BEFORE THE OIL AND GAS CONSERVATION COMMISSION

OF THE STATE OF COLORADO

 

IN THE MATTER OF THE INVESTIGATION TO TAKE MEASURES TO PREVENT WASTE OF OIL AND GAS IN THE RANGELY FIELD IN THE STATE OF COLORADO

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CAUSE NO. 2

 

ORDER NO. 2-13

 

REPORT OF THE COMMISSION

 

On June 20, 1952 the Commission entered its Order No. 2-8 in the above entitled matter. In said Order the Commission determined that the current flaring of approximately 20,000,000 cubic feet of residue gas daily from the Rangely Weber Reservoir constitutes waste of oil and gas, and the failure of the operators in the field to return such gas to the Weber Reservoir unreasonably reduces reservoir pressure and unreasonably diminishes the quantity of oil that might ultimately be produced. The Commission found that if the residue gas currently being flared were returned to the Weber Reservoir the ultimate recovery of oil from the Reservoir could be increased 30 to 87 million barrels of oil. Said Order, among other things, prescribed Rules 3a and 3b.  Rule 3a was a temporary measure and was designed to be effective only until Rule 3b could reasonably go into effect.

 

Rule 3a imposed a limitation on the production of gas from the Weber Reservoir, providing that the operators in the field shall not produce gas from any one well in an amount during any one month exceeding a daily average of 150,000 cubic feet, and further providing that a well may produce an amount of gas in excess of said daily average if the operator thereof returns to the formation from which produced all gas produced in excess of said daily average, or if the allowed gas production from an input well is transferred to said well in accordance with certain provisions therein set forth.

 

Rule 3b provided that on and after a date certain no gas shall be produced from the Weber Reservoir unless all gas so produced shall be returned to said reservoir. Rule 3b further provided that the provisions of Rule 3b should not apply to gas required for lease development or operations, gas used as fuel or represented by shrinkage in the gasoline plant or gas injection operations, and gas required to supply domestic or municipal needs in the immediate vicinity of the Rangely Field.

 

By Order No. 2-12, dated June 2, 1953, the presently effective date of Rule 3b is September 1, 1953 and Rule 3a is presently in effect through August 31, 1953.

 

By its Order No. 2-9, dated November 25, 1952, the Commission ordered each operator in the Rangely Weber Reservoir to file with the Commission its proposed plan of gas injection to comply with Rule 3b of Order No. 2-8.

 

Law suits to test the validity of the Commission Orders No. 2-8 and No. 2-9 were commenced, however, in the District Court in and for the City and County of Denver by the Sharples Oil Corporation and the Texas Company and the Union Pacific Railroad Company, operators in the Rangely Weber Reservoir, and the decision in these suits was not entered by the Court until June 4, 1953.

 

The Court in its decision, however, sustained the validity of Orders No. 2-8 and No. 2-9 of the Commission and dismissed in entirety the complaints filed against the Commission's Orders.

 

The Commission, commencing on May 5, 1953 and continuing from time to time until July 21, 1953, held further hearings in this matter to consider the gas injection plans to comply with Rule 3b of Order No. 2-8 filed by the various operators in the Rangely Weber Reservoir pursuant to Order No. 2-9 of the Commission and to make such further orders as may be required in the premises to put Rule 3b of Order No. 2-8 into effect as expeditiously as possible.

 

The Commission now has before it the various plans of the operators for gas injection under Rule 3b of Order 2-8. These plans have been modified from the original filings to some extent by the various operators during the course of the hearings. Certain of the operators have requested exemptions as to certain leases from the application of Rule 3b. In addition, the Phillips Petroleum Company and The Texas Company and the Union Pacific Railroad Company have suggested field-wide injection plans for the consideration of the Commission. Also, at the request of the Commission, a field-wide injection plan has been presented by Mr. J.J. Zorichak, Director of the Commission.

