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Home My WebLink About941589.tiff UNITED STATES ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL APPLICATION AND SUBMITTALS 941589 941078 form Approved. Fora t UNITEL \TES ENVIRONMENTAL PROTECTION AGENCY I.EPA ID NUMBERS No.2pd.!-opd?,F:onex 9.3o-aE 4 n ' UNDERGROUND INJECTION CONTROL � ' 6 EPA PERMIT APPLICATION77.4 c e UIC (Collected under the authority of the Sale Drinking U L Water Act,Sections 1421, 1422,410 CFR 144) READ ATTACHED INSTRUCTIONS BEFORE STARTING FOR OFFICIAL USE ONLY I Application Woad Date Received l mo dry year mo day year Permit/Well Number Comments II.FACILITY NAME AND ADDRESS ! &q51.) - Facility Name III.OWNER/OPERATOR AND ADDRESS SUCKLA FARMS TN.7ECTT0N WELL #L Owner/OperatorNamar.t "r, r. " • Street Address WRICHTrS DSSP0SAT. INC. Street Address ' .Cut'.. nsr'. , city 9270 Qni tman • State •: ZIP Code City Westminster"" • 9 State ZIP Code , , L IV.OWNERSHIP STATUS(Mark'x) C� � ` ' 80030 V.SIC CODES ❑A.Federal � . .❑B.Stan CRC.Private.!, ,; yr '':C L. 0 D.Public 0 E.Other(Explain) .;-;u tScs�u ;'. +, y�_.'�.,; VI.WELL STATUS(Mark x) ®A. Date Started • 0 ma ar veer B,Modification/Conversion, 0C.Proposed ei, ' l'''` Operating 7 15 89 ., 1. VII.TYPE OF PERMIT REQUESTED(Mark:and s city if required) I Number of Exist- Number of Pro- Names)of field(s)or project(s) :�„ t A.Individual ❑ B.Area ing welt '2;,:;>.:i, Posed wells' - one none Suckla Farms ' .'.;, VIII.CLASS AND TYPE OF WELL(see reverse) i._.. A.Class(es) B.Type(s) C.If class is"other"or is code °' explain D.Number of wells per type(if area permit) (enter code(s)) (enter cadets)) I & II I & D ONE L" ix.LOCATION OF WELL(SI OR APPROXIMATE CENTER OF FIELD OR PROJECT C A.Latitude 8.Longitude Township and Range X INDIAN LANDS(Mark'x% Deg Min Sec Deg Min Sec Twsp Ran Sec 4 See Feet from Line Feet from b I Line Yes ® No XI.ATTACHMENTS' , ' following questions on a separate sheet(s)(Complete the and number accordingly;see instructions) L' FOR CLASSES I,II,Ill(and other classes)complete and submit on separate sheet(s)Attachments A—U appropriate.Attach maps where required. List attachments by letter which are applicable and are included witas h your application: L XII.CERTIFICATION /certify under the penalty of law that /have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. lam aware that there are significant penalties for L. submitting false information, including the possibility of fine and imprisonment. (Ref. 40 CM 144.32) A.Name and Title(Tye or print) i B.Phone No.(Area Code and No.) TAMF. [JRrr�__ PRESIDENT t C.Sign (303) 426-8911 1 L. ` O. ante Signed PA F 7620-s(2.04) - - 9/21 89 1 9 UNDERGROUND INJECTION CONTROL PERMIT ATTACHMENTS TO FORM 4 l-- WRIGHT'S DISPOSAL INC 9270 Quitman L Westminster, CO. 80030 , A. AREA OF REVIEW METHODS: The area of review shall be a fixed radius of mile from the L_ well bore. B. MAPS OF WELLS/AREA AND AREA OF REVIEW: L See Attached Exhibit I C. CORRECTIVE ACTION PLAN AND WELL DATA: There are no existing well with-in a five mile radius of the existing injection well that penatrate the Lyons Formation. D. MAPS AND CROSS SECTIONS OF USDWs : See Attached Exhibit II E. NAME AND DEPTH OF USDWs (CLASS II) : Arapahoe Formation - 350' and the Foxhills Formation - 650' F. MAPS AND CROSS SECTIONS OF GEOLOGIC STRUCTURE OF AREA: There exist only general information pertaing to structure of the Lyons Formation, as the injection well is the only deep test with-in a ten mile radius . See attached Exhibit III for a cross section of the area.. G. GEOLOGICAL DATA ON INJECTION AND CONFINING ZONES (CLASS II) : The lyons formation, the strata being injected into, is a massive Permian Sandstone, which is white to pink in color and is a crossbedded sandstone of fine to coarse grains . The top of the Lyons is at 9139 KB to 9424 KB with a Frac gradient of .70. The top of the formation is covered by the Harriman Shale, which is a medium hard to hard red shale. The Base of the Lyons is the Satanka Shale similar in deposition as the Harriman shale. H. OPERATING DATA: The Sukla Farms Injection Well currently injects 1,200 BBLS per day of produced water from oil and gas wells in Weld County, Colorado. We do not currently inject any industrial materials . Our injection rate is 84 BPH at 520 psi with an anticipated maximum pressure of 650 psi. See attachment Exhibit IV for analysis on fluids currently being injected. The annulus fluid between the tubing and the casing is fresh water treated with a anti- corrosive chemical. COPY L._ 941079 941079 M I r �� , EXHIBIT, I T I N R 67 . W r L Range No. th Mer. 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I �I II I II —II III IIIIIIIIII III IIIIIII IG GROUP a OUI I 1I'1'�III'1II1' MIOCENE I III IIII IIIIII III 111' WHIT[ RIPER FORMATION OLIOOCG[ L'IfO dal Ill I III0 i'iiiplld eY11TL RVlyN fY l.�iclLii:L11:�i1;IlJ IM11111d./1;i'Ig IIIIIS'Ila,I;IAquOi— GO — 1111111111 vRl. o[nu xoL[ r Ru.nx u FORMATION 111111 pX IYt0 ROCKS IIIIIII III I III II IIIlI111111liii111111 Gta( 111111IIIIIIIII FARISITA FORMATION GREEN RIVER FORMATION I NVT.FIRO-CVCONA FORMATION L PALEOCENE SAN JOSE FORMATION WAl1TCN FORMATION <OAlYONT FORMATION Il lllllllllllllilllllll�ll . RITOY IORYITIOY FARMINGTON It Fr.UNION FY. OHIO CAEEE COLS MIDDLE PARE IM. • POISON GAMMON IOPYPT IOx —TO=G— ANIMA! JIIIIIIIIIIIIIII�IIIIUIJII~ — � FORMATION 0,0 AL YO a, I I I- FORMATION UPI YI(r�FORMATION YOY[J0 FORMATION LANCE ' I .- WLYIL CI9[LIMO(MALE fit /FY4xIILL" a FRUITLAXO FORMATION "'311.AS `- VETO! CLI/ S SS NEIIYFRDE WILLIANS FORE FM. PIERRE IN L[ PIERRE SALE ACM SHALE .♦]'ROCKY TOR0 NIP Y[MLIG LEWIS St a0U1 LCi fit L 'or RS.A /Y C If!X uww! so if PIERRE SHALE 'I T Una AEN p >tlo.e a CfriatiLICKE iT.u:,E1Us l:c • r_. CXETACM.JHOA CRCWa3[ 44 LtlCANN-IRPR� MI SMOKY NIA NOR NI SNORT LL Sit GANYON UI'Y[N AEON III ANN tl10NMAMA IOM MINION FORMATION moAAARA mini. WRAY HILL se FM. [HAYS LS.M.R. FORMATION F(RATS LS NBA Ft NAYS U.NO YAxcot SHALE I I LOWER SHALE IJ IAxA InP lv CGLIL[ - CIRLIIt ClRlllC — MANC01 SEYTOM SHALE SFMTOY SHALE 2141E �' SHALE I4RCLXNORII U.4 GROUP 5. ENNORX GROUP GREENHORN'Li. MENTON UMW GREENHORN LS. CRIMEAN SX. . GRANEROS ill.DAKOTA GROUP._ _�I'Ill'I�II'Ihr�INSINIl.[Ii 111 1111IR I"I"IIII III"I"IIIIIII" DAXOTAPLATTE IN �Y DAKOTA IYRGATOE[ III _Rau;ll SX. _, a xO 3ARNOA— aAMGO LONER GROUP RAT I[ A J ON DIRDTA SANDSTONE CRETACEOUS 1 Tiil ll l:�a 13515 MORRISON I}1?11Y;r.or /IIU; MORRISON SRUfNT SSIN NOR MORRISON "RUSHY BASIN MIS FORMATION"q;lAll:R' _ FORMATION fa YAT IOM MORRISON FORMATION MORRISON FORMATION MORRISON FORMATION SLUR SANDS ON SALT WASH Mill SALT WON YOR JURASSIC GLEN RAF tUYCURTIS F FM, 3UYYMATItE IFORMATION RALSTON aLG FORMATION RAN ION GREEN FORMATION 1V NLIJF SA.IogYSIIOX SAN RAFAEL MENVIf fY. GAY RAIA[L FORMATION 'RALSTON CREEK �4Y�\[4 (Q4CrIP9 GROUP _-__._- LXTPAG SANDSTOR( NCANNE I+ GROUP WY Ii.[19.E4�!'i11.I0.TLITFICTI (IIIIIII! ■II'll�llllll�l CG Y[O SS. I �1■■■1 —It01l�I OL[N CANYON NAVAJO JJ , UPPER GROUP GROUP NAVAJO SS. OLEN CANT _ 1 1 INNATE SJ OR NUGGET St CANTON A CHIN( FM CNINN FORMATION . CXIXLE FORMATION � �� DOCK ISM GROUP TAIASNIC .. . -. YO[NIOPI YO[MYO/I STATE BRIDGE a LONG FORMATION tlRol01E}EP •PHNOM S1ATjggSAIOR FORMATION FY.IUP PART( LT RIMS FON.ASIOYI • —rE:as—a— Rmn[aRla /plllll iIIIIIIIIIIIIIIIIIu...-_ STEINS STRAIN SHALE I PARE CITY, MA II II[ FORMATION GLUNON St TALO/A FORMATION q YI! STATE IRIORC WV.PART) OAT CREEK DOLOMITE PNOnNORIA • SOUTH CANYON CA.OOL, BERGEN SHALE WHITEHORSE SAMORIOXt NOOYSIDE (MS FRARION NR, FALCON LA YNYAY[D IIIIIIIIIIIIII1111111 _ li l Ilillll NDGRt rN , fr (Pn PERMIAN LYONS.St ATAXIA SN. riAI,6k'1iI11U�r1,! Y IPf[WALLI WW 44 YYMM OO LL` L SAI ANN ERA SUMNER GOUT CUTE[! FOR MINION IGLGIOC Ft OXA__[ 4ROUP MAROON BANG AN TOOL EC O TURK COUNC LgOY[ cR V1 —210.5.— IY. l;q T� A YIR q r �,nT)JO,POIOTROI� IIARTI MAROON FORMATION(PART) II(II NOXARER TRAIL FIR. l_ NGYOrA ILLLLLOID{ t PENN- GROUP PARA00:I I1AlAL?)di EAGLE VALLEY O L FOUNTAIN FORMATION FM. �,TIEIOP1 YOGAN FORMATION [VE AITL SYLVANIA \ :1:T F YIXTYPN IBA FOUNTAIN FