TRIMETEOR has spent six and a half years in R&D of the QUAD-S system. The following information is the summary of some of the key test results.
RMOTC Field Testing
A primary goal of field-testing at RMOTC was equipment functionality. It should be noted that at the time of our testing at NPR-3, our Superheated Steam Supply System, the QUAD-S™, was less advanced than today’s model. The temperatures and volume of steam achieved were sufficient at the time to accomplish our testing protocol, however, since 2011, the QUAD-S™ has significantly improved in performance, primarily thermal stability of its alloys and materials resulting in ASME (American Society of Mechanical Engineers) certification, refinement of custom high-temp heaters, implementation of a more sophisticated water delivery system, full automation, and sustainability, e.g. duration of operation. The Company was able to observe equipment systems performance in a real world, non-commercial environment. Not having to meet the expectations or concerns about constant production let us focus on observing and making changes to the water treatment and delivery systems and experiment with program changes affecting water injection and temperature control. This experimentation led us to significant improvements in system design and process control operation. These findings have already been incorporated with great success into the company’s newest equipment.
Another target goal was to develop and perfect the Company’s unique installation methodology for which a Methodology Utility Patent was filed in November 2012. The Trimeteor process is distinctive in that it is primarily well specific and oil production continues during the delivery of steam down the production wellbore through the use of high-temp insulated tubing, which is attached to the production tubing. Injection wells are not necessary, although our process could be adapted to such a configuration. We were able to practice, perfect and document this process at RMOTC. The availability of qualified personnel to operate work over rigs, workshops with “oil field” ready tools facilitated immediate changes to equipment made it possible to refine this procedure quickly.
Lastly, the Company wanted to test the QUAD-S™’ ability to both deparaffin wells and achieve lateral distribution. The buildup of paraffin and the resulting decrease in production is a common problem in the production of oil. Current methods for mitigating this problem include chemical treatments and circulating hot oil through the well bore. These methods are expensive, environmentally unfriendly and not wholly successful. The results of the superheated steam injection were immediate. Paraffin build up in each well bore was melted and removed within the first 24 hours. Flush production (“a high flow rate reached with a new well” Schlumberger Oil Glossary) occurred in each well up to a maximum of 38.41 barrels in one well after clean out.
RMOTC provided the company with four primary wells and four monitor wells, which had been shut-in since 2008-2009. These wells were an average depth of 1,700 to 485 ft. and were located in the Shannon, an area known for its sandstone formation. All of the wells were paraffinitic and on the periphery of the producing zone. Each monitor well was located within 300 to 600 feet of a corresponding primary well and were included in the test parameters to discover what, if any, lateral distribution of steam would be achieved. The QUAD-S™ was installed and operated on the primary wells during the months of June through the first of September 2011. Fluid production was recorded on both the primary and monitor wells. Superheated steam was introduced in the primary wells one well at a time. Baseline oil production was established for each well prior to the commencement of steam injection.
Results from two of the four primary production wells and their corresponding monitor wells are explained below. Baseline production on these wells was an average of .2 to .97 BOPD as reported by the Wyoming Oil and Gas Commission (WOGC) for the period 2000-2008 and 2009 when last active. It should be noted that the decrease in production over time is an inherent problem in the oil industry and is directly related to decreased reservoir drive and insufficient EOR technology to reach the remaining oil at Teapot Dome.
Average production over the test period ranged from 5.4 to 12.2 BOPD in the primary wells and 7 BOPD(1) in the monitor wells. It should be noted that during our test period, RMOTC had approximately 71 to 78 producing wells averaging 1.9 to 2.1 BOPD(2). Trimeteor’s test wells were the highest producing wells at NPR-3. These production increases represent significant percentage increases. The oil recovered from the test wells was pipeline ready and needed no treatment.
Another significant detail is that the DOE resumed production on Trimeteor’s test wells in April of 2013 using their conventional steam methodology. Average production on the two primary wells were 1.61 and .58 BOPD from April through September 2012 compared to Trimeteor’s test production as stated above of 12.2 and 5.4 BOPD, respectively. Production on the two monitor wells for the same period, as reported to the WOGC, were an average of .90 and .21 BOPD compared to Trimeteor’s test production of 6.9 and 7.0 BOPD, respectively.
New Castle Field Testing
A primary goal of testing at this field was to prove the functionality of the innovations made to Trimeteor’s Superheated Steam Generators during the first two quarters of 2012. The improvements were the result of engineered solutions to machine functionality, which Trimeteor became aware of during our testing at RMOTC. Another primary goal was the opportunity to test in a “heavy” oil field. Having already demonstrated the ability to increase reservoir drive mechanisms and to remove paraffin at RMOTC, further tests needed to be conducted in wells with oil < 20 API.
Baseline production on the wells tested, as reported to the Wyoming Oil and Gas Commission from 2007 to 2012, was an average of 1.15 BOPD on well 201 and 1.6 BOPD on well 101. It is significant to note that total liquid produced from these wells since 2007 was approximately 46,000 bbls, 3,000 bbls of oil and 43,000 bbls of water. Additionally these wells had an average oil to fluid ratio commonly referred to as the “oil cut” (the fraction of the total flow rate produced from a well that is due to a particular fluid), of 9.2% on well 201 and 5.2% on well 101.
In the first full month of testing, July 2012, oil production increased on well 201 from a historical average of 1.15 BPOD to 9.4 BOPD(3). Another positive outcome from the Trimeteor process was the substantial improvement of the cut on well 201 from a historical average of 9.2% for the years 2007-2012 to 27.5% in July 2012 with an average increase in the cut to 20% for the three months ended September 2012. The results of Trimeteor’s superheated steam injection was less efficient on well 101 due to the PTOC’s continued flooding into the selected well which challenged the integrity of the test results.
Finally, and maybe more dramatically, is the fact that the increased production evidenced by Trimeteor was complimented by a significant decrease in utility costs (water and power). In other words the SOR was extremely low meaning the more efficiently the steam was utilized, the lower the associated costs (Schlumberger Oilfield Glossary).
(2) The Company assumes that the WOGC calculates their BOPD using total production/days pumping. The Company did not believe that this calculation represented the performance of the QUAD-S™ due to their expected downtime. However, with an injection rate of 64%, it became obvious that the wells were being stimulated and reservoir drive mechanisms affected; and even with the downtime factored in, the residual effects of the steam were at work. Therefore, for comparative purposes, the Company is presenting herein Trimeteor’s BOPD at RMOTC using the assumed WOGC formula. Average production over the test period ranged from 3.5 to 5.8 BOPD in the primary wells and 3.1 to 4.6 BOPD in the monitor wells.
(3) The Newcastle test was performed on wells with a significant water table and oil cap, as well as the lessee’s continued flooding into the test wells. As a result down hole temperatures were much lower than expected. During the machines downtime, the Company believes that there was substantial heat loss resulting in no residual benefit from the steam (heat) due to the water dominance of the reservoir. Therefore, BOPD was calculated as a percentage of days steaming.