 

Under the gas injection plan submitted by the California Company, The California Company proposes to inject all of its residue gas in four different wells spread throughout its leases, Fee 65, Emerald 34, Fee 20, and A.C. McLaughlin 38. The injection wells have been selected in such a way as to inject the residue gas in the approximate location in which it is produced. In Fee 20 in the eastern portion of the field, The California Company proposes to inject approximately 3,000,000 cubic feet a day from the California Fee Lands located in the eastern portion of the field and also from the S.W. McLaughlin Lease.  In Fee 65, The California Company proposes to inject all the gas available for injection produced from that part of its Fee Lands located in the western end of the field, and also the Gray "A", Gray "B", Raven "A" and "B", and the Neal Leases, and it proposes to inject approximately 5,000,000 cubic feet a day. Emerald 34 well will inject all the gas available for injection produced on the Emerald Lease, approximately 7,000,000 cubic feet, and the A. O. McLaughlin 38 well will inject all the residue gas produced on the McLaughlin Lease, approximately 2,000,000 cubic feet per day.

 

The plan as submitted by The California Company states that it is the intention of the company to uniformly inject into the whole Weber productive section exposed in each injection well, and that if and when it is necessary to selectively inject within the Weber section to correct a poor distribution of injected gas, then packers will be set to accomplish the correction and achieve the desired uniform gas injection. The company is already injecting gas in Fee 65, injection having been commenced November 26, 1950.  A packer is set at 6217’ to confine the injection to the interval 6217’-6413’. This packer was set to get gas into the section below 6217’, which previously was not taking gas. The company is also injecting gas into Emerald 34, injection having been commenced November 6, 1952.  A packer setting at 5910’ is contemplated for this well for a reason similar to the reason a packer was set in Fee 65.

 

Under the gas injection plan submitted by the Stanolind Oil and Gas Company, Stanolind estimates that the daily average volume of gas available for injection from Stanolind operated leases during 1953 will be 4,415,000 cubic feet. Stanolind proposes to divide this volume, 2,360,000 cubic feet for the block of leases in the west portion of the field, and 2,055,000 cubic feet for the eastern block of leases.  For the Stanolind operated leases in the western end of the field Stanolind proposes to use the L.N. Hagood 6 well for injection. For the Stanolind leases in the eastern end of the field Stanolind proposes to use the F.V. Larson "B" 11 and the E. Rector 4 wells for injection, the injection gas to be equally divided between both wells.  As to the plan as submitted, Stanolind states that the injection well locations selected will provide maximum control of the injected gas by control of injection volumes, producing rates, and selective injection if such proves necessary.

 

Stanolind also requests exemptions as to Rule 3b of Order No. 2-8 with respect to gas available for injection produced from the following Stanolind operated leases; Chase Unit, L.N. Hagood "B", F.A. Larson, and A.C. McLaughlin "B". These leases are not connected to the gasoline plant and it has proved to be uneconomical to do so.

 

The Union Pacific Railroad Company and The Texas Company submitted their gas injection plan whereby in addition to the present injection well UP 57-21 the following wells were designated as injection wells: Carney 12-5, UP 35-32, and UP 34-31.  The Texas-Union Pacific estimates that gas volumes available for injection from their properties will approach 8,800,000 cubic feet per day and they propose to inject this volume of gas in the wells named in as near equivalent volumes as the individual well gas injection capacities permit.  They propose to inject approximately 1,500,000 cubic feet per day in UP 57-21 and between 2,500,000 and 3,000,000 cubic feet into each of the other three injection wells.

 

The Phillips Petroleum Company estimates that the volume of gas available for injection attributable to Phillips operated leases which are connected to the gasoline plant is approximately 1,000,000 cubic feet. Phillips proposes to inject this gas into Levison 16 or M.B. Larson "A" 2-26 or both if the required injection volume cannot be injected into either one of the wells at a reasonable injection pressure. Phillips proposes to inject gas in each of the wells through the entire exposed oil section of each well. In addition, Phillips has a number of leases which are scattered throughout the field which are not now connected to the gasoline plant and from which the production of gas is relatively small. Phillips requests the exemption of these leases from Rule 3b of Order No. 2-8, and these leases are as follows: M.B. Larson "A" Lease, Battery A and Battery B; M.B. Larson "D" Lease, Battery D and Battery E; Purd Lease; Newton Government Lease; and the Weyrauch Lease.

 

The Sharples Oil Corporation did not submit a plan of gas injection and requested an exemption as to all of its leases. On June 2, 1953 the Commission was notified by the Sharples Oil Corporation that it had designated its McLaughlin 5-33 well as an injection well and that the company was proceeding to inject into said well a portion of the gas produced from its wells on its A.O. McLaughlin 440 Lease in order to obtain the maximum benefit under Rule 3a of Order No. 2-8.

 

The Continental Oil Company has requested an exemption for its Rooth 1 well, the only well operated by the Continental Oil Company in the Rangely Weber Sand. During the year 1952, the Rooth 1 well produced a daily average of 56 barrels of oil and an estimated daily average of 11,000 cubic feet of gas, of which gas a minimum of one-half or 5,500 cubic feet per day was consumed for lease and camp operations in the Rangely Field. The Rooth 1 well is not connected to the gasoline plant gathering system.

 

Cobb Stringer has requested an exemption as to its Hildebrant Lease and its M.E. Hefley Lease.  In its request for the exemption it is stated that there is not produced from these leases gas sufficient for field use and that it has been necessary to purchase additional gas to supplement its gas for field use.

 

At the hearing in this matter the operators were given the opportunity of objecting to any of the gas injection plans submitted, and various objections were raised by certain of the operators to the location of injection wells proposed or to the volumes of gas to be injected. In addition, the Phillips Petroleum Company and The Texas Company and the Union Pacific Railroad Company suggested field-wide plans for consideration of the Commission.

 

Phillips submitted two alternative field-wide plans. Plan 1 designates 17 injection wells and Plan 2 designates 16 injection wells for the field as a whole. Under both plans gas roughly equivalent in volume to gas produced from a particular area would be reinjected into that area. The adoption of such a proposal would necessarily result in that one operator would be required to handle for injection, gas produced from another operator's leases.

 

The Texas-Union Pacific field-wide plan as submitted proposes that the total amount of gas available for injection in the field be distributed to the various operators in amounts proportional to their oil production, with a limitation of the amount of gas to be so distributed from any battery to twice the per-well average for the field. Such a plan definitely contemplates that one operator would be required to inject gas in his leases produced from another operator's leases.

 

During the course of the hearing in this matter on July 1, 1953, the Commission requested its Director, Mr. J.J. Zorichak, to submit a plan for field-wide gas injection. This plan was prepared by the Director and furnished to the operators prior to hearing, and the plan was presented to the Commission on July 21, 1953 when each of the operators was given an opportunity to express objections, if any, to the plan.  This plan we will refer to hereinafter as the "Zorichak Plan". The Zorichak Plan was prepared after full consideration by the Director of all the various plans submitted by the operators for gas injection and after consultation by the Director with the engineers and other representatives of the various operators in the field. Fundamentally, the Zorichak Plan is composite of all the plans submitted by the parties, adjusted sufficiently in a few instances to accomplish the results contemplated by Order No. 2-8.

 

The Zorichak Plan is based on the following: (1) each operator shall have the responsibility of returning to the Weber formation residue gas originating on his own properties; (2) the volumes shown were illustrative and were based on May 1953 gas production figures, during which month the residue gas represented approximately 65% of wet gas production; and (3) as nearly as possible injection gas was assigned to leases from which produced or in the case of smaller leases to the nearest injection well of the operator.

 

The Zorichak Plan suggests the following well locations and volumes, based on May, 1953 production figures:

 

WEST END

May 1953 Wet

Gas Production

Da. Avge. Mcf.

Residual

Gas

Mcf.

 

Injection

Volumes

MMcf/D

California

18,918

 

12,297

Fee 65

5.4

 

 

 

 

Emerald 34

4.6

 

 

 

 

McLaughlin 38

2.3

Stanolind

4,074

 

2,648

Hagood 6

2.7

Phillips

928

 

603

To Levison Lease

 

Total

23,920

 

15,548

 

15.0

 

 

 

EAST END

May 1953 Wet

Gas Production

Da. Avge. Mcf.

Residual

Gas

Mcf.

 

Injection

Volumes

MMcf/D

Texas

11,774

 

7,653

Carney 12-5

1.5

 

 

 

 

UP 57-21

3.1

 

 

 

 

      34-31

3.1

Sharples

1,902

 

1,236

McLaughlin 5-33

1.2

California

3,821

 

2,484

Fee 54

2.5

Stanolind

3,739

 

2,430

Rector 4

1.2

 

 

 

 

F.V. Larson B 11

1.2

Phillips

2,034

 

1,322

Levison 16

1.9

 

 

 

 

 

 

Total

23,270

 

15,125

 

15.7

 

 

 

 

 

 

Total Field

47,190

 

30,673

 

30.7

 

In addition, the Director recommended that if exemptions were granted by the Commission that some top limit should be placed on the wells of the leases exempted. A top limit of 50,000 cubic feet per well per day was suggested by The California Company.

 

The California Company approved the Zorichak Plan as submitted, as did the Stanolind Oil and Gas Company. The Phillips Petroleum Company approved the plan in general, but recommended continuing control by the Commission so that changes could be made after notice and hearing. Phillips further suggested that some latitude should be recognized in the injection volumes and suggested a permissible overage of injection volume up to an average of 1,000,000 cubic feet per day averaged over any monthly period. Phillips further recommended that there should be sufficient flexibility in the order so that alternate injection wells may be used to supplement or replace injection wells designated. Phillips reiterated its request that exemptions should be granted to those leases on wells which are not connected to the gathering system of the gasoline plant, and suggested that any lease or well which is exempted should remain subject to some control perhaps similar to that set up under Rule 3a.

 

The Sharples Oil Corporation also approved the Zorichak Plan in general but recommended that provision be made in the order for a continuing supervision and change to suit conditions as they may develop in the future. Sharples further pointed out that some rule for allocation of injection gas to the various injection wells would have to be devised and recommended that the Sharples Weyrauch Lease, which is not connected with the gasoline plant, should be exempted.

 

The Texas-Union Pacific approved the Zorichak Plan as to the number of injection wells and their selections but reiterated again that the distribution of injection gas to the operators should be on the basis of oil production.

 

It should not be necessary here to repeat what is clearly set forth in Order No. 2-8 of the Commission. Suffice it to say that waste is being committed in the production of oil and gas from the Rangely Weber Reservoir. The Commission in issuing its Order No. 2-8 has undertaken to prevent such waste of oil and gas, and the Commission must now issue the order hereinafter to follow to effectuate the objectives of its Order No. 2-8, and to initiate a gas injection program for the field. Let it be stated here that every consideration has been given each operator and the sole objective of the Commission is to achieve the maximum benefits to the people of the State in the prevention of waste from this field and in the realization of the increased ultimate recovery of millions of barrels of oil with the least damage possible to each operator. Certain exemptions to the application of Rule 3b of Order No. 2-8 will have to be made to prevent undue hardship on any one operator, but such exemptions cannot be in conflict with the basic objective of Rule 3b of Order No. 2-8 which is that all gas which might otherwise be flared should be returned to the reservoir, by which it is estimated that the ultimate recovery of oil from the Rangely Weber Reservoir can be increased 30 to 87 million barrels of oil. The Commission expects to maintain a continuing supervision of the gas injection program so that undue hardships which develop may be corrected if possible and the maximum objectives reasonably attainable will be achieved. Further Orders of this Commission will undoubtedly have to be entered after the gas injection program has commenced and the effects of field-wide gas injection into the Weber Reservoir have become more ascertainable. In the last analysis, the success of this injection program is going to depend to a large extent on cooperation between the various operators and the Commission and the United States Geological Survey. To date, in spite of differences of opinion which have developed, the Commission believes that it has had the cooperation of the operators, and it is hopeful that such cooperation will continue in the future as the gas injection program gets underway.

 

As stated hereinabove, Rule 3b of Order No. 2-8 is presently to go into effect September 1, 1953, and Rule 3a of Order No. 2-8 is to be effective through August 31, 1953. The issuance of this Order, however, has been delayed due to the most unfortunate illness of the Director, Mr. J.J. Zorichak, culminating in the death of Mr. Zorichak on August 6, 1953. It has, thus, become necessary to extend the effective date of Rule 3b to Sept. 15, 1953 so that there will be sufficient time for the operators to complete preparations for compliance before the effective date of Rule 3b. Rule 3a should remain in effect as before until Rule 3b becomes effective.  

 

FINDINGS

 

The Commission finds as follows:

 

            1.      That due notice of the time, place, and purpose of the hearings in this matter was given in all respect as required by law.

 

            2.      That the Commission has jurisdiction over the subject matter expressed in said notice and of the parties interested herein, and jurisdiction to promulgate the following prescribed order.

 

            3.      That, in addition to the rules and regulations heretofore prescribed in Order No. 2-8 of the Commission, which order and its findings are made a part hereof by reference, the rules and regulations and the matters hereafter in this order prescribed for the Weber Reservoir of the Rangely Field are reasonably necessary to effectuate the provisions of Rule 3b of Order No. 2-8 and are reasonably necessary to carry out the provisions of the Oil and Gas Conservation Act of 1951, as amended, and to prevent waste of oil and gas as defined by law and to increase the ultimate recovery of oil from said reservoir.

 

            4.      That any program of gas injection into the Weber Reservoir of the Rangely Field pursuant to Rule 3b of Order No. 2-8 should be carried out in accordance with the following basic principles:

 

         (a)     That each operator should be required to return to the Weber Reservoir only the gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to leases operated by such operator. Gas "produced from or attributable to" any lease or leases, as that term is used herein, includes, but is not limited to, residue gas available for injection as that gas is presently defined and determined under the provisions of the several Gas Purchase Contracts between the operators in the field and the owners of the Rangely Gasoline Plant.

 

         (b)     That, to the extent possible, gas available for injection under the terms of Rule 3b of Order No. 2-8 should be injected back into the lease from which it is produced, and in the case of smaller leases, upon which it is not feasible or practicable to locate an injection well, gas available for injection from such leases, to the extent possible, should be injected by the operator producing such gas in an injection well of such operator in close proximity to such lease.

 

         (c)     That any program which may be prescribed or provided by the Commission for gas injection into the Weber Reservoir pursuant to Rule 3b of Order No. 2-8 and any other orders of the Commission must necessarily be flexible and subject to change as the conditions in the field may warrant after gas injection by the operators is commenced.

 

            5.      The Commission further finds that the injection wells of each operator hereinbelow approved for gas injection purposes are adequately located in the Weber Reservoir to achieve maximum benefits from gas injection from said reservoir; that each of such injection wells has sufficient penetration of the Weber producing pay for gas injection purposes; that the characteristics of each injection well indicates that such wells may reasonably be expected to have sufficient injection capacity to handle the necessary gas volume to be injected as herein provided for; and that said wells are suitable for gas injection purposes pursuant to Rule 3b of Order No. 2-8 and as provided for herein.

 

            6.      That there are in the field a number of leases producing from the Weber Reservoir which leases are not now connected to the gathering system of the gasoline plant and from which the amount of gas available for injection under the terms of Rule 3b of Order No. 2-8 is relatively small. The Commission finds that it would impose an undue hardship on the operator of each such lease if the operator thereof was required to comply with the provisions of Rule 3b of Order No. 2-8 and return such gas to the reservoir as therein provided fops provided that the amount of gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from each such lease does not exceed a daily average of 50,000 cubic feet of gas per well during any one month. To exempt such gas from being returned to the reservoirs with the limitation hereinabove stated, will not appreciably affect the maximum benefits to be obtained from gas injection in the Weber Reservoir nor the increase in the quantity of oil that might ultimately be produced from the said reservoir contemplated herein. The escape blowing or releasing, directly or indirectly into the open air of gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from each such lease up to an amount not exceeding a daily average of 50,000 cubic feet of gas per well is not excessive or unreasonable.

 

            7.      The Commission further recognizes that it is inherent in the operation of the gasoline plant in the field that occasional emergency flaring of gas is unavoidable, but the amount of such flare should be kept at a minimum in accordance with sound engineering practices. Such flaring is not deemed to be excessive or unreasonable and will not unreasonably diminish the quantity of oil or gas that might ultimately be produced from the Weber Reservoir.

 

ORDER

 

NOW THEREFORE, IT IS ORDERED by the Oil and Gas Conservation Commission of the State or Colorado that commencing with the effective date of Rule 3b of Order No. 2-8 as herein provided, the following rules and regulations be and the same are adopted for the Weber Sand Pool in the Rangely Field, said rules and regulations to be in addition to and to supplement the rules and regulations set forth in Order No. 2-8, the rules and regulations contained in Order No. 2-8 to remain in full force and effect except as modified herein.

 

Rule 1

 

Commencing with the effective date of Rule 3b of Order No. 2-8 as herein provided, each operator in the Weber Reservoir of the Rangely Field shall be required to return to the Weber Reservoir only the gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to leases operated by such operator, except as provided herein.

 

Rule 2

 

The following wells tabulated below are approved for gas injection into the Weber Reservoir, the tabulation showing the operator and the lease name and well number of each injection well, said wells also being shown on Exhibit 1 hereto attached:

 

Operator

Lease Name and

Well Number

The California Company

Fee 65

Emerald 34

McLaughlin 38

Fee 54

 

Stanolind Oil and Gas Company

L.N. Hagood 6

E. Rector 4

F.V. Larson “B” 11

 

Phillips Petroleum Company

Levison 16

 

The Texas Company

Carney 12-5

UP 57-21

UP 34-31

 

Sharples Oil Corporation

McLaughlin 5-33

 

Rule 3

 

The amount of gas to be injected by the operator in each injection well shall be determined in the manner hereinafter in this rule set forth, except insofar as the provisions of Rule 5 and Rule 6 herein may be applicable.

 

         (a)     All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to that part of the Calco Fee Lands located west of the line A-A' shown on Exhibit l attached hereto, and the Gray "A" Lease, Gray "B" Lease, the Neal Lease, the Raven "A" Lease and the Raven "B" Lease shall be injected by The California Company in Fee 65 well.

 

         (b)     All gas available for injection under the terms of Rule of Order No. 2-8 produced from or attributable to the Emerald Oil Company Lease shall be injected by The California Company in Emerald 34 well.

 

         (c)     All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to the A.C. McLaughlin Consolidated Lease shall be injected by The California Company in the McLaughlin 38 well.

 

         (d)     All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to that part of the Calco Fee Lands located east of the line A-A' shown on Exhibit l attached hereto, and the S.W. McLaughlin Lease shall be injected by the California Company in Fee 54 well.

 

         (e)     All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to all Stanolind operated leases located west of the line A-A' as shown on Exhibit 1 attached hereto, shall be injected by the Stanolind Oil and Gas Company in L.N. Hagood 6 well.

