Exhibit 10.68
January 13, 1995
Chaparral Resources, Inc.
621 Seventeenth Street, Suite 1301
Denver, Colorado 80293
Attention: Paul V. Hoovler
Gentlemen:
At your request, Ryder Scott Company Petroleum Engineers (Ryder Scott) has
reviewed the reserve estimates prepared by P & M Petroleum Management (P & M) of
the Karakuduk Field located in The Republic of Kazakhstan. The summary table
below presents a comparison of the estimated recoverable reserves as prepared by
P & M with Ryder Scott's estimates.
Comparison
Estimated Gross Undeveloped Reserves
Attributable to the Karakuduk Field
P & M Ryder Scott
Formation (Thousand bbls) (Thousand bbls)
-----------------------------------
Proved
J1 Lower 64,207 61,786
J2 357 257
J4 521 500
J5 1,639 1,199
J8 7,360 9,198
J9 881 950
------ ------
Total 74,965 73,890
Chaparral Resources, Inc.
January 13, 1995
Page 2
P & M Ryder Scott
Formation (Thousand bbls) (Thousand bbls)
---------------------------------
Probable
---------------------------------
J1 Lower 32,104 (1) 30,893 (1)
J1 Upper 2,893 2,777
J2 3,668 3,606
J3 7,526 7,225
J4 4,729 4,540
J8 3,680 (1) 4,599 (1)
----- ------
Total 54,600 53,640
(1) Pressure Maintenance - Water injection reserves
Review Procedure and Opinion
- ----------------------------
In performing our review, we have relied on the data furnished by P & M and
Chaparral Resources, Inc. These data were accepted as authentic and sufficient
for determining the reserves.
In our opinion, P & M's estimates of future proved undeveloped reserves
were prepared in accordance with generally accepted procedures for the
estimation of future reserves, and we found no bias in the utilization and
analysis of the data in estimates of reserves for the properties.
In general, Ryder Scott was in agreement with the use of the data that was
available. The isopach maps of net pay reflect a reasonable and consistent use
of the available data. In certain reservoirs where test data was limited, the
assignment of proved reserves for limited areas of the reservoir was reasonable
and appropriate.
Porosity values utilized for making the estimate of original oil in place
were based on available core data and the average values selected by P & M are
very reasonable, based on data which was available for our review.
Water saturation, the other key parameter in volumetric calculations, was
more difficult to estimate. Because of the uncalibrated nature of resistivity
logs and the lack of porosity logs, water saturation values could not be
calculated. A large number of successful well tests have been conducted in the
various members of the Jurassic formation. These tests have indicated limited
water production and based on the overall results of these tests, P & M assigned
an average water saturation of 35 percent. Empirical correlations available in
the literature which relates porosity, permeability and water saturation
indicate that 35 percent assigned by P & M is reasonable and possibly high.
Chaparral Resources, Inc.
January 13, 1995
Page 3
P & M utilized the results of a laboratory PVT analysis of a bottom hole
sample for fluid properties for the J1 through the J5 members of the Jurassic.
Test data indicated higher GOR performances from the J8 and J9 reservoirs. P & M
utilized Standing correlations for developing fluid properties for these members
of the Jurassic. Checking the results of the PVT analysis with available
correlations, Ryder Scott accepted the fluid properties utilized by P & M as
reasonable.
In summary, it is Ryder Scott's opinion that the estimates of original oil
in place prepared by P & M are reasonable. In some instances minor adjustments
were made to the P & M estimates due to small differences in the pay counts.
For assignment of primary reserves, P & M utilized a recovery efficiency of
20 percent. In addition, they assigned an additional 10 percent incremental
probable reserves for pressure maintenance water injection in the J1 Lower and
J8 reservoirs. Ryder Scott utilized the API correlation for recovery in solution
gas drive reservoirs to estimate a recovery efficiency of 19.2 percent for the
J1 through J5 members and 25.2 percent for the J8 and J9. It was our opinion
that the secondary to primary ratio of .5 utilized by P & M to assign pressure
maintenance water injection reserves was reasonable and utilized this same ratio
in assigning incremental probable reserves to the J1 Lower and J8.
