditional oil field chemicals. These properties suggest a potential application for near well bore clean-up to address plugging by scale and bio-film. In carbonate reservoirs the acidizing characteristics may prove beneficial for increasing permeability. A possible use of the treatment fluid in formation fracturing is also suggested. These possibilities are discussed in more detail in the Q5-6 interim report. Further laboratory research and field work is needed to determine the validity and commercial viability of these potential applications.

Prior field trials conducted by RAM Biochemicals between 1988-1992 used treatment slugs of 15 to 25 gallons for cyclic treatment of single wells ranging from 1,500 to 3,500 feet.^[4] The project wells are located in central and south-central Kansas and range in depth from 3,500 to 6,500 feet for Schlobohm Oil and American Warrior respectively. AX&P wells located in southeastern Kansas average about 950 feet. This project involved a cross-section of oil fields in Kansas: Neodesha, Karst, Bemis-Shutts, Boxberger West, Gorham, Galatia South, Shuck Northwest, and Larrabee North. Multiple oil bearing formations were treated: the Lansing-Kansas City, Arbuckle, Mississippian, and Bartlesville Sand being the most prominent. A control treatment was conducted to determine if the treatment methodology alone without MEOR fluid has a positive influence on oil production.

Single well treatments were made with 15 to 50 gallons of MEOR fluid depending on well depth and application methodology. Microbial enhanced waterfloods received calculated slugs ranging 100 to 250 gallons. Single wells treatments were made by either fluid squeeze or soak methods. A fluid squeeze treatment consisted of a pre-treatment injection of off-road diesel followed by a low volume slug of MEOR fluid followed by a squeeze with produced oil or lease water to overcome static fluid pressures and force treatment fluid into the critical production matrix. Wells were shut in for two to three days following treatment to allow residence time for microbial activity. Soak treatments employed a similar methodology, but used a much lower volume of flush. The wells were then shut in and well bore fluids circulated for 1-2 hours and then allowed to soak for two to three days shut in. All project wells are cased completions and treatment fluids were injected through the annulus. Single well treatments were intended to stimulate microbial activity of indigenous microbes in the near well bore and critical production matrix. Enhanced waterfloods received larger volume slugs of MEOR fluid (100 to 250 gallons) with no shut in time provided for the adjacent producing wells. The two Schlobohm Oil waterflood leases permitted for EOR were treated by injecting 250 gallons through the existing injection system over a three day period. For AX&P's Fee lease, 100 gallons was mixed with produced lease water in a 90 bbl holding tank to make an approximate 4% solution which was then injected over a 24 hour period. These treatments were intended to stimulate microbial activity deeper within the formation at the oil-water-rock interface.

Several of the project's primary objectives were accomplished: 1) MEOR treatment fluid was produced and shipped to cooperating oil producers in sufficient quantity to satisfy the project's recommended application rates and schedules; 2) candidate wells and waterfloods were selected using a modified screening matrix developed inclusive of previous field trials; 3) historical pre-treatment data and the available post-treatment production data has been received and analyzed; 4) preliminary post-treatment results evidence positive responses in some wells. As of this final report date only 8 out of 14 single well have received three MEOR treatments at the recommended intervals, and all three waterfloods have been treated.

Presently there is insufficient post-treatment production data available to verify that preliminary positive results rise above measurement error. Consequently, the project's primary objective to validate incremental oil production is inconclusive.

MANUFACTURING / PROCESSING - [This section has been redacted.]

Experimental methods for R&D and manufacturing methods are trade secrets and not germane to the reporting requirement of this topical report.

Research & Development

Manufacturing Methods

Manufacturing Equipment

2,500 gallon polypropylene tanks, submersible pumps, fluid transfer pumps, cartridge filters, bag filter, two and four inch OD PVC rigid piping, two inch ID flexible clear PVC tubing with polymer quick-connects, microbiology laboratory glassware, microscope, incubation chamber, chemicals for pH adjustments, miscellaneous PVC valves, fittings, clamps, and hoses.

Raw Feed-stock R&D

Processing

Pilot Plant Operations

Results and Discussion

Ultimately, the MEOR fluid must be easy to use and inexpensive enough to allow it to be tried for efficacy; if there are no positive results, then go on to the next well, and treat it. There is little to gain from doing expensive testing or much engineering especially for stripper and marginal wells. Wells that don't have an indigenous population of microbes due to excessive salinities, pH's, or toxicity of the well treating regimes will be the ones least likely to show an effect. Wells that show some effect, should be susceptible to dose relationships; doubling the effect in a stratum may need the square or quadruple the amount of MEOR fluid. Since the indigenous population dynamics may be adversely affected by increased nutrient levels, dosing wells may show a peak with subsequent drop off or a threshold effect. For wells that don't show any effect, but otherwise fit the treatment matrix for MEOR, inoculation by beneficial organisms is suggested. Investigation of this alternative MEOR methodology is extensive ^{[8] [9] [10]}, and lies outside of the scope of this project. The company does anticipate structuring future field projects with microbial enhanced waterflooding in mind.

The results of treatments with the project's MEOR fluid have not been sufficient to rise above noise (measurement errors), yet none of the treatments showed any loss of production so the proposal that re-treatments be a go, no-go decisions based on production results is supported. The ease of processing finished MEOR fluid using basic equipment was an expected result from our experience in the 1990's; however, we were also pleased to find that the ability to extend the range of feedstocks that are usable for processing, allows the production to be sustainable and transferable to other locations. It also suggests that production costs can be lowered and give better ROI for shotgun treating all applicable wells for go, no-go decisions for continuing treatments.

FIELD TRIALS

Introduction

This microbial enhanced oil recovery (MEOR) project was conducted to validate the production of additional oil in stripper wells by stimulating native microbial populations present in the critical production matrix and surrounding oil-bearing strata. A cross-section of Kansas stripper wells and three small waterfloods were selected as candidates using an MEOR treatment selection matrix. Although the wells operated by AX&P, Inc. were not good candidates for this MEOR technology due to high salinities and shallow plays, they were included in the project to help assess the validity of the candidate selection matrix. Single wells were treated by several easy to use treatment methodologies generally referred to as 'huff-and-puff'. Enhanced waterfloods were treated by injecting MEOR treatment fluid through the existing injection systems.

