Review of Geology and Original Oil In Place of Two Pools, Coalinga Oil Field

Transcription

1 Review of Geology and Original Oil In Place of Two Pools, Coalinga Oil Field For First Oil & Gas Company Randall T. Metz, P.G. Pacific Geotechnical Associates, Inc. June 2, 2011

2 Review of Geology and Original Oil In Place of Two Pools, Coalinga Oil Field Randall T. Metz, P.G. Pacific Geotechnical Associates, Inc. June 2, 2011 Summary Introduction The study area consists of two pools on the southwestern edge of the Coalinga Oil Field, Fresno County, California. The eastern pool produces from the Temblor sand of the Vaqueros formation. The Temblor consists of the 1st, 2nd and 3rd Temblor sands. The 1st Temblor onlaps onto the second and pinches out to the south. The average depth of the reservoir is 1500 feet. Average produced oil gravity is 14 degrees API. The downdip reservoir limit is the oil/water contact located somewhere on Section 6. The updip limit of the Temblor pool is a sand pinchout to the west. As there are no wells immediately west of the producing trend the exact position of the pinchout cannot be defined with certainty. The western pool produces from the Domengene formation. The average depth of the reservoir is 250 feet. Average produced oil gravity is 16 degrees API. The downdip reservoir limit is the oil/water contact located at approximately Sea Level minue 825 feet. The updip limit of the Domengene pool is a sand pinchout to the west. As there are few wells immediately west of the producing trend the exact position of the pinchout cannot be defined with certainty in the southwest. Conclusions 1. Assuming the Temblor pool consists only of the area currently under development the Original Oil In Place (OOIP) under First Oil & Gas property is estimated to be: Temblor Porosity Oil Saturation Net Pay Area OOIP Avg. Avg. Initial Avg. Ft. Acres Bbls 1 st Temblor 33.8% 50% ,000 2 nd Temblor 33.8% 50% ,121,000 3 rd Temblor 33.9% 50% ,000 Total ,316, The western pool produces form the Domengene sand of the Kreyenhagen formation. The updip limit of the Temblor pool is a sand pinchout to the west. As there are no wells immediately west of the producing trend the exact position of the pinchout cannot be defined with certainty. Porosity Oil Saturation Net Pay Area OOIP Avg. Avg. Initial Avg. Ft. Acres Bbls Domengene 31.8% 50% ,287,000

3 3. Additional potential lies to the south in both pools and to the north in the western (Domengene) pool. 4. Almost all of the available data consisted of drillers logs from the early to mid-1900 s. Additional data such as modern logs and cores from new wells would enhance the reliability of this report. 5. The economic success of any new wells will require drilling techniques or enhanced recovery techniques. Additional Comments 6. The locations and elevations of many of the wells are in question. Well locations in histories often do not match the locations reported by the Division of Oil Gas and Geothermal Resources. An engineering survey of well locations for key wells is highly recommended. The accuracy of this report is dependent on accurate well locations. 7. While this is not an engineering study, history has shown that these wells will produce only small amounts without some sort of enhanced recovery. Horizontal drilling will probably not be the solution in itself. Some mechanism to move the oil into the well bore must be employed. An evaluation of the possible effectiveness of a steam or water drive should be undertaken. 8. Historic production appears to be unreliable due to the lack of data, the way it is reported and past disagreements about lease ownership. 9. Heavy oil shows and gas are reported in the Jacalitos formation along with some gassy zones. Because of their inconsistent nature and poor data quality no attempt was made to quantify possible reserves. TDT logs which may be able to identify gas zones were run in two existing wells, but the logs were not immediately available. History and Scope One of the oldest oil fields in California, the earliest well of record Lawless #4 was drilled in The study area lies in Sections 1 and 2, T.21S. R.14E., the south halves of sections 35 and 36 T.20S. R.14E. and the west half of Section 6, T.21S. R.15E. MDBM. Several of the wells drilled in the study area were drilled in the early 1900 s with almost all of the wells drilled before The early history of the Coalinga Oil field is described by E. J. Kaplow (1945) in the Summary of Operations California Oil Fields, Vol. 11, No. 2, pp (See Location Map 1). A total of approximately 110 wells in the study wells were reviewed for this study. Of these only twenty have open hole wireline logs. The rest have drillers logs or no geological data whatsoever. Of the total 25 are producing, 20 are suspended, 22 are former producers that have been abandoned, 13 were wells drill and abandoned, and the remainder are other types of well or status unknown. Nearly all of the dry holes had oil or gas shows. The most recent well drilled and completed was First Oil & Gas Company Mirada 1 10 which was completed in June, 1984, for a Pacific Geotechnical Associates, Inc. Page 3

