BOB: For your eyes only! *ggg*
Think this stuck to my ''tackle'' box when I left today. :o)
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September 21st 2000
Contributing Analysis from:
Fall Line Energy – Colorado, USA
Petrel Robertson Consulting – Calgary, Canada
Adams Pearson Associates – Calgary, Canada
Fall Line Energy – Scott Stinson PE - Summary
Conclusions:
1. The test was successfully performed and met the stated objectives of establishing economic production rates and reviewuating the completion. The test data was of high quality but influenced by numerous wellbore induced anomalies (fluids moving past the gauges, cross flow between zones, condensation, etc.). These anomalies caused pressure changes at the gauges, which added a degree of difficulty to the reservoir analysis, in particular, to the estimations of true reservoir pressure and depletion. Despite this, several highly useful conclusions can be derived from the test.
2. The short term flow test was not designed for, or conducive to, reviewuating the reservoir limits or the size of the container, but instead was designed for reviewuating the efficiency of the completion. Extended production testing (EPT) is recommended once gas sales are possible to help quantify the size of the reservoir.
3. Commercial production rates were established from the Bloemer-Phacoides interval from 19,370’-19,698’. Stabilized flow rates were established of 13 MMCFGD, 120 BCPD and 4000 BWPD on a 20/64” choke with flowing tubing pressure of 8100 psi. Gas analysis indicates a 1250 BTU gas (3.48% CO2, 29 ppm H2S). Bottom hole temperature is 368 F.
4. The apparent skin factor for the completion is in excess of +50. This high skin is caused by a combination of: 1) a partial penetration of the reservoir, 2) multiple layers with natural fractures and 3) near wellbore formation damage. This high skin yields a completion efficiency of 20%. Theoretically, if all the skin could be removed, this reservoir would have delivered, under the same drawdown conditions, a gas flow rate in excess of 65 MMSCFD.
5. Reservoir pressure is estimated to be 16,927 psig (mid perfs: 19,534’ datum, .866 psi/ft gradient).
6. The well was flow tested for 124 hours (5 days). Total gas production during this time was 74 MMCF, 1860 barrels of condensate and 16,140 barrels of water. Despite this production, the initial and final shut in pressures, after accounting for different fluids in the wellbore, were essentially identical. Therefore, no apparent or quantifiable depletion occurred as a result of the test.
7. The best description of the reservoir, as investigated by this test, is an unlimited container with a dual porosity system (matrix and fracture). The one thin section taken of the Bloemer-Phacoides (porosity of 10.8%, perm. of .28 md) would suggest this as a very probable scenario as both matrix porosity and microfractures could be seen in the thin section.
(2)
8. The late time pressure recovery data indicates that there was approximately a 7 psi additional pressure drop beyond the infinite acting radial solutions. This pressure drop could be associated with any number of outer boundary/shape conditions such as 1) a pressure differential between fractures and the matrix, 2) one or two boundaries at some distance from the wellbore, or 3) trap curvature mimicking a boundary. Attempts to draw any conclusions regarding the shape of the reservoir and/or determining distance to a boundary from this test would be purely speculative and strongly influenced by assumptions about fluid and rock properties (in particular compressibility) and zone thickness. The estimated radius of investigation of this test was approximately 1500’.
9. The container reviewuated only took into account the Bloemer-Phacoides interval. All additional sands both above and below were not seen during the flow and build up tests. Per discussions with your geologists, the Bloemer-Phacoides interval should have a relatively constant thickness throughout the prospect area. Assuming this to be the case, and the fact that the blowout well located 2.3 miles southeast of the BKP #1 encountered the Temblor sands 139’ high to the BKP #1, the Bloemer-Phacoides should be present and gas saturated within this area of investigation. Volumetrically with the pressures seen during the test and the lack of any apparent boundaries the implied gas in place between the two wells in the Bloemer-Phacoides would be in excess of 1 TCF.
10. Attached is a Radial Analysis plot showing pressure buildup vs. time. As you can see, the pressure built up extremely fast during the initial shut in period indicating significant, near wellbore pressure drop (skin). The late time data is very flat indicating good permeability.
11. A multi-flow system was observed during the test indicating both fracture flow and matrix flow. The fracture network appears to be very extensive, essentially creating it’s own pseudo-matrix. The water flow appears to be coming out of the fracture network somewhere below the bottom of the perforations. During the shut-in portion of the test, the 7600’ of water that was in the tubing could be seen to drain from the tubing and reenter the formation. The manner in which the fluid levels dropped may indicate a limited water reservoir. While the well did start making water within the first day of production, it is doubtful that long term water production will ever be a problem. This conclusion is based on the following observations.
First, The stable to declining water/gas ratio. I have included a plot of the ratio of water to gas production. The ratio had stabilized and started to decline the last 1.5 days of production. On the cumulative production plot, this is the period after 10,000 bbls. This stable production level indicates the hydraulic connection to the water zone is limited or the total size of the water zone is limited.