Treatment Methodologies

Treatment volumes, application methods, and schedules were discussed with the cooperating oil producers during two field trips to Kansas, one in early July 2009 and another in September 2009. The recommended regimen for each project well and enhanced waterflood was also posted to the company website and periodically updated to reflect treatment dates and schedule modifications.

Single well treatments were made with 15 to 50 gallons of MEOR fluid depending on well depth and application methodology. Microbial enhanced waterfloods received calculated slugs ranging 100 to 250 gallons. Single wells treatments were made by either fluid squeeze or soak methods. A fluid squeeze treatment consisted of a pre-flush injection of off-road diesel followed by a low volume slug of MEOR fluid followed by a calculated amount of produced oil or lease water. This final flush was used to overcome static fluid pressures and force treatment fluid into the critical production matrix. The well was then shut in for two to three days allowing residence time for microbial activity. Soak treatments employed a similar methodology, but used a much lower volume of flush followed by a brief period of shut-in circulation before being allowed to soak for two to three days while shut in. All single project wells are cased completions and treatment fluids were injected through the annulus. Single well treatments were intended to stimulate microbial activity of indigenous microbes in the near well bore and critical production matrix. Enhanced waterfloods received larger volume slugs of MEOR fluid (100 to 250 gallons) with no shut in time provided for the adjacent producing wells. The two Schlobohm Oil waterflood leases permitted for EOR were treated by injecting 250 gallons through the existing injection system over a three day period. For AX&P's Fee lease, 100 gallons was mixed with produced lease water in a 90 bbl holding tank to make an approximate 4% solution which was then injected over a 24 hour period. These treatments were intended to stimulate microbial activity deeper within the formation at the oil-water-rock interface.

DATA COLLECTION AND ANALYSIS

Historical and Post-treatment Production Data

Daily gauge reports and pumper notes were used to establish pre-treatment and post-treatment production averages. Single well low producing leases counted zero gauge inch days as production days unless the well was noted as down. Down days were excluded from the arithmetic mean calculations. Multiple well leases pumping into a common tank battery were assumed to be pumping all wells on those days showing gauge inches of production. A simple statistical analysis using standard deviation calculation excluded production days showing one or more standard deviation above or below or the mean. This was done to smooth out the data for days when one or more wells were not pumped or the lease was having mechanical problems. Cold weather, mechanical problems, routine maintenance, and workovers are external factors that can skew production data. These factors are expected to be systematic errors that would skew data by one or more sigma and would be accounted for by the analysis. The PI requested that no chemical or acid treatments be made during the course of the project.

Data Analysis Methodology

Margins of measurement error were estimated based on the raw tank gauge (inches) for the error in volume X. A range of error was also estimated for the time that any two measurements may be made and recorded as one time period in days (t). At each tank sale, or recorded down time, the measurement (±) errors can be described as X(±)dX and t(±)dt. Time ranges that include multiple down times and tank sales propagate the errors additively, so production rates for any time range can be calculated with the errors due to measurement ascribed.

Typically, tank measurement errors of (±)½ inch on any particular day reading have to be tempered with time error as to whether the tank is read in the morning or evening, of (±) 5 hrs of a 24 hr day. A typical time range will have X”(±)1” and t(±)10/24 days for a single event such as a down time or tank sale. A time range that includes n single events will be expected to have a propagated error of n times, and is ascribed X”(±)1n” and t(±)10n/24 days. There is room to reduce errors if the pumpers notes can be refined and reconciled with copies of sales tickets having recorded volumes and times since these can be more exact. For much of the project we are confined to using historical pumpers daily gauge sheets or some equivalent data.

Since down times (and ranges of data eliminated for other reasons) propagate error, we have to be judicious in using any simple statistical method to eliminate ranges of data. One analytical method was used for low production wells and leases. It does not involve standard deviation calculations and instead involves cumulative production. Ultimately, to the producer incremental oil increases will be reflected in increased sales tickets. Unless noted as down days, days showing zero gauge inches of production were counted as production days and included in calculation of the daily production rate (arithmetic mean) for a given date range.

There are two reasons for taking this approach: 1) production is typically shown in whole inches and a zero production day does not mean the well or lease was not pumped. It might take two or more days for oil production to register one gauge inch. Consequently, days showing zero gauge inches of production are true production days and were included in the total number of production days for a given date range; 2) Low producing wells typically show from 0 to 3 gauge inches. Measurement errors will give rise to a noisy line that can only be smoothed by taking cumulative measurements over larger time intervals.

Application of standard deviation analysis and the exclusion of production days that are one or more deviations from the mean would force exclusion of too many valid gauge readings. Calculations are made as follows: 1) gauge inches for production days in a given date range are totaled; errors in the gauge inches and production days are ascribed. 2) total gauge inches are divided by the number of production days to yield an arithmetic mean; the corresponding rate errors are calculated and ascribed. 3) the mean value of gauge inches and the errors are multiplied by the barrels per inch for a given stock tank to yield the average BOPD production with error.

A statistical method was used in an attempt to remove suspect data from higher producing single well leases and multiple-well leases pumping into a common tank battery on days when one or more wells were down or faltering. These readings show up when produced oil is pushed over from the gun barrel into the stock tanks, and on days when one or more wells may not have been pumping. Statistical calculations are made as follows: 1) daily gauge inches are recorded for a given date range excluding zero gauge inch days noted as down days; 2) an arithmetic mean is calculated for the given date range; 3) variance and standard deviations are calculated; 5) gauge inches are then reviewed and days showing more than one standard deviation above or below the mean are not counted as production days counted; 6) production day ranges for measurements of gauge inches (and errors) are totaled and divided by the number of production days in the given date range (and errors) to arrive at average inches per day; 7) average inches are then multiplied by the barrels per inch for the given stock tanks to yield the average BOPD production with the associated measurement error.

FIELD PROJECTS BY OPERATOR

PROJECT OVERVIEW - Schlobohm Oil Operations

Summary of Results

Lease Name	Pre-MEOR BOPD	Post-MEOR BOPD
Crissman 'A'	9.09 ±0.28	10.24 ±0.34
Schruben	2.44 ±0.06	3.33 ±0.09
Dumler	1.24 ±0.07	1.18 ±0.10
Art Karst	1.31 ±0.03	1.31 ±0.04
*Boxberger	1.78 ±0.03	1.43 ±0.10
Bemis-Shutts (Waterflood)	0.44 ±0.03	0.47 ±0.05
Morgenstern (Waterflood)	6.13 ±0.18	6.51 ±0.06

Table 1

* Control – Well treated by same treatment method without MEOR Fluid

This microbial enhanced oil recovery (MEOR) project was conducted to validate the production of additional oil in stripper wells by stimulating native microbial populations assumed to be present in the critical production matrix and surrounding oil-bearing strata. Schlobohm Oil’s part of the project consisted of 11 stripper wells, one 3-well lease and four 1-well leases plus two permitted waterflood, each with one injection well and two production wells. The treatment regimen for single wells called for three MEOR treatments at regular 30 to 45 day intervals. Enhanced waterflooding treatments were made by injecting larger slugs of MEOR fluid through the existing injection system followed by post-treatment monitoring of total fluid production for 60 to 90 days. Single well re-treatment volumes, rates, and schedules were based upon the initial treatment results. Routine mechanical maintenance activities continued throughout the project, but no chemical or acid treatments were done after the project was restarted on 4/15/2010. Hot oil treatments for paraffin build-up were not needed since the project wells do not exhibit significant paraffin problems.

Implementation

The project was initially started on 9/16/2009 by fluid squeeze treatment of all three Crissman 'A' Lease wells. Well bore fluids were pumped off before injecting the treatment fluids through the annulus. Two wells were treated by injecting 20 gallons of off-road diesel, a 50-gallon slug of MEOR fluid, followed by 10 BBLS of produced oil, and a 2-day shut-in. The third well was treated with 20 gallons of diesel, a 15-gallon slug of MEOR fluid, 5 BBLS of lease water, and 2-day shut-in. No other Schlobohm wells were treated in 2009. On 12/28/2009 the pump on the No. 2 well was changed out due to mechanical problems. On 1/11/2010 the No. 1 well was worked over and then acidized on 1/14/2010. The No. 4 well was worked over and acidized on 1/15/2010.

Schlobohm Oil restarted their MEOR project in on 4/14/2010 with treatment services provided by Evans Tank Service, Russell, Kansas. Between 4/14/2010 and 7/08/2010 all single wells, with the exception of the Boxberger control well, were treated three times with MEOR fluid. The two enhanced waterfloods were treated once. The Boxberger well was used for project control to help determine the effect of the treatment methodology alone without MEOR. Its initial treatment used with the same methodology, but lease water was substituted for MEOR treatment fluid. Daily production reports noted all maintenance activities, pump changes, down days, and days when the production was pumped into the gun barrel. No chemical treatments or acidizing work was done after the project was restarted. Daily gauge reports from 1/01/2008 through 7/31/2010 were available for review and analysis.

Individual Lease Details

Crissman 'A' Lease

The Crissman 'A' is a 3-well lease in the Gorham Field, Russell County, Kansas. All three wells in this lease produce from the Lansing-Kansas City and Gorham groups and pump into a common tank battery with two stock tanks. Production shows a gradual downward trend from 2008 through 2009. The 348 production days in 2008 show an average of 6.61 gauge inches or 11.04 BOPD. The 338 production days in 2009 show an average of 5.74 gauge inches or 9.59 BOPD. The lower production levels are due in part to pump problems on the No. 2 well.

In late December mechanical problems on the #2 well required a pump change which was completed on 12/28/2009. At that time the producer also made a decision to acid treat two wells on the lease. On 1/11/2010 the #1 well’s rods and pump were pulled, steamed and tested. The No. 1 well acidized on 1/14/2010. On 1/15/2010 the No. 4 well's rods and pump were pulled and worked over and the well was acidized. Pump replacement, workovers, and acid treatments on the Crissman ‘A’ lease call its post-MEOR treatment results into question. Although these results are reported, more weight is given to the post-MEOR treatment results after the project was restarted three months later on 4/14/2010. After restart the treatment regimen for all single wells consisted of 25 gallons of off-road diesel, a 50-gallon slug of MEOR fluid followed by another 25 gallons diesel, and a 2 to 3 day shut-in.

It is impossible to determine what percentage of the production shown is due to the initial MEOR treatment vs. the acid treatments, workovers and pump change. Regardless of how much weight is placed on each of these activities, a comparison of the 218 day pre-acidizing average shows 9.09 BOPD vs. 9.91 BOPD for the 85 day post-acidizing average up to 4/14/2010 when project was restarted. For 104 production days after the project was restarted the Crissman ‘A’ lease averaged 10.24 BOPD, a further increase above the acidizing results of 0.33 BOPD. This strongly suggests that MEOR treatments on the Crissman 'A' Lease were at least as effective as the acidizing treatments. No maintenance activities and one down day are noted for this 104 day period.

Crissman 'A' Lease

Comparison of Pre-acidizing vs. Post-acidizing vs. MEOR Treatment

Table 2

Schruben Lease

The Schruben is a 1-well lease in the Galatia Field in Barton County, Kansas pumping into a with a single stock tank. The well was initially treated on 4/14/2010, a second MEOR treatment was made on 6/02/2010 and a third on 7/08/2010. Production data from 7/01/2009 to 7/31/2010 was analyzed. Production averaged 2.44 BOPD for 271 pre-treatment production days with 17 down days during this period, and 3.33 BOPD for 99 post-treatment days with 9 down days.

Table 3

Dumler Lease

The Dumler is a 1-well low producing lease in the Galatia North Field, Barton County, Kansas. It produces from the Lansing-Kansas City group and pumps into a single stock tank. The well was treated initially on 4/17/2010, second treatment on 6/02/2010, and third on 7/07/2010. Daily gauging is shown in whole inches. Some days show zero inches of production even though the well was pumped that day. Consequently, statistical analysis was not applied and the cumulative analysis was used which counted zero days as production days unless the well was noted as down on the daily reports.

Table 4

Pre-treatment production from 7/01/2009 to 4/15/2010 averaged 1.24 BOPD. There were 187 production days during this period and 84 down days. Post-treatment production from 4/18/2010 to 7/31/2010 shows 1.18 BOPD for 104 production days with one down day during this period, a slight decrease in production.