 

         (f)      All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to all Stanolind operated leases located east of the line A-A' as shown on Exhibit 1 attached hereto, shall be injected by the Stanolind Oil and Gas Company in the F.V. Larson "B" 11 well and the E. Rector 4 well, the gas to be divided between such wells as nearly equally as possible.

 

         (g)     All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to all Phillips operated leases shall be injected by the Phillips Petroleum Company in the Levison 16 well.

 

         (h)     All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to the Carney Lease and the Carney Unit Lease shall be injected by The Texas Company in Carney 12-5 well.

 

 

         (i)      All gas available for injection under the terms of Rule 3b of Order No. 2-8 produced from or attributable to all Texas-U.P. Fee Lands shall be injected by The Texas Company in UP 34-31 and UP 57-21, the gas to be divided between such wells as nearly equally as possible.

 

         (j)      All gas available for inject job under the terms of Rule 3b of Order No. 2-8 produced from or attributable to the Sharples operated leases shall be injected by the Sharples Oil Corporation in McLaughlin 5-33 well.

 

 

Rule 4

 

Gas injected into each injection well shall at all times be injected only in accordance with sound engineering practices.

 

Rule 5

 

There is hereby exempted from all gas available for injection under the terms of Rule 3b of Order No. 2-8 a daily average of 50,000 cubic feet of gas per well during any one month produced from or attributable to a lease not presently connected to the gathering system of the gasoline plant. Should any of the leases not presently connected to the gathering system of the gasoline plant be subsequently connected, then the exemption herein contained shall not apply to such lease, provided that any injection of gas into the Weber Reservoir from leases shall be subject to approval of the Commission after notice and hearing.

 

Rule 6

 

Occasional emergency flaring of gas in connection with the operation of the gasoline plant is permitted provided that the amount of such flare shall be kept at a minimum in accordance with sound engineering practices.

 

Rule 7

 

Commencing with the effective date of Rule 3b of Order No. 2-8 as herein provided no gas shall be injected into the Weber Reservoir in an injection well or in a manner other than that herein approved or provided for except on approval of the Commission after notice and hearing.

 

Rule 8

 

In addition to the reports required in Order No. 2-8 each operator shall submit to the Commission on Form OGCC-11 a certified report on the 15th day of each and every month commencing October 15, 1953, covering the gas injection operations of such operator for the preceding calendar month or fraction thereof if applicable, showing such information as therein prescribed to enable the Commission to properly administer Rule 3b of Order No. 2-8 and this Order.

 

IT IS FURTHER ORDERED that the rules and regulations hereinabove promulgated are subject to alteration and modification as may be required after gas injection is commenced in the field, and the Commission expressly reserves its right, after notice and hearing, to alter, amend, or repeal any and/or all of the above rules and regulations, furthermore, any operator may at any time apply to the Commission for modification of this Order or any rule or regulation herein contained.

 

IT IS FURTHER ORDERED that all rules and regulations contained in any Statewide order in effect, or that may be promulgated by this Commission, which are not inconsistent with the foregoing rules and regulations, are hereby adopted and will apply by reference.

 

IT IS FURTHER ORDERED that, except as herein specifically provided, all other requests for exemption to the application of Rule 3b of Order No. 2-8 are hereby denied.

 

IT IS FURTHER ORDERED that the effective period for compliance with the provisions of Rule 3a of Order No. 2-8, as amended by Orders No. 2-9, 2-10, 2-11 and 2-12 is hereby extended to be effective during the two weeks period from August 31, 1953 to and including September 14, 1953, and the effective date of Rule 3b of Order No. 2-8, as amended by Orders No. 2-9, 2-10, 2-11 and 2-12, is hereby extended to September 15, 1953.

 

IT IS FURTHER ORDERED that this Order shall become effective forthwith.

 

ORDERED this 11th day of August, 1953, by the Oil and Gas Conservation Commission of the State of Colorado.

 

OIL AND GAS CONSERVATION COMMISSION OF THE STATE OF COLORADO

 

 

By Annabel Hogsett, Assistant Secretary