4 reported one half barrels of oil and 20 barrels of water per day. This well has a cumulative production of 326 barrels of oil and 1,435 barrels of water. This well is currently on production and is making a reported one barrel of oil and one barrel of water per day. Digital well location and oil, water and gas production data were acquired from the California Division of Oil, Gas and Geothermal Resources records (DOGGR). Electric logs were scanned from paper copies obtained from the DOGGR. Log header information (DF elevation, total depth (TD), selected spud dates) were derived from log headers, histories, or back calculated based upon annotations on the electric log. Geologic tops were adopted from Kaplow s (1945) report. Completion annotations and core data are from scanned histories and logs. Two of the wells had core analyses, and the majority of the remaining had lithologic descriptions of some kind. The core and wireline log data were used to determine reservoir characteristics. Stratigraphy The stratigraphic horizons correlated for this study are: Recent......Alluvium Pliocene.... Jacalitos Etchegoin Pliocene.... Jacalitos Tar Base of sandy interval with tar and showing of oil, often with gas /\/\/\/\/\/\/\/\/ Unconformity Miocene....McLure Shale Blue clay, hard, often with shell fragments Miocene....Temblor Formation 1 st Temblor Sand Producing sand in eastern pool 2 nd Temblor Sand Producing sand in eastern pool 3 rd Temblor Sand Producing sand in eastern pool /\/\/\/\/\/\/\/\/ Unconformity Eocene......Kreyenhagen Dark brown or black shale, hard, often with shell fragments Eocene......Domengene Producing sand in western pool /\/\/\/\/\/\/\/\/ Unconformity Cretaceous Undifferentiated Sand and Shale A regional Pliocene unconformity at the base of the Jacalitos formation has a relief that deepens to the east and truncates nearly all of the stratigraphic units which dip to the east (see Cross Section A A ). Immediately above or near to the unconformity is reported heavy oil and gas shows in the Jacalitos formation. Pacific Geotechnical Associates, Inc. Page 4

5 The McLure Shale forms the trapping caprock for the Temblor sands and the Kreyenhagen Shale forms the caprock for the Domengene. Structure Map 2 displays structure maps on the top of the Temblor (easterly contours) and the top of the Domengene (westerly contours). This Temblor sand dips approximately twenty one degrees to the east and increases in dip to the east. The sinuous nature of the Sea Level +900 feet contour suggests wells are mis located or well elevations are incorrect. A review of the meets and bounds locations reported on well histories shows a consistent disagreement with Latitude/Longitude locations published by the DOGGR by more than 200 feet. Cross Sections Two west to east dip structure sections (B B and C C ), two north to south (1 1 and 2 2 ) structure sections and one north south correlation with a datum of the Top McLure Shale (1c 1c ) are presented in this report as Plates II through VI respectively. All cross sections show correlations of major stratigraphic markers developed for this report. Map 3 is a cross section index map. Net Pay Definitions A combination of resistivity cutoff and SP deflection were used to determine net pay. Three core samples were analyzed in the Temblor zone and five in the Domengene. The average porosities reported for these samples were used to refine values that are given as ranges in DOGGR (1998) California Oil & Gas Fields, CD 1, pg 97. Net sand was counted as those depths with a negative SP deflection using the one third of maximum deflection rule. Thin intervals were not counted as sand when the SP displayed a positive inflection which was interpreted to be non sand. Net pay was determined by using a nine ohmm deep resistivity cutoff in the Temblor and an eighteen ohm cutoff in the Domengene. The top of pay for each well was set where the deep resistivity curve first exceeded nine or eighteen ohmm. The deep resistivity curve reads lower than the true resistivity in the top half of thick beds on the old electric logs. These lower values were corrected by visual inspection as the net pay was counted. The base of pay was set where the deep resistivity curve last went below the ohm cutoff. Net Pay Isopach Pacific Geotechnical Associates, Inc. Page 5

6 Map 4, 5 and 6 are Net Pay Isopach maps of the 1st, 2nd and 3rd Temblor sands. They represent the completed pay and potential pay zones from the resistivity, SP, and core examination. The sums are posted in green to the right of the well spots. The downdip limit was set by the oil/water contact and the updip limit by the sand pinchout line. The 1st Temblor sand pinches out to the south and west. Map 7 is the Net Pay Isopach map of the Domengene sand. It also represents the completed pay and potential pay zones from the resistivity, SP, and core examination. The sums are posted in green to the right of the well spots. The downdip limit was set by the oil/water contact and the updip limit by the sand pinchout line. Volumetrics The Net Pay grid was input into the volumetric calculation. The resulting calculations are based on averages of petrophysical parameters as described above. Only volumes within the grid are calculated. In other words only volumes within the developed area are counted. In addition, no volumes beneath Section 6 and Section 36 are included as they are non First Oil & Gas Company leases. The following are the resulting volumetric calculations exported from the Petra interpretation software: Assuming the Temblor pool consists only of the area currently under development the Original Oil In Place (OOIP) under First Oil & Gas property is estimated to be: Temblor Porosity Oil Saturation Net Pay Area OOIP Avg. Avg. Initial Avg. Ft. Acres Bbls 1 st Temblor 33.8% 50% ,000 2 nd Temblor 33.8% 50% ,121,000 3 rd Temblor 33.9% 50% ,000 Total ,316, The western pool produces form the Domengene sand of the Kreyenhagen formation. The updip limit of the Temblor pool is a sand pinchout to the west. As there are no wells immediately west of the producing trend, the exact position of the pinchout cannot be defined with certainty. Porosity Oil Saturation Net Pay Area OOIP Avg. Avg. Initial Avg. Ft. Acres Bbls Domengene 31.8% 50% ,287,000 Production Definitions: Area = Volumetric Polygon Areas, First Oil & Gas Company Lease OOIP = Volume * Por * (1-Sw) / FVF Pacific Geotechnical Associates, Inc. Page 6

7 Historical production and injection data for the First Oil and Gas Company study area wells were obtained from the DOGGR District 5 office and imported into Petra. Figure 1 (Monthly Production Graph) shows the monthly production values for all wells combined. The DOGGR reports nine active wells and 28 idle wells in March of this year. Of these the best producer is Well 1 4 which made 20 barrels of 13.5 API oil and 20 barrels of water that month. Of the remaining four produced one barrels of oil per day and three reported no oil production in March. Cumulative production since 1977 has been almost 52,257 barrels of oil and 99,558 barrels of water. The oil recovery factor of the oil produced since 1977 represents less than one percent of the original oil in place. A review of the well histories suggests that early production figures may not be accurate and at best are incomplete. Several of the wells have no records on file, and a lease dispute where more than one operator claimed the same wells makes production figures doubtful. Current production numbers are suspect because several of the wells report one barrel of oil per month for many months, and in some case years, in a row. The wells which do report initial production and 30 day production in the history show a very rapid decline in that period of time and a rate of one or two barrels per day typical after 30 days. Considering the above, it is estimated that less than ten percent of the original oil in place has been recovered to date. Additional Drilling In the eastern pool the well spacing is approximately 1.1 acre to four acre spacing. Most of the wells reported some gas during drilling, but 14 API gravity of the oil is relatively low. Assuming the gas was associated with the oil, the pressure has been blown down for many years. Unless some other form of motivation which moves the oil into the well bore such as steaming or pressure drive is applied, a new well would not be expected to producer at a higher rate than the best existing well. The best existing well is Well 1 1 which is currently producing one barrel of oil per day and has made less than five thousand barrels of oil since The condition of the western pool is similar to the eastern pool however well spacing is much more dense. The best existing well is 1-5 which is currently producing less than one barrel per day and has produced only 3,510 barrels of oil since Drilling Recommendations Pacific Geotechnical Associates, Inc. Page 7

8 Before any drilling is contemplated: 1. An engineering survey of well locations and elevations should be undertaken to confirm or improve historical data. 2. Samples of produced oil should be sent to a laboratory and measured for viscosity under different temperatures. This test will indicate whether steaming might be effective or not. 3. A reservoir development plan should be assembled that incorporates existing wells and possible new producers and/or injection wells. Possible Well Locations In the eastern pool a well located 370 feet due west of Well 1 1 would have the following characteristics: 1. Updip of and adjacent to best producer in the pool. 2. In a location that is productive in the 1st, 2nd and 3rd Temblor sands. 3. In a location has is expected to have approximately 30 feet of total net pay. It is shown as Location 1 11 on Map 1. This well should be drilled to a true vertical depth of 1600 feet to test the 1 st, 2 nd and 3 rd Temblor sands. In the western pool a well located 220 feet due west of Well 1 20 would have the following characteristics: 1. Centrally located in the producing part of the pool 2. In a location has is expected to have more than forty feet of total net pay. It is shown as Location 20 on Map 1. This well should be drilled to a true vertical depth of 450 feet to test the Domengene. Closing This report has been prepared using information from various sources and has also relied, in part, on the professional judgment of the preparer. The preparer does not warrant the accuracy of the results or predictions contained herein. Pacific Geotechnical Associates, Inc. Page 8