Art Karst Lease

The Art Karst is a 1-well low producing lease in the Karst Field, Barton County, Kansas. It produces from the Lansing-Kansas City and Arbuckle groups and pumps into a single stock tank. The well was treated initially on 4/17/2010, a second MEOR treatment was made on 6/02/2010, and a third on 7/08/2010. Daily gauging is shown in whole inches. Even though the Art Karst was pumped daily unless noted otherwise some days show zero gauge inches of production. Consequently, statistical analysis was not applied and the cumulative analysis was used which counted zero days as production days unless the well was noted as down. The 422 pre-treatment production days show an average BOPD of 1.31 with 47 down days. Post-treatment shows unchanged at 1.31 BOPD for 106 production days with no down days noted.

Table 5

Boxberger Lease

The Boxberger is a 1-well low producing lease in the Gorham Field, Russell County, Kansas. It pumps into two 200 BBL stock tanks. This well was used for project control by using the same treatment methodology and substituting lease water for MEOR fluid. The purpose of the control is to differentiate between treatments made with and without MEOR fluid, and determine the effect on production of the treatment methodology alone. The Boxberger received its initial MEOR treatment on 6/02/2010, and second treatment on 7/08/2010.

Table 6

For 275 days before the control treatment Table 7 shows the Boxberger averaged 1.78 BOPD with two down days noted, and 1.43 BOPD for 47 production days after the control treatment until the first MEOR treatment on 6/02/2010. This indicates that the treatment methodology alone is not a likely contributing factor for any increases shown.

Table 7

The post-control interval from 4/14/2010 to the initial MEOR treatment on 6/02/2010 is included in the pre-treatment average of 1.73 BOPD for 323 production days. Post-treatment production has averaged 1.67 BOPD for 60 production days; still below the pre-treatment average, but back up from the post-control average of 1.43 BOPD.

Bemis-Shutts Lease - Enhanced Waterflood

The Bemis-Shutts is a 3-well lease in the Bemis-Shutts Field, Ellis County, Kansas. It has 1 injection well permitted for EOR and 2 stripper wells producing from the Lansing-Kansas City formation. Waterflooding was enhanced on 4/15/2010 by injecting an initial 50-gallon slug of MEOR fluid through the existing injection system (well API 15-051-05183-0004). A second 100-gallon slug was injected on 4/20/2010 and a third on 4/23/2010. Injection rates were monitored and no problems were encountered. Enhanced waterfloods may require 60 to 90 days or more of post-treatment production data before a production trend can be established and a re-treatment regimen recommended.

Table 8

Morgenstern North Lease - Enhanced Waterflood

The Morgenstern North is a 3-well lease in the Boxberger West Field, Russell County, County, Kansas. It has 1 injection well permitted for EOR and 2 stripper wells producing from the Lansing-Kansas City formation. Waterflooding was enhanced on 4/15/2010 by injecting an initial 50-gallon slug of MEOR fluid through the existing injection system (well API 15-167-00561-0001). A second 100-gallon slug was injected on 4/20/2010 and a third on 4/23/2010. Injection rates were monitored and no problems were encountered. Injection rates and pressures will to be monitored for 60 to 90 days and total fluid production gauged.

Table 9

The Morgenstern North Lease averaged 6.13 BOPD for 403 production days from 1/01/2009 to 4/23/2010 with 75 down days over this date range. Following MEOR treatment the well has averaged 6.51 BOPD for 71 production days with 27 down days from 4/24/2010 to 7/31/2010.

FINDINGS – Schlobohm Oil Operations

Post-treatment data from Schlobohm Oil shows sufficient positive results from the Crissman 'A', Schruben, Bemis-Shutts, and Morgenstern North to warrant consideration for continued MEOR treatments. The Boxberger regained production after its control treatment, but it is not yet above the pre-treatment level. However, it should also be considered for further MEOR treatment and evaluation. The Dumler and Art Karst leases may show a positive response to another MEOR approach that injects viable microbes and nutrients, further treatments with this MEOR fluid should be suspended.

Project Economics

Project economics were evaluated for Schlobohm Oil and are reported as a low and high range due to accumulations from the mean ± error. The aggregated oil increase of all leases from 4/15/2010 to 7/31/2010 ranges between 147 BBLS to 256 BBLS (201 BBLS ± 54 BBLS). Validation of the actual incremental oil production will be shown through cumulative sales tickets.

At pilot plant scale the MEOR fluid cost $8.00 per gallon to produce and ship FOB to Russell, Kansas including the cost of the non-returnable totes. Third party treatment services were priced at $50 / hour with a one hour minimum. Treatments took an average of 30 minutes per well and combined they required one thousand gallons of off road diesel at $2.80 per gallon, and one thousand two hundred and fifty gallons of MEOR at $8.00 per gallon for Schlobohm Oil.

The producer received an average Kansas bonus price of $68.25 per barrel for oil sold. Total treatment costs for the project to date are $15,300. Proceeds from oil sales at the low range of error measurement (148 additional barrels) are $10,101, and $17,472 at the high range (256 additional barrels). Given this range in measurement error, Schlobohm Oil's project has realized somewhere between a net loss of $5,199 to a net gain of $2,200. The mean between low and high range is 202 additional barrels for a net loss of $1,514. The longer these production increases hold without additional MEOR treatments, the closer the project comes to producing net positive income.

Conclusion

All Schlobohm wells were judged to be viable candidates by screening with the modified treatability matrix. Yet three of the single wells showed no measurable response to three treatments over a 90 day period outside of the calculated measurement error. This was not surprising as it is indicative of past results using this benchmark MEOR fluid and treatment methodologies. Positive results are not insured even though a screened well may appear to be an ideal candidate for this MEOR technology. For a 'shotgun approach' to be economically viable a success rate of 50% to 60% should be achieved after preliminary screening. Treatment costs must to be kept low and the volume of additional oil produced from wells showing a sufficient positive response to realize a net gain after sales.

Under normal operating circumstances a stripper well producer would have dropped the unresponsive wells from the program after the second treatment. The economics of Schlobohm Oil's MEOR project look better under this real world scenario. After the project was restarted in April 2010, a practical application of the 'shotgun approach' would have dropped the unresponsive wells from the program. This practical approach lowers the total treatment cost to $12,420 and yields a range from a net loss of approximately $2,400 to a net gain of $5,050 through 7/31/2010.