Reserves Estimate
- -----------------
The original reserve estimates were based on a volumetric analysis and
assignment of recover factors for primary and incremental pressure maintenance
reserves.
The reserves presented herein, as estimated by P & m and reviewed by Ryder
Scott, are estimates only and should not be construed as being exact quantities.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.
The proved and probable reserves, which are attributable to the wells and
locations reviewed by Ryder Scott, conform to the definitions approved by the
Society of Petroleum Engineers and The Society of Petroleum Evaluation
Engineers, except that no economic evaluations have been performed by either P &
M or Ryder Scott at this time. It is assumed, based on current development
activity in Kazakhstan, that economic development of these reserves can be
achieved. Our definitions of proved and probable reserves follows.
Proved reserves of crude oil, natural gas, or natural gas liquids are
estimated quantities that geological and engineering data demonstrate with
reasonable certainty to be recoverable in the future from known reservoirs.
Reservoirs are considered probed if economic productibility is supported by
actual production or formation tests. In certain instances, proved reserves may
be assigned on the basis of a combination of core analysis and electrical and
Chaparral Resources, Inc.
January 13, 1995
Page 4
other type logs which indicate the reservoirs are analogous to reservoirs in the
same field which are producing or have demonstrated the ability to produce on a
formation test. The area of a reservoir considered proved includes (1) that
portion delineated by drilling and defined by fluids contacts, if any, and (2)
the adjoining portions not yet drilled that can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of data on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Proved reserves are estimates of hydrocarbons to be recovered from a given date
forward. They may be revised as hydrocarbons are produced and additional data
become available.
Reserves that can be produced economically through the application of
established improved recovery techniques are included in the proved
classification when these qualifications are met: (1) successful testing by a
pilot project or the operation of an installed program in the reservoir, or one
in the immediate area with similar rock and fluid properties, provides support
for the engineering analysis on which the project or program was based, and (2)
it is reasonably certain the project will proceed. Reserves to be recovered by
improved recovery techniques that have yet to be established through repeated
economically successful applications are included in the proved category only
after successful testing by a pilot project or after the operation of an
installed program in the reservoir provides support for the engineering analysis
on which the project or program was based. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or
natural gas liquids being held in underground or surface storage.
Probable reserves are the estimated quantities of recoverable hydrocarbons
which are based on engineering and geological data similar to those used in the
estimates of proved reserves but, for various reasons, these data lack the
certainty required to classify the reserves as proved. Probable reserves
include, without limitation: (a) reserves that apparently exist a reasonable
distance beyond the proved limits of productive reservoirs where water contacts
have not been determined and proved limits are established by the lowest datum
at which proved reserves exist; (b) reserves in formations that appear to be
productive from log characteristics only, but lack definitive tests or core
analysis data; (c) reserves in a portion of a formation that has been proved
productive in other areas in a field but is separated from the proved area by
sealing faults, provided that the geologic interpretation indicates the probable
area is structurally high relative to the proved portion of the formation; (d)
Chaparral Resources, Inc.
January 13, 1995
Page 5
reserves obtainable by improved recovery where an improved recovery program,
that has yet to be established through repeated economically successful
operations, is planned but is not yet in operation and a successful pilot test
has not been performed, but reservoir and formation characteristics appear
favorable for its success; and (e) reserves in the same reservoir as proved
reserves that would be recoverable if a more efficient primary recovery
mechanism develops than was assumed in estimating the proved reserves.
General
- -------
Neither Ryder Scott not any of its employees has any interest in the
subject properties and neither the employment to do this work nor the
compensation is contingent on our estimates of reserves for the properties which
were reviewed.
This report was prepared for the exclusive use of Chaparral Resources, Inc.
The work papers used in the preparation of this report are available for
examination by Authorized parties in our office. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Larry T. Nelms
Group Vice President
December 8, 1994
Mr. Paul V. Hoovler, President
Chaparral Resources, Inc.
621 17th Street, Suite 1301
Denver, CO 80293
Dear Mr. Hoovler:
As per your request, I am enclosing a copy of my engineering report of the
estimated recoverable oil reserves for the Karakuduk Field located in the
western portion of the Republic of Kazakhstan. These reserves, from the Jurassic
formation, have been determined using generally accepted petroleum engineering
practices. The geologic and engineering data for the most part was supplied by
the Mangistau Regional Geologic Section. This entity would be comparable to the
Oil and Gas Commission for the state of Colorado.
The oil reserves are defined in two categories, (1) Proved Undeveloped Reserves,
and (2) Probable Reserves. The two classifications are described below as
general definitions adopted by The Society of Petroleum Evaluation Engineers:
Proved Undeveloped Reserves: Oil reserves in which the proven commercial
producibility is supported by a number of wells that have been drilled and from
which actual oil production or positive formation tests were achieved. The area
of the reservoir considered as proved has been delineated from information
obtained by drilling and the determination of oil/water contacts defining the
parameters of the reservoir are reasonably judged as being commercially
productive on the basis of available geologic and engineering information
derived from the existing wells. The reserves are classified as proved
undeveloped in the areas where interpretation of data from the tested wells is
laterally continuous and the formations contain commercially recoverable oil
reserves on locations beyond the direct offsets to the existing wells.
Probable Reserves: Oil reserves that are less certain than proved reserves
but can be estimated to exist with a degree of certainty. Such reserves
based on the available geologic and engineering data in the probable
productive area indicate that such reserves may be recovered. This includes
oil or gas reserves from formations that appear to be productive by log
characteristics, but lack definite core data, drillstem test data or
production testing. This category also includes oil reserves that may be
recoverable through enhanced recovery methods. As an example, a limited
project or pilot program for secondary and/or tertiary recovery that is
planned but has not been implemented or placed into operation but the
reservoir characteristics appear favorable for such adaptation leading to
commercial production.
Mr. Paul V. Hoovler
Chaparral Resources, Inc.
December 8, 1994
Page Two of Two
The Karakuduk Field, located in the Mangistau Region of western Kazakhstan,
appears to be a very good candidate for an extensive development drilling
program. Most of the wells that have been previously drilled were production
tested through casing or formation tested. The clastic sandstones within the
Jurassic formation should be receptive to stimulation by acidizing or fracture
treatment. Daily production rates from this development program should be
significantly increased by such stimulation. This should also increase
recoverable oil reserves. As development drilling takes place, additional
reservoir data will increase or decrease the estimated ultimate recoverable
reserves from these multiple sand reservoir within the Jurassic formation.
As an aside and beyond the scope of this study, the Karakuduk #20 well, drilled
into the next lower formation, although not tested, appears to have very thick
productive porosity zone within the Triassic section. Other fields within the
general area proven this formation productive and if exploration within the
Karakuduk Field finds these same reservoir characteristics, it should add
substantially to future recoverable reserves.
In summary, I believe the Karakuduk Field offers an excellent opportunity for a
small independent oil company to drill and develop significant low risk oil
reserves. I don't know of any other province in North American that this type of
opportunity exists. Topographic conditions are very favorable for development
and the field is located within twenty miles of a major pipeline that has
deliveries to the Black Sea ports. Access to local roads and the major railroad
in this part of Kazakhstan all lie within thirty miles.
I also believe that as the development project gets underway, there will be
substantial improvements over the drilling operations, completions and
production methods previously utilized. This should significantly enhance daily
oil flows and ultimate reserves.
The reserve report has not taken into consideration any cash flow forecasts or
time schedules as to the development of the project. I am not privy to the
parameters of the Agreement between Chaparral Resources, Inc. and the Karakuduk
Munay Joint Stock Company, nor am I aware of any agreements that could affect
Chaparral's ultimate reserves in this field. This study simply defines the
recoverable reserves for the field.
Best regards,
Robert W. Peterson
KARAKUDUK OIL FIELD
ESTIMATED OIL RESERVES
PREPARED FOR
CHAPARRAL RESOURCES, INC.
P&M PETROLEUM MANAGEMENT
DECEMBER, 1994
KARAKUDUK OIL FIELD
ESTIMATED OIL RESERVES
The Karakuduk Oil Field is located in the Republic of Kazakhstan, 227 miles
northeast of the city of Aktau. The oil reservoir was originally drilled because
seismic data showed a geological subsurface structure at this location. The
first well was drilled in 1972 and found oil production in the Jurassic Age
formations.
A total of 22 wells have been drilled on this geological structure by the
Russians. Ten of these wells encountered oil sands. Some of the wells were drill
stem tested and other wells were production tested. The first well was drilled
1972 and the last four wells were drilled since 1991. The Kazkhstans did not
furnish us with any data showing which wells had casing run in them and which
wells they thought the casing would be satisfactory to place the wells on
production. The wells reportedly were plugged by placing cement plugs inside the
casing. The Turkish Petoil personnel stated that the #20 and #21 Karakuduk wells
ere the only wells that had casing that could be re-entered for sure. Five other
wells could possibly be re-entered.
The Jurassic formation is approximately 2300' thick and has been divided into 15
porous sand sections divided by continuous shale beds.
The producing sands are described generally as fine to medium grained sandstone
and coarse grained siltstone. The porosities from core analysis average 15
percent. In some of the reserves, the Russians used up to 17 percent porosity
and the Petoil personnel prefer this figure. The Jurassic sand sections are
identified as J1, J2, J3, etc. Listed below is a brief description of the oil
potential of each sand.
J1: This sand section consist of two sand beds that I have identified as the J1
upper and the J1 lower. These two sand beds are continuous over the structure
and the J1 lower has been tested in 14 wells. The sands are very easy to
identify on the open hole logs. And oil-water contact has not been definitely
established. Some production and drill stem tests in J1 have recovered only a
small amount of water of no fluid recovery could be from formation damage.
According to the information we received from geologist and engineers in Turkey
with Petoil and a very competent consultant who has thoroughly studied this oil
reservoir, the Russians used no drilling solids, mud weight, water loss, or
formation damage. The mud weight was much higher than the formation pressure
when the sand beds were drilled so you would expect high damage. The intervals
tested by perforating were not stimulated in any way to the best of our
knowledge.
The J1 upper sand averages about 6 feet thick and J1 lower sand averages about
35 feet thick. The J1 upper sand has not been production tested adequately by
itself to determine whether it is definitely oil productive or not. The J1 lower
sand has produced oil over 100 bbls/day in nine wells and possibly ten (well
#22). We don't have the production rate form Karakuduk #22 but the Petoil people
indicated it produced over 100 bbls/day from the lower J1 sand. I have given the
J1 lower sand 517,800 acre feet of reservoir and 64,207,000 barrels of proved
undeveloped reserves. By pressure maintenance from water injection they should
recover at least and additional 32,104,000 barrels of probable reserves.
I have reduced the areal extent of the J1 upper sand and have calculated a
reservoir volume of 23,332 acre feet for it and assigned it 2,893,000 barrels of
probable reserves. The J1 upper sand and the J1 lower sand are separated by a
consistent shale bed about 16 feet thick.
J2: The J2 section consists of three sand. Oil production has been tested in
wells #4, #7, and #10 in the J2 sands. The production rate from the #10 well was
385 barrels of oil and 533 mcf of gas. This reservoir has oil-water contact at
- -8074 feet. I have isopached this J2 oil sand and calculated an oil reservoir of
32,456 acre feet and proved undeveloped reserves of 357,000 barrels and
2,893,000 barrels probable reserves due to the thin sand thickness in the rest
of the wells. A small amount of oil was also tested from the #4 well but the
sand is lower structurally from the main reservoir and is located over one mile
west of the main reservoirs.
J3: The J3 section consists of two sand beds. The #7 wsell tested 20 bbls/day of
oil from 36 feet of perforations. This sand section has an oil-water contact at
- -8321'. The sands cover an area of 5,043 acres and the oil reservoir is 60,693
acre feet with oil reserves of 7,526.000 barrels. These oil reserves are
classified as probable reserves since only one well has been production tested
but it was determined to be uneconomical.
J4: The J4 sand beds flowed 288 barrels of oil and 498 mcf/day gas in the #7
well. The #20 and the #21 wells also have porpous sands above the oil-water
contact of -8465' datum. The oil reservoir has a volume of 42,336 acre feet. I
have assigned 524,000 barrels of proved undeveloped reserves for well #7. I have
also assigned 4,729,000 barrels of probable reserves because well #7 is the only
well that tested oil flow rates at near commercial rates.
J5: The #7 well was perforated 9124-9140' and recovered oil and was perforated
9140-9157' and recovered oil and water with no fluid recovery amounts recorded.
The feasibility study shows only one fluid recovery at 936 bbls/day oil and 971
mch/day gas but it does not name the well. Presumably the oil production is from
the upper perforations of the #7 well at 9124-9140'. They also list an oil-water
contact of -8513' which matches the #7 log. To complicate the information the
#21 well tested 900 bbls/day oil and 971 mcf/day gas from perforations
9153-9249' and the lower perforations are at -8663' datum which is 150' below
the previous stated oil-water contact without recovering any water.
Based on 120 acre spacing, I have given wells #7, #20, and #21 1,639,000 barrels
of primary proved undeveloped reserves. Since it is difficult to understand what
is going on in this reservoir I haven't assigned any other reserves although it
is very possible there are some in the structurally lower parts of the J5 sand
reservoir.
J6: No reserves.
J7: No reserves.
J8: The J8 sand section is a thick sand with up to 66' of porous sand in well #7
and 63" in well #21. The isopack of the J8 sand calculates 72,867 acre feet of
volume and 7,360,000 barrels of proved undeveloped reserves for the J8 sand and
3,680,000 barrels of probable reserves for pressure maintenance by water
injection.
J9: The #21 is the only well that has penetrated this interval that has
recovered oil production. Although Petoil personnel say oil was recovered in the
#22 well the records we received don't verify this. The #21 was perforated
9918-9947' and recovered oil at the rate of 562 bbls/day and gas at the rate of
837 mcf/day. The interval 9839-9904' was also perforated and tested 543 bbls/day
oil and 684 mcf/day gas. The proved undeveloped reserves calculated to this well
based on 120 acre spacing are 881,000 barrels.
The total reserves calculated for this field are 74,965,000 barrels of proven
undeveloped reserves and 54,600,000 barrels of probable reserves for a total of
129,565,000 barrels.
The size of the reservoir is easily determined for the J1 sands since they are
uniform in thickness in all the wells that penetrated it. Due to the poor
logging tools and capabilities of the Russian logging equipment and the lack of
information supplied with the open hole logs it is impossible to calculate the
porosity or water saturations from logs. The information that was valuable were
the well test listed on Table I. The limited core data was also helpful.
The oil reserves assigned in this report were calculated using data supplied by
the Russian and Kazakhstan government personnel. The reservoir data supplied
ranged from poor to good. The poor data in general were from the open hole
Russian logs and the good data from the wells tests. In general I thought the
data was better than normal in attempting to determine the feasibility of
developing a field of this size and complexity due to the multitude of producing
sands.
The Russian open hole logs are poor for quantitative data for determining
porosity, water saturation, and shaliness of the producing wells. The Russian
logs don't have any calibration data or drilling mud or filtrate data. The only
open hole porosity logs are the micro-log and single detector neutron logs which
neither are good for porosity calculations. The micro-log is good for permeable
sand thickness determinations. The resistivity logs are lateral type logs which
aren't good for thin bed water saturations and without mud filtrate and
calibration data are not good for calculating reservoir water saturations. The
gamma ray logs were not calibrated in standard API counts so they have limited
use for reservoir shaliness. The reproduction of some of the open hole logs was
so poor they were not legible so that further detracted from their usefulness.
The Russians did run some DST's and cased hole tests of perforated sands which
were very useful. Also a lot of cores were taken and were analyzed in a
laboratory. Some of this data was available.
The cores data showed an average sand porosity of 15.1 percent for the J1 lower
sand so I used 15 percent although Karakuduk Oil Field Production Feasibility
used 15,16, and 17 percent porosities in their studies.
