Attachment_5-_2010_Updated_Est_of_Project_Life_0001.pdf

Subsurface Technology, Inc.

6925 Portwest Drive Suite 110 Houston TX 77024 713/880-4640 Fax 713/880-3248 1-800-535-4105

February 11, 2010

Mr. Andy Nicholas U.S. Department of the Interior Bureau of Reclamation Post Office Box 49 Bedrock, Colorado 81411

Re: 2010 Updated Estimation of Project Life Subsurface Project 60Z6449

Dear Andy:

Pursuant to your request, we have updated the injection data for Paradox Valley Injection Well No. 1 and revisited the predictions for the life of the well. Generally, the estimates of ultimate project life have not changed appreciably, but they have narrowed somewhat.

Subsurface submitted an Estimation of Project Life on December 19, 2005. For reference and convenience, that complete document is attached to, and made part of this report. Since the report was submitted, the BOR has modified the surface injection equipment to a maximum surface injection pressure rating of 5,300 psi. The increased maximum injection pressure will significantly extend the reservoir life. However, as the pressure increases in the reservoir system, there is also the increased likelihood that the frequency and magnitude of seismic events will increase. This is addressed in detail in the recently issued Technical Memorandum 86-68330-2009-22. Specifically, the frequency of events in 2009 increased after a period of relative quiet in the years from 2005 through 2008. More correlation is discussed later in this report.

Since the 2005 update, injection has continued according to the planned schedule of 160 injection days followed by 20 days of shut-in time to allow the reservoir to “relax”.

The injection rate is nearly constant at approximately 230 gallons per minute, except for planned shut-down periods and occasional mechanical problems. Figure 1 is a graphical display of the injection rate and pressure history from 1996 through 2009.

The gradually increasing magnitude of injection pressure is apparent in Figure 1. The uppermost trend is the calculated bottom hole injection pressure which is based on the measured surface pressure, brine density, and friction at 230 gallons per minute. The middle trend is the measured surface injection pressure. The scale for the upper and

Andy Nicholas February 11, 2010 U.S. Department of the Interior Page 2

BOR/60Z6449/2010 Update middle trends is on the left axis. The lower trend (red) is the injection rate in gallons per minute, with the scale displayed on the right axis. A line has been inserted in the upper trend at the approximate value of the bottomhole pressure during the high-rate injection from July 1996 to May 2000. When extended to present, it is apparent that a significant portion of each injection period occurs at pressures that are equal to or greater than the pressures from 1996 to 2000, especially through 2008 and 2009. The pressures recorded are located at the bottom of the well, but are distributed in time through the reservoir system. Consequently, there is likely a lag in time between the recorded injection pressure and the pressure which may correlate with the time lag discussed in the Technical Memorandum

Figure 1

Injection Rate, Surface Pressure, and Bottomhole Pressure, 1996 Through 2009

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Jul-96 Jul-97 Jul-98 Jul-99 Jul-00 Jul-01 Jul-02 Jul-03 Jul-04 Jul-05 Jul-06 Jul-07 Jul-08 Jul-09 Jul-10

Date

In je ct io n P re ss u re p si

In je ct io n R at e

(g p m

Surface (psi) Bottomhole (psi) Rate (GPM)

96-09 Sfc Press Rate

As discussed in the 2005 evaluation, the most consistent performance evaluation tool we have had is the semi-log plot of injection pressure and the log of injection days for each injection session. Although this plot is not designed to evaluate fractured reservoir systems, this evaluation approach has produced reasonably consistent linear trends for

U.S. Department of the Interior Page 3 over 19 years. The linear trends on the semi-log plot generally begin approximately 20- 30 days into the session and continue to the end of the session unless the injection is interrupted by mechanical conditions. Figure 2 is the Semi-log Pressure Buildup from June 2000 to August 2005. Figure 2 was also included in the 2005 report. The slope of the linear portion of individual injection periods are presented in Figure 2 and appeared to be converging or decreasing in slope over time.

Figure 2

Semi-Log Pressure Buildup June 2000-August 2005

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Jun-Dec 00 Jan-Jun 01 Jun-Sep 01 Sep-Dec 01 Jan-Jun 02 Jun-Dec 02 Jan-Jun 03 Jun-Dec 03 Jan-Jun 04 Jun-Sep 04 Sep-Dec 04 Jan-Jun 05 Jun-Dec 05

Slope = 200 psi/cycle Slope = 240 psi/cycle Slope = 290 psi/cycle Slope = 345 psi/cycle Slope = 366 psi/cycle Slope = 355 psi/cycle

Log Chart Inj 00-05

Figure 3 is the Semi-log Pressure Buildup for injection sessions from June 2006 to December 2009. Because of the large amount of data, and overlapping pressure curves, the continuation of Figure 2 for report was deemed impractical. There are only four pressure trends shown on Figure 3. The two injection sessions for 2006 and the second session of 2007 encountered periods of inconsistent injection rate, which impacted the linear portion of the trend, and were excluded from Figure 3. Each of the four remaining injection sessions displayed some periods of interrupted injection;

however, the interruptions did not affect the magnitude of the pressure in the 40 to 90 day time period. An estimation of the straight line portion was manually placed through those segments and a “representative” slope of 367 psi per cycle was calculated. In

U.S. Department of the Interior Page 4 comparison, in Figure 2, the individual slopes from 2000 to 2005 ranged from 200 psi per cycle to 365 psi per cycle.

Using the estimated pressure increase of 367 psi/cycle and a maximum bottom hole injection pressure of 12,383 psi (5,300 psi surface injection pressure, less friction, plus hydrostatic pressure), an estimated time was calculated to reach the maximum of 5,300 psi surface injection pressure.

Figure 3

Semi-Log Pressure Buildup January 2007 to September 2009

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Jan-Jun 07 Jan-Jun 08 Jun-Dec 08 Apr-Sep 09 BHP at 5300 psi Sfc

367 psi/cycle

BHP at 5300 psi Surface Injection

Log Chart Inj 07-09

Bottom hole injection pressure on Day 100 (September 9, 2009) was 11,896 psi.

Remaining pressure increase to reach 5,300 psi (surface) is 12,383-11,896 = 487 psi.

At 367 psi per cycle, the time extrapolation to maximum pressure is 487/367 or

1.326 cycles.

U.S. Department of the Interior Page 5

Adding to Day 100 ( the second cycle), total days = 3.326 cycles or 2120 days or

5.8 years of continuous injection with no consideration for the 20-day relaxation periods. Since continuous injection is not planned, this extrapolation is not valid for prediction of overall well life.

The pressure falloff periods from 2000 through 2005 were presented in the 2005 report and are included in this report as Figure 4. The pressure falloff curves, although similar are not parallel. They are provided as a visual comparison of the trends. Pressure falloff calculations (transient pressure analyses) have not been proven to provide good results in the past, because the fractures close and the pressure transient dynamics in the reservoir change. No attempt has been made to evaluate the pressure transients in this report.

Figure 4

Pressure Falloff Periods 2000-2005

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Days After Shut-In

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May-00 Dec-00 Dec-2001 Jun 2002 Dec-2002 Jun-2003 Dec-03 Jun-04 Jun-05 Nov-05

PFO 00-05

U.S. Department of the Interior Page 6

Figure 5 is a plot of the pressure falloff for the injection sessions from November 2005 to October 2009. The spacing of the individual pressure falloff curves is closer and more consistent from 2005 to 2009 and the magnitude of the pressures has increased by 200 psi in the last 4 years. It is interesting to note that the pressure falloff for December each year is slightly higher than for the June pressure falloff. It is possible that cooler injection temperatures and the ensuing thermal recovery are affecting the magnitude of pressure during the winter months.

Figure 5

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Days After Shut-in

Pressure Falloff 2005 to 2009

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NOTE: The top three curves are for Dec 2008, Dec 2007, and Dec 2006. The falloff pressures are slightly higher in December than in June each year. The heavy blue curve is for Oct 2009

PFO 05-09

For comparative purposes, the pressure at the 100th day of injection, 140th day of injection, and the falloff pressures on the 10th, 15th, and 20th day of each session are plotted in Figure 6. The significance of this selective comparison is that during most sessions, the injection pressure at 100 days is very close to the injection pressure at 140 days and that the difference in pressure on the selected falloff days is relatively constant. There is no apparent trend that is readily recognizable from this composite plot.

U.S. Department of the Interior Page 7

Figure 6

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C al cu la te d B o tt o m h o le P re ss u re

Reference Date

Injection and Falloff Pressure for Injection Sessions

100 days injection 140 days injection 10 day falloff 15 day falloff 20 day falloff

Inj and PFO vs Days 05-09

To provide a series of trends that may be used for predictive purposes, pressures were plotted as a function of the total volume of fluid that has been injected into the reservoir system. All previous analysis of the Leadville system has indicated that the natural porosity of the formation matrix is extremely low, and that the bulk of the capacity of the reservoir is in the volume of the fracture network, both natural and induced. As fracture channels widen or grow in length, the volume of the fracture grows. This is accomplished by the compression of the rock and minute movement of blocks of rock to allow fluid to enter the void spaces under pressure. Consequently, the trend of pressure as a function of volume injected may lead to more predictive behavior.

Figure 7 is a plot of the calculated bottomhole pressure as a function of cumulative volume injected during the life of the project. To date, approximately 1.65 billion gallons of water have been injected. From 1996 to mid-2000, the injection rate varied from 300 to 350 gallons per minute, at the maximum allowable surface pressure of 5,000 psi.

The fluid injected was a dilute form of PVB and the calculated bottomhole pressure during injection was approximately 11,750 psi. In May 2000, the injection rate was reduced to approximately 230 gallons per minute and was sustained at a more constant rate than previously maintained. A schedule was also established to inject for 160 days, U.S. Department of the Interior Page 8 with a 20-day relaxation period. Generally it was planned for two injection sessions of six months per year. In January 2002, dilution of the brine was discontinued and the injection of 100% PVB began. Since then, nearly one billion gallons of PVB has been injected.

Figure 7

An approximation of a straight line has been inserted aligning the maximum injection pressure for each session from March 2003 to December 2009. The slope of the straight line has been calculated to represent a pressure increase of 0.342 psi per million gallons injected.

The maximum injection pressure during the session was 11,963 psi on September 28, 2009. Using a maximum bottomhole injection pressure of 12,383 psi, the remaining pressure increase is 12,383 - 11,963 or 420 psi.

Dividing: 420 psi / 0.342 psi per million gallon yields a remaining volume of

1,228 million gallons or 1.228 billion gallons.

U.S. Department of the Interior Page 9

Estimating 230 gallons per minute x 325 days per year, the annual injection volume is 107,640,000 gallons per year.

Dividing: 1,228,000,000 gal/107,640,000 gal per year yields 11.4 years remaining.

A second plot of pressures as a function of cumulative volume injected is presented as Figure 8. The injection pressure at 120 days into each session and the falloff pressure at 20 days after shutdown were plotted as a function of cumulative volume.

Figure 8 y = 4E-07x + 11234 y = 4E-07x + 7904

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Cumulative Volume (gal)

Pressure at 120 days injection and 20 days Falloff

120 Day Injection Pressure 20 Day Falloff Pressure Linear (120 Day Injection Pressure) Linear (20 Day Falloff Pressure)

Inj 120 FO 20 02-09

The data for both series was processed to calculate the slope of the linear curve fit.

The slope of the curve was calculated to be 0.400 psi per million gallons.

Using the equation of the 120-day injection pressure line and letting y = 12,383 psi, then x = (12383-11234) / 4 x 10-7 or 2.875 billion gallons (ultimate capacity).

The remaining volume is then calculated to be 2.875 billion - 1.65 billion or 1.225 billion gallons

U.S. Department of the Interior Page 10

At 107,640,000 gallons per year, the remaining life of the system is 11.35 years.

In the 2005 report, a comparison of the 20 day falloff pressure was made as tabulated in Table 1. Based on those pressures, the bottomhole pressure had increased by 1855 psi in 14 years of operation.

Table 1 Bottomhole Pressure on the 20th Day of Pressure Falloff

August 1991 6537 psi

November 1993 7663 psi April 2005 8392 psi

January 2007 8453 psi January 2008 8472 psi January 2009 8484 psi

Since April 2005, the 20-day falloff pressure has increased by only 92 psi (See also Figures 6 and 8 above). This is indicative of the growing fracture network that has been created by injection and the expansion of the area that is subject to "bleed-off" of the induced pressure. The number of seismic events in the near wellbore area tends to support the speculation that the fracture network size is increasing.

In the 2005 report, the final injection pressure for each injection session was plotted in Figure 3. The slope of the linear approximation of the pressures from January, 2002 to November, 2005 was calculated to be 0.4678 psi/million gallons injected. Based on the maximum allowable surface pressure of 5,000 psi, the predicted life of the well, at 230 gpm injection rate, was 7.14 years extending into 2013. With the anticipated increase of surface pressure to 5350 psi, the anticipated life of the well was estimated to be 14 years or 2020.

The current extrapolation of the data from 2005 forward, using a maximum surface injection pressure of 5,300 psi, is 11.3 to 11.5 years from the end of 2009, which is consistent with the 2005 projection of 2020.

Additional life projections were made at rates of 173 gpm, 117 gpm, and 58 gpm as tabulated in Table 1 of the 2005 report. Projection at reduced rates has not been included in this report.

There were five observations made on page 3 of the 2005 report. The first two are compared below:

U.S. Department of the Interior Page 11

First, it was stated that the individual slopes of the straight line portions of the semi-log plots appeared to be decreasing as the pressure increased. The data currently suggests that this may not be valid; however, the inconsistency of the injection rate for the last few years may be affecting the current observation.

Second, it was stated that the extrapolation of the converging straight line portions of the semi-log plot indicated that the 5000 psi pressure could be reached in 7000 days. The current estimated slope of the composite straight line portions (Figure 3 above) is greater than the slope that was used in the 2005 report, and thus predicts a shorter life of continuous injection than was predicted in 2005.

Subsurface bracketed three possible scenarios in the 2005 report, ranging from the most conservative estimate of project life to the most liberal estimate. The most conservative estimate was based on the increasing trends of injection pressure at approximately 200 psi per year and estimated that the maximum allowable injection pressure could be reached in 3-1/2 years. That would have been sometime in 2008 and it did not happen. The most liberal estimation was 19 years based on the extrapolation of the "converging and decreasing" slope of the linear portion of the semi-log plots.

Currently, Subsurface believes the data does not support that estimate. The "mid-range" prediction of 14 years, which was based on a pressure increase of 0.467 psi per million gallons injected, appears to be closer to the current estimation that includes the additional injection data from 2006 through 2009.

In summary, the current estimate of project life is approximately 11 years from the end of 2009, or approximately 2020. This estimate is based solely on the hydraulic and pressure response in the reservoir. This report does not attempt to predict the seismicity that results from injection and the increased fluid pressure in the reservoir.

The ultimate life of the reservoir will be decided by either the mechanical pressure limitations of the well, the downhole integrity of the components of the well, or the frequency and magnitude of the seismicity.

Subsurface still believes that the ultimate extension of the life of the project will be a second well installed in a fault block that is not hydraulically connected to the current fracture system.

The opinions expressed in this report are those of the undersigned. Subsurface appreciates the opportunity to update the project data, especially considering an involvement of nearly 25 years.

U.S. Department of the Interior Page 12

Sincerely, Jim Bundy Director of Engineering

JDB/jz

Attachment – December 2005 Report