PROJECT OVERVIEW - American Warrior

Five single wells located about 30 miles north-east of Liberal, Kansas are involved in this portion of the project. Four wells lie in the Shuck Northwest oil field and one in the Larrabee North field. Both fields are in Stevens County, Kansas. Eight additional wells meeting the criteria for MEOR treatability were identified for inclusion in the project pending positive results from the initial five wells. Knock-out-pots were fabricated and installed on all five project wells prior to treatment for barrel testing and to facilitate injection of treatment fluids without killing casinghead gas production used to run the pump jacks. The project's Principal Investigator requested one or two barrel tests before treatment and monthly barrel testing and WOR evaluations after treatments started to gather solid base-line production data in support of the weekly gauge reports.

Each well was to have received a minimum of three MEOR treatments at regular 30 to 45 day intervals. A near wellbore clean-up treatment was recommended for all five wells. With the exception of the Marcellus B-1 which specified a 2 day circulation and no soak due to scaling problems, the clean-up regimen consisted of: a) pump off the well bore fluids, b) inject 1 barrel of condensate or 20 gallons of off-road diesel, c) inject 50 gallons of MEOR fluid, d) flush with 1 barrel of lease fluids (condensate or produced brine), e) shut in and circulate well bore fluids for 1-2 hours, f) soak for 24-48 hours and circulate well bore fluids for 1 hour before turning back into production.

Follow-on treatments for well stimulation recommended the following treatment regimen: a) pump off well bore fluids, b) inject 20 gallons of diesel or condensate, c) inject 50 gallons MEOR fluid on first stimulation treatment and 25 to 50 gallons on second stimulation treatment, d) flush with 1 barrel of lease fluids (produced brine or condensate), e) shut the well in for 2-3 days before turning back into production. Unforeseen circumstances prevented barrel testing and OWR evaluations and full implementation of the recommended treatment regimens and schedules.

Historical and Post-treatment Production Data

Weekly gauge and production reports from 1 January 2009 to 30 April 2010 were received. A compiled consolidated spreadsheet showing total weekly and monthly production from 1 January, 2009 through 1 January, 2010 was also received and cross-checked against the weekly reports gauge reports. The cross-check revealed minor discrepancies between the spreadsheet data and weekly reports; mostly in the December 2009 and January 2010 data sets. Major issues were uncovered in the February 2010 through April 2010 weekly reports. These discrepancies have not been rectified as of the date of this report. Consequently, the data analysis and charts presented herein reflect the results of only one MEOR treatment in October 2009 with post-treatment data running through 30 November, 2009.

Summary of Results

Lease Name	Pre-MEOR BOPD	Post-MEOR BOPD
J.S. Burchett 34 week pre vs. 6 week post	1.88 ±	2.28 ±
J.S. Burchett 6 week pre vs. 6 week post	1.78 ±	2.28 ±
Marcellus B1 & B2 32 weeks pre vs. 6 weeks post	4.42 ±	3.41 ±
Marcellus B1 & B2 6 weeks pre vs. 6 week post	3.07 ±	3.41 ±
Marcellus E-1 40 week pre vs. 1 week post	1.67 ±	2.00 ±
H.H. Wulfmeyer 8 weeks pre vs. 4 weeks post	2.95 ±	2.76 ±
H.H. Wulfemeyer 4 weeks pre vs. 4 weeks post	2.66 ±	2.76 ±

Table 10

NOTE 1: Table reflects the results of one (1) MEOR treatment administered on 16 October 2009 with post-production data running through 30 November 2009. The number of production weeks was calculated by dividing the actual number of production days by seven, not counting down days. The Marcellus E-1 shows only 1 week of production, because it only pumped 7 days out of 42 post-treatment days in the date range used for analysis. The H.H. Wulfemeyer shows a decrease in production when comparing 8 weeks pre-treatment to 4 weeks post-treatment, but a slight increase when comparing 4 weeks pre-treatment to 4 week post-treatment.

NOTE 2: There is a large measurement error of ±1.0 BOPD in the post-treatment production shown for each well. The measurement error is large owing to the limited amount of post-treatment data included in the analysis, and will decrease as more post-treatment production days are included.

Individual Lease Details

J. S. Burchett #1

American Warrior's Josephine S. Burchett #1 well produces from the Shuck Northwest Field located in South Central Kansas. Oil production is from the Chester Sandstone Formation at 6,300 feet. This formation is part of the much larger Mississippian System. Casinghead gas production is used to power the pump jack. Gas pressure is approximately 80 psig. This well has slight paraffin problems, but not severe enough to require regular hot oil treatments. (See: Appendix II; Josephine S. Burchett #1 Well Profile)

J.S. Burchett Production

Table 11

NOTE: Post-treatment production data from 1 December, 2009 through 30 April, 2010 is suspect and therefore was not used. Charted data runs through 30 November, 2009.

Oil production on the J.S. Burchett shows a slight downward trend from 4/01/2009 through 10/16/2009. Pre-treatment production from 1/01/2009 to 10/16/2009 (235 production days) averaged 1.89 BOPD. Post-treatment production 10/17/2009 to 11/30/2009 (43 production days) showed a 2.28 BOPD average, or a 0.39 BOPD / 21% increase.

Chart 1

The 18 week pre-treatment average was 1.90 BOPD which is virtually the same as the 235 day pre-treatment production average of 1.89 BOPD.

Glen Marcellus B1 & B2

Two wells in the Gen Marcellus 'B' lease were involved in the project. This lease is located the Shuck Northwest field, Stevens County, in Southwestern Kansas. Both wells produce from the Chester Sandstone formation at approximately 6,140 feet. This formation is an upper part of the much larger Mississippian System. Production fluids are pumped into a common tank battery. Casinghead gas runs the pump jacks of both wells. Gas pressure on the #B1 runs about 80 psig and the #B2 about 120 psig. (See: Appendix II – Well Profiles)

The #B1 pump was reported stuck closed and rebuilt on 6/28/2006 due to scale problems. This finding plus the water analysis prompted a treatment modification for the initial treatment. The first treatment for the #B1 made on 10/17/2009. Rather than the typical 2 day shut-in / soak period, the company recommended elimination of a soak after circulation as this might allow scale reformation. The well was treated, then shut in and well bore fluids were circulated for one day. The well was turned right back into production with no additional shut in time. The initial #B-2 treatment was made on 10/17/2009 using the same amount of MEOR fluid and method that was used for the J. S. Burchett. (See: Appendix II; Well Profiles)

Oil production from the Marcellus B1-B2 lease shows a fairly steep downward trend from 1 January 2009 to 17 October 2009. Although the average production for all 228 production days during this period was 4.42 BOPD, the last 42 production day (6 production week) the average was only 3.41 BOPD. No major mechanical issues are reported during this period.

Table 12

Comparison of average daily production for 42 production days (six production weeks) pre-treatment and post-treatment shows the Marcellus B1-B2 lease to have average 21.49 BOPW (3.07 BOPD) prior to its initial treatment and 23.87 BOPW (3.41 BOPD) for 6 weeks thereafter. However, the spread between pre-treatment and post-treatment averages narrows as one goes further back in the historical data taking larger and larger sample date ranges. Without barrel testing and WOR evaluations there is simply too little data in the 12 week period to establish a true production trend and validate incremental oil production.

Chart 2

Glen Marcellus #E-1

American Warrior's Glen Marcellus #E-1 well is in the Shuck Northwest field, Stevens County in Southwestern Kansas. Production is from the Chester Sandstone Formation at ± 6,300 feet. This formation is the upper part of the much larger Mississippian System. Gas pressure runs approximately 80-100 psig. (See: Appendix II; Glen Marcellus #E-1 – Well Profile)

Table 13

NOTE: NOTE: Post-treatment production data from 1 December, 2009 through 30 April, 2010 is suspect and therefore was not used. Charted data runs through 30 November, 2009. Weekly Gauge and Production Reports indicate the Marcellus E-1 well down for all of October, 2009.

Oil production was trending downward from 1/01/2009 to 10/16/2009

Chart 3

The Marcellus E-1 produced an average of 1.49 BOPD for the 6 weeks before the MEOR treatment date and 2.00 BOPD for 6 weeks thereafter. However, only five (5) days of production data are available from 10/17/ to 11/30/2009. This is far too few data points to establish any kind of a production trend or validate incremental oil production.

H.H. Wulfemeyer

American Warrior's H.H. Wulfemeyer #B-1 well produces from the Larrabee North Field located in Stevens County, South Central Kansas. Oil production is from the Upper Mississippian (Chester Sandstone) formation at ± 6,090 feet. (See:Appendix II; H.H. Wulfemeyer – Well Profile)

Table 14

NOTE: Post-treatment production data from 1 December, 2009 through 30 April, 2010 is suspect and therefore was not used. Charted data runs through 30 November. No production data prior to July 2009 is presently available.

The H.H. Wulfemeyer production has been trending downward since July 2009. The 86 day pre-treatment average was 3.21 BOPD, trending down to a 53 day pre-treatment 2.95 BOPD average, and down further to a 30 day pre-treatment average of 2.66 BOPD.

Chart 4 Wulfmeyer Production Trend

Chart 4

This trend continues downward for the 46 day post-treatment period which averages 2.35 BOPD. However, MEOR treatments were scheduled to take place at 30-45 day intervals. Looking at the 30 day post-treatment average shows 2.76 BOPD which is slightly above the pre-treatment 30 day average of 2.66 BOPD. The production decline then appears to resume 40 days after treatment. However there are too few post-production days of data to establish a trend or validate incremental oil production.

Chart 5

FINDINGS – American Warrior

This report reflects the results following one (1) MEOR treatment made in on 23 October 2009 with post-treatment data running through 30 November 2009.
Knock-out-pots were fabricated and installed on all wells for fluid injection and barrel testing, however no barrel testing or WOR evaluations were made.
Each well was to have received three treatments at 30 to 45 day intervals, only two treatments were made 85 days apart.
Weekly and monthly production data taken from the consolidated spreadsheet provided by the producer was the sole source of data used for analysis.
The consolidated spreadsheet data was cross-checked against the weekly gauge reports and to verify the data. Discrepancies in the numerous data sets disallowed use December 2009 and January through April 2010 data.
All project wells were initially treated on 23 October 2009, and second time on 17 January 2010.
All leases show a general decline in production from 1/01/2009 up to the initial treatment date of 10/16/2009.
Looking at a shorter pre-treatment time frame (30 to 120 days) rather than going back to 200 plus days to 1 January 2009 shows an even steeper decline trend for most wells, particularly the Wulfemeyer.
Looking at the 6 week period before and after treatment, the J.S. Burchett, Marcellus B-1-2, and Marcellus E-1 wells all appear to show increased production and/or an arrested decline trend.
Looking at the 4 week period before and after treatment, the Wulfemeyer well's decline trend is arrested and it shows a slight production increase. However the decline trend appears to continue at post-treatment week five.
No economic analysis was performed for American Warriors' project.

Conclusion

The findings outline the major factors that make the preliminary post-treatment analysis for American Warrior tenuous at best. Despite the appearance of positive results there is simply too little verifiable post-treatment to determine a production trend validating incremental oil production. An economic analysis of net gain or loss is also precluded.

PROJECT OVERVIEW - AX & P, INC.

Two single stripper wells and one small waterflood are involved in this portion of the project. The Wilson Unit #1 and Casebeer are single wells, and the Fee Lease is a waterflood with 1 injection well and 7 production wells, but only Fee well was pumped during the project period. All of these wells are located in the Neodesha Field, Wilson County, Kansas. The Neodesha Field is part of the vast Mid-Continent oil field covering parts of Kansas, Nebraska, Oklahoma, Arkansas, Louisiana, and Texas. The Neodesha Field's Norman #1 well came in on 28 November, 1892 and is credited with being the first well drilled West of the Mississippi to produce commercial quantities of oil. The portion of the field produced by AX&P is a unitized unit generally referred to as the Bailey Unit or Unit #1. This unit was put on continual waterflood by a previous operator during the 1950's and 1960's using fresh water drawn from the nearby Verdigris River.

Water analysis on the Wilson and Casebeer wells was performed by and conveyed to AX&P on 6/06/2009 in a written report. The analysis shows high TDS and calcium, magnesium, and barium chlorides in both single wells, well beyond conditions for the usual oil field indigenous micro-biota. The Casebeer being to the south, has a TDS about one half that of the Wilson, but this still is outside the MEOR treatability selection criteria. The Fee lease is located between the Wilson Unit to the north and Casebeer to the south. Although no water analysis is available for the Fee lease it was assumed that produced water would have an intermediate TDS and salt profile concentrations to the wells on the north and south. Indeed water from wells that are approximately due west of the Fee has an intermediate TDS and salt profile. None of these wells were considered good candidates for MEOR treatment, but they were included in the project in an effort to assess the applicability of the modified candidate selection criteria for identifying stripper wells that can be capably treated with the project's MEOR fluid.

(See: Appendix 1 – Unit #1 Field Map)

Historical and Post-treatment Production Data

Historical and post-treatment production data, treatment dates and methods, and oil sales were provided by AX&P via email. The water analysis was copied and picked up from the AX&P field office in September 2009.

Individual Lease Details

Wilson Unit #1

The Wilson Unit #1 is a one well lease which historically has produced 1 ½ barrels and 3 barrels of water per day. The well was originally drilled in the early 1920's and re-completed in the 1970's. Production is from the Bartlesville Sand formation with a top pay at 814 ft. and bottom at 820 ft. Produced water is a concentrated salt brine with calcium, magnesium, and barium chlorides and a TDS of 60,000. The well has slight paraffin and scale problems, but not severe enough to require hot oil or chemical treatments.

The initial treatment on 9/15/2009 was made to effect a near well bore clean-up. Treatment consisted of 5 gallons diesel and 15 gallons of MEOR fluid followed by ½ barrel of lease water. The well was shut in for 48 hours and well bore fluids were circulated for 48 hours before turning back into production on 9/20/2009.

The second treatment on 10/19/2009 was a fluid squeeze. The well was pumped off and 45 gallons of MEOR fluid were injected followed by 3 bbls of produced oil. A two day shut in followed and the well turned back into production on 10/21/2009. The well produced 3 ½ bbls of oil in 40 hours thus recovering the three barrels used for the squeeze. The third treatment, another fluid squeeze, was made on 12/01/2009 using 30 gallons of MEOR fluid and 1 ½ bbls of produced oil. The well was re-started on 12/03/2009 after a two day shut in.

The Wilson averaged 1.48 BOPD for 24 production days prior to its initial treatment and 1.56 BOPD for 26 post-treatment production days before the second MEOR treatment. The average production for 40 production day average following its second treatment was 1.46 BOPD. Only 6 production days of data are available following the third treatment. Produced oil used for the fluid squeeze was recovered, but no increase in production is show in the analysis of available data.

Casebeer Lease

The Casebeer is an old one well lease originally completed in the early 1920's and re-completed on 9/26/1968. 4 ½ inch casing was run to ± 820 ft and the well was perforated with 32 shots between 762 and 776 feet. This well is located at the edge of the old East Unit waterflood that was conducted from the mid-1950's until late 1960's. Water analysis show lower TDS and chloride concentration than the Wilson Unit #1. It appears that the Casebeer well has been affected by near by water injection activity at the Fee lease though there is no injector on the lease. Oil production is from the Bartlesville Sand formation and has historically run about one barrel oil and three barrels water per day. The produced waters are pH 6.8 and TDS of 32,000 indicating dilution by the previous and adjacent fresh water flood. The well has slight paraffin and scale problems, but not severe enough to require hot oil or chemical treatments. The Casebeer well pumps into a separate tank so accurate production measurements can taken over the course of this project.

Initial Treatment for near wellbore clean-up was made on 4/09/2010. Wellbore fluids were pumped off and 10 gallons of diesel injected through the annulus, followed by 30 gallons of MEOR fluid. A ½ barrel flush of lease water completed the treatment. The well was then shut in for 1 day and circulated 1 day before turning back into production on 4/12/2010. A second treatment was made on 5/25/2010 using the same volume of MEOR treatment fluid and 10 gallons of lease water due to low static fluid level. The well was shut in for 1 day and wellbore fluids circulated for 1 day before turning the well back into production on 5/28/2010.

Casebeer – Preliminary Results

The Casebeer historically has produced a little less than 1 BOPD. Post treatment production through 7/31/2010 remains unchanged. This is not surprising as the water analysis places this well near the limit for treatability. An MEOR regimen that injects viable, salt-tolerant microbial in combination with the requisite nutrients may produce a positive response from the Casebeer.

Fee Lease - Enhanced Waterflood

The Fee Lease is composed of one injection well and 7 producing wells only 2 of which were pumped during the project period. Produced water is held in a 90 bbl tank and re-injected into the oil-bearing formation periodically when the tank is full. It takes approximately 1 day to inject the 90 bbls of lease water. There is direct connectivity from the injector to the Fee #7 approximately 800 ft East. Fracture channeling is evidenced by the amount of re-injected water produced at the Fee #7 compared to the adjoining Fee wells. Selective plugging of this diversion channel would lower the WOR of the #7 well. This Unit was part of an ARCO waterflood project begun in the 1950's and suspended in the late 1960's.

A treatment was made on 5/25/2010 by mixing 110 gallons of MEOR fluid with 60 BBLS of lease water in the holding tank to make a 4% dilution which was then injected through the existing injection system over a 12 hour period. Enhanced waterfloods require 60 to 90 days or more to evidence a production trend and determine follow on treatments. The two Fee lease productions wells have been down all of June and July. As of this report there is insufficient data to determine what, if any, effect the single MEOR treatment has on oil / water production from this lease.

FINDINGS – AX&P, Inc.

1) Based water analysis and the geophysical and geochemical characteristics of this field, the project wells were considered to be marginal candidates for this MEOR technology.

2) The Wilson #1 Unit was treated with a near wellbore clean-up, shut-in circulation with soak period, and a fluid squeeze.

3) Produced oil used for the fluid squeeze was recovered with no improvement in oil production.

4) Oil / water rations remain unchanged.

5) There is insufficient post-treatment data available for the Fee and Casebeer leases to determine a production trend or validate incremental oil production.

Conclusion

Preliminary results help validate the use-fullness of the modified treatment criteria matrix for this MEOR technology. Large amounts of down time due to local flooding postponed the initial treatments, and flooding plus routine maintenance requirements prevented continuous pumping operations during the project period. Gauge readings were taken on production days, but with this low oil production, a more accurate measure of produced fluids was called for. Another MEOR approach using a microbial system composed of viable salt-tolerant microbes has greater potential for producing incremental oil from these leases. Water diversion channeling was evident on the Fee lease. Selective plugging by a variant application of MEOR would be recommended to address this production problem.