I used a water saturation of 35 percent in the reserve calculations. I though
that 35 percent water saturation was near the upper limit of saturation that
could be in place without producing free water from the higher permeability
zones flowing oil at high rates. The water saturations could be considerably
lower, also, so I though this was a good conservative compromise. The
Kazakhstan's did use water saturations from 45 to 50 percent in their study. The
formation volume factor of 1.22 was determined by the Kazakhstan laboratory in
Aktau.
I used a primary oil recovery of 20 percent for the proved undeveloped reserves
and an additional 10 percent oil recovery for pressure maintenance by water
injection for probable reserves. The Kazakhstans used an oil recovery factor of
40 percent of the original-in-place for primary recovery with water injection
for pressure maintenance. The Petoil personnel stated that a large field to the
south producing from the same Jurassic sands is going to recover 43 percent of
the oil-in-place with water injection for pressure maintenance.
I have used the data available to attempt to arrive at the best conclusion to
the oil reserves of the Karakuduk Field using accepted engineering practices.
Due to the limited amount of engineering data available, the data being
generated in a foreign country by personnel not familiar with our standards or
using our quality of equipment, and also due tot he complexity of the reservoir,
the results of this report could vary considerably from other reports or the
actual future oil recoveries.
This report has been prepared utilizing methods and procedures regularly used by
petroleum engineers to estimate oil and gas reserves for properties of this type
and character. The recovery of oil reserves and projection of producing rates
are dependent upon many variable factors. These include, among others, prudent
operation, compression of gas when needed, market demand, installation of
lifting equipment, and remedial work when required.
Reserves included in this report have been based upon the assumption that all
wells will be operated in a prudent manner by responsible parties.
The basic data used to prepare this report has been retained in our files and is
available for review by appropriate parties.
P&M PETROLEUM MANAGEMENT
-----------------------------
Robert W. Peterson
Petroleum Engineer
KARAKUDUK FIELD
WELL TESTS
GEOLOGICAL TEST INTERVAL NET PAY FLUID GAS FLOW CHOKE SIZE GOR
WELL SECTION DEPTH-FT DATUM-FT FT REC BBLS/DAY CU FT/DAY INCHES CU FT/BBL COMMENTS
- ------------------------------------------------------------------------------------------------------------------------------------
Karakuduk #1 J1 8546-8563' -(7920-7936') 16' OIL 151 -- 0.1959
Karakuduk #4 J1 8596-8612' -(8004-8020') 16' WATER 2.5 --
Karakuduk #5 J1 8543-8559' -(7921-7937') 16' OIL 19.5 706 With compressor
Karakuduk #6 J1 8550-8573' -(7943-7966') 23' OIL 236 49434 0.2756 209
Karakuduk #7 J1 8435-8471' -(7834-7870') 36' OIL 446.6 564960 0.3150 1265
Karakuduk #8 J1 8481-8994' -(7869-7882') 13' OIL 90.6 ? ?
Karakuduk #8 J1 8481-8994' -(7869-7882') 13' OIL 15.1 ? 1.0236 Natural flow
Karakuduk #10 J1 8517-8537' -(7922-7942') 20' OIL 289.4 529650 0.2756 1832 Gas out oil
Karakuduk #10 J1 8537-8553' -(7942-7958') 16' OIL 966.2 600270 0.3543 621 Gas out oil
Karakuduk #11 J1 8474-8491' -(7873-7890') 17' OIL 162.9 -- --
Karakuduk #11 J1 8474-8491' -(7873-7891') 17' OIL 2.8 1.0236 Natural flow
Karakuduk #12 J1 8458-8484' -(7856-7882') 26' OIL 132.1 ? ? Water comes
Karakuduk #12 J1 8441-8448' -(7839-7846') 7' WATER 12.6 upper zones of
Karakuduk #13 J1 8520-8533' -(7912-7925') 13' OIL 4.4 -- 1.0236
Karakuduk #20 J1 8464-8507' -(7840-7883') 43' OIL 122.6
Karakuduk #20 J1 8464-8507' -(7840-7883') 43' OIL 20.1 -- Nautral flow
Karakuduk #21 J1 8425-8458' -(7839-7872') 33' OIL 452.9 384879 0.2756 850
Karakuduk #21 J1 OIL 364.8 300135 0.1968 823
Karakuduk #22 J1 8618-8635' -(8017-8039') 17' OIL W/GAS ? ? ? Gas out oil
Karakuduk #22 J1 8618-8635' -(8017-8034') 17' OIL W/WTR ? ? ?
Karakuduk #22 J1 8543-8727' -(7942-8126') 84' OIL W/GAS ? ? ?
Karakuduk #23 J1 8514-8681' -(7928-8095') 167' WTR W/GAS ? ? ?
Karakuduk #4 J2 8737-8760' -(8145-8168') 23' OIL 7.5 ? 1.0236
Karakuduk #7 J2 8556-8760' -(7955-8159') 204' OIL 3.1 ? 1.0236
Karakuduk #10 J2 8652-8681' -(8057-8086') 29' OIL & GAS 385 533181 0.2756 1385
Karakuduk #7 J3 8865-8901' -(8264-8300') 36' OIL 20.1 1.0236
Karakuduk #21 J3 8865-8878' -(8279-8312') 33' OIL 88.1 ? ? Rowing
8901-8920' -(8321-8334') 13' OIL W/WTR 3.0 ? ?
Karakuduk #7 J4 9025-9035' -(8425-8435') 10')
9045-9068' -(8444-8467') 23') OIL 287.5 497871 0.4724 1732
Karakuduk #21 J4 8996-8029' -(8410-8443') 33' OIL W/WTR 1.6 ? ?
Karakuduk #21 J4 9071-9081' -(8485-8495') 10' OIL 1.9 ? ?
Karakuduk #21 J5 9153-9249' -(8567-8663') 96' OIL & GAS 900 971025 ? 1079
Karakuduk #21 J7 9524-9563' -(8938-8977') 39' OIL & WTR ? ? ?
Karakuduk #7 J8 9652-9731' -(9051-9130') 79' OIL 283.1 198442 0.2756 701
Karakuduk #21 J8 9665-9731' -(9079-9145') 66' OIL W/GAS 283 459030 ? 1622
Karakuduk #21 J9 9839-9905' -(9253-0319') 66' OIL W/GAS 546 688545 0.3543 1261
Karakuduk #21 66' OIL W/GAS 425 582615 0.2756 1370
Karakuduk #21 J9 9915-9947' -(9372-9361') 29' OIL W/GAS 437 730917 ? 1672
KARAKUDUK FIELD
SUMMARY OF OIL RESERVES
PRIMARY RESERVES ADD'TL PROBABLE RESERVES
---------------------- ------------------------------ TOTAL
WATER INJECT'N-PRESSURE TOTAL RESERVES
PRIMARY PROVED UNDEV MAINTENANCE PROBABLE RESERV PROVED UND
AREA VOLUME POROSITY WATER RECOV 124 BPAF PROBABLE --------------------- --------------- & PROBABLE
RESERVOIR -ACRES AC FT % SATURAT'N% FVF % OF OIP BBLS BBLS % OF OIP BBLS BBLS BBLS
- --------- ------ ------- -------- ---------- ---- ------- ------------ --------- -------- ----------- --------------- -----------
J1 Lower 15,092 517,800 15.0 35.0 1.22 20 64,207,000 10 32,104,000 32,104,000 96,311,000
J1 Upper 10,199 23,332 15.0 35.0 1.22 20 2,893,000 10 --- 2,893,000 2,893,000
J2 4,217 32,456 15.0 35.0 1.22 20 357,000 3,668,000 10 --- 3,668,000 4,025,000
J3 5,043 60,693 15.0 35.0 1.22 20 7,526,000 10 7,526,000 7,526,000
J4 2,776 42,335 15.0 35.0 1.22 20 521,000 4,729,000 10 4,729,000 5,250,000
J5 360 13,224 15.0 35.0 1.22 20 1,639,000 10 1,639,000
J8 2,851 72,867 15.0 35.0 1.22 20 7,360,000 --- 10 3,680,000 3,680,000 11,040,000
J9 120 15.0 35.0 1.22 20 661,000 --- 10 --- --- 661,000
---------- ---------- ------------ --------------- -----------
TOTAL RESERVES 74,965,000 18,816,000 35,784,000 54,600,000 129,565,000