Second, The limited ability of the water to expand and the limited aerial extent it could reside over relative to the thick and aerially extensive gas column. In general, overpressured reservoirs have limits to the size of the aquifer present. Both water and gas exist in the reservoirs during over pressurization and neither is free to leak out. The water will settle to the bottom of the compartment but has limited aerial extent and very little fluid compressibility. However, the gas has the potential to expand 400:1 (1/Bg). What may only be 100 MCF of reservoir gas space contains 40 MMSCF of gas at surface conditions.
(3)
Third, The manner in which the water drained from the wellbore. Approximately 1 hour after shut-in, the measured bottom hole pressure experienced a “hump”. The implied level of water in the tubing is approximately 7600’ above the gauge. By my calculations, the pressure in the gas zone and the pressure in the tubing then exceeds the pressure in the water zone and cross flow begins. Over the next 62 hours, the fluid level rapidly falls until it passes the pressure gauges at approximately 63 hours. Now, with the gauge above the fluid level, the pressure rapidly climbs as the fluid level is displaced below the gauge and out the perforations. The final measured pressure is approximately 10 psi higher than the pre-test level. This indicates to me a limited water zone, minimal depletion of the gas zone and the presence of a lighter fluid in the perforation area prior to the test. I have attached a wellbore diagram, which details the gradient calculations between the pressure gauge, perforations and various datums.
12 Miscellaneous Plots - I have attached several detailed plots that my be useful for discussion purposes. The Log-Log plot with the derivative is considered the industry standard for diagnostic purposes. I have included numerous annotations to this plot to show my interpretation of the various anomalies. Several other detailed plots are attached for your information and use.
In summary, this well has all the makings of a great well but a sustained production period will be required to accurately quantify the reserves. The flow rate of 13 MMCFD barely stressed the reservoir. What little pressure drop did exist, was near the wellbore. The deliverability of this well will be limited by the tubulars far more than by the reservoir.
Petrel Robertson Consulting Ltd. - Summary
(This report was completed prior to the flow and pressure build-up testing and, therefore, utilizes none of that data. Estimations are based solely on the electric logs. – Hilton Petroleum Ltd.)
Conclusion:
Based on the logs (18,280-19,716 ft.) of the Temblor formation, estimated gas-in-place potential is 363 billion cubic feet. This estimate assumes 171.5 vertical feet of net pay, a homogeneous and isotropic reservoir with a surface area of 640 acres, and infinite permeability. Recoverable gas will be significantly less and will be governed by factors such as:
The true surface area of the area under structural closure
Actual permeability of the reservoir
Any lateral or vertical variations in gas-charged intervals
True reservoir pressure
True grain densities of reservoir sandstone
(4)
Adams Pearson Associates Inc. – Summary
Conclusion:
Analysis of flow and build-up tests conducted on the Berkley #1 suggests that there is still considerable uncertainty with respect to the interpretation of well behavior. The well is draining at least 80 BCF and probably in excess of 250 BCF. Based on a cumulative production of around 74 MMcfd during the test, this implies a connected initial gas-in-place (IGIP) of around 250 Bscf. It is
quite possible that the connected volume is greater than 250 Bscf, but further testing and pressure data is needed to quantify the upside.
The complex geology of the field in conjunction with observed behavior of pressure derivative results suggests five possible models. Of these five models, Cases 4 and 5 are the most likely
Homogeneous system between two parallel barriers with changing wellbore storage.
A close system with two parallel barriers near the well and two additional distant barriers.
For the most likely scenario (Case 4), the apparent pressure decline appears to be 12 psi or 0.07% from initial pressure. Based on a cumulative production of around 74 MMscf during the test, this implies a connected initial-gas-in-place (IGIP) of around 250 Bscf. However, it should be noted that with the cumulative test production totaling only 0.03% of this estimate of the connected gas volume, the certainty that these estimates are representative of the total connected IGIP is quite low. It is quite possible that the connected volume of greater than 250 Bscf, but further testing and pressure data is needed to quantify the upside.
Analysis of wellbore dynamics resulted in the observation of several interesting phenomena. The temperature gradient data indicates that the location of the initial gas source was estimated to be around 19,700 ft. and the main gas source appears to be around 19,900 ft. Using a similar temperature gradient methodology to locate the water source, calculations suggest the water source is from around 20,300 ft. This suggests that the reservoir continues below that depth of penetration (19,700). The tests indicate that the most highly porous zone toward the top of the perforated zone (19545) is making very little contribution to the total flow and pressure behavior of this well. Calculations confirm that the most permeable pay section that is controlling the reservoir pressure is in the lower half of the perforated interval and much of the production likely comes from a partially penetrated reservoir extending below the total depth of this well. |