PROJECT FINDINGS & RECOMMENDATIONS

The key findings and recommendations for improving this microbial oil recovery technology can be summarized as follows:

Findings

MEOR treatment fluid can be produced by conversion of readily available non-hazardous waste streams.
Manufacturing / processing is conducted at standard atmosphere and pressure using relatively inexpensive off-the-shelf equipment.
The pilot plant design is modular, easily scalable, and manufacturing / processing facilities can be located near or at multiple MEOR projects.
The MEOR treatment fluid was found to have chemical properties; chelating, reducing, acidizing, and surfactant, suggesting uses other than bio-available nutrients for the indigenous micro-biota.
Project wells were screened and selected using a modified version of the company's candidate selection matrix.
Preliminary results from project wells judged not to be good candidates for MEOR treatment according to the screening matrix showed no production increases.
Conversely, some wells judged to be good candidates did not respond positively.
Several application methodologies were employed that can likewise be easily implemented by stripper well operators.
Average daily pre-treatment production vs. average daily post-treatment was the sole criteria used to validate incremental oil increase.
Data analysis excluded days showing zero gauge inches noted as down days.
Preliminary results show slight to moderate increases in oil production and/or short-term arrest of production decline trends in 9 out of 14 project wells.
One of the 3 enhanced waterfloods shows a measurable increase in production.

Recommendations

To enable this MEOR technology to produce consistent and predictable results, the following areas should be further investigated:

Determine the correlation of candidate selection criteria with wells showing positive results to enable stripper well producers to better determine which wells are more likely to respond to treatment.
Develop an inexpensive rapid field test to determine whether or not a well will produce positive oil production.
Conduct follow-on trials using high-end analytical techniques to assess the pre-treatment and post-treatment micro-biota metabolites and triggers so that oil production increases can positively be attributed to stimulation of indigenous populations.
Conduct laboratory and pilot field projects to evaluate the use of this MEOR fluid for near wellbore clean-up, acidizing treatments, and paraffin control.
Implement manufacturing improvements identified during the project to shorten batch processing time and product stability.
Investigate treatment methods that combine both in situ stimulation and injection of specially selected microbial strains.
Improve existing MEOR simulation and predictive models to enable objective engineering to be applied to field-wide MEOR projects.
Encourage and foster cooperation between microbiologists, reservoir engineers, geologists, and petroleum chemists.

SUMMARY & CONCLUSION

This report presents the results of research and development work leading to the successful production of a benchmark MEOR treatment fluid and preliminary positive results from field trials which were carried through the reporting period of 7/31/2010 for Schlobohm Oil Operations. Findings of results, recommendations, and conclusions for each cooperating producer are presented in their respective sections. The overall project findings and recommendations are summarized here above. An economic assessment was made for Schlobohm Oil using the aggregated amount of incremental oil produced within the margin of accumulated error.

MEOR treatment fluid was derived from locally available raw feed-stocks consisting of non-hazardous brewing and bottling industry waste streams converted by microbiological processes. Multiple feed-stock sources were identified and samples were obtained and evaluated for compatibility with the company's microbial conversion process. Modifications to the manufacturing process were identified and implemented which enabled acceptance of a wider range of raw feed-stocks. R&D work identified process modifications for improved product stability, shelf-life, and performance which warrant further investigation. These are discussed in the manufacturing / processing section of this report.

The pilot plant design and layout was modular and easily scalable. MEOR treatment fluid was processed in batch and semi-batch mode. This opens the possibility of locating multiple manufacturing operations virtually on site, and the utilization of locally and regionally available raw feed-stocks that would result in significant cost reductions. Per gallon manufacturing costs under pilot plant operations were determined and cost projections made at various scaled-up production levels and shipping rates.

Potential candidates were screened and selected prior to treatment using a modified MEOR selection matrix. AX&P's wells were judged borderline candidates due to high TDS, but they were included in the project in an effort to refine the selection matrix. None of AX&P's wells showed production gains, which tends to validate the selection matrix. However, some wells judged as viable candidates showed no response to treatment. This points to the need for a reliable predictive tool / field test for assessing the strength of an individual well's response to this MEOR technology prior to treatment. In lieu of a reliable field test, this project adopted a 'shotgun approach' whereby, under normal business operations, the well's response to initial treatments would determine whether or not to place that particular well on an MEOR maintenance regimen.

Water and oil samples were evaluated for compatibility with the MEOR fluid and for indications of potential problems with H₂S, corrosion or scale. Testing showed a low likelihood of negative performance and none of these problems were reported for any of the project wells. Several different treatment methods with varying amounts of MEOR treatment fluid were used depending upon the depth of the production zone(s) and the specific application; 1) 15 to 50 gallons MEOR fluid with shut-in circulation for 1 to 2 hours and two day soak was used for near well bore clean-up and no circulation for soak applications, 2) 25 to 50 gallon slugs were used for fluid squeeze applications intended to stimulate microbial activity in the critical production matrix (3-5 meters out from the well bore), and 3) 100 to 250 gallon slugs injected with co-produced lease water for microbial enhanced waterflooding. Dosing by doubling or quadrupling the initial slug of treatment fluid should be further evaluated.

By analysis of post-treatment data, single wells that respond to treatment began showing results as soon as they are turned back into production after flush (if any) had been produced. One of the three enhanced waterfloods treated showed a measurable amount of incremental oil. Waterfloods look to require 60 to 90 days or more before beginning to evidence changes in oil production. The determining factors for how long takes for a showing of incremental oil at are: distance from injector to producer, formation permeability, and injection rates, volumes, and pressures. No well damage was reported for any of the project wells or enhanced waterfloods over the course of the extended project period.

This project assumed that microbial populations beneficial to oil recovery were present in all candidate wells and that their metabolic activity would be increased by injecting the MEOR treatment fluid - a bio-available nutrient media. Although several single wells and one waterflood showed measurable production gains through the reporting period, validation of incremental oil production by stimulation of indigenous microorganisms remains inconclusive. Additional field work is required to determine whether the positive responses indicated are due to increased metabolic activity, near well bore clean-up, or a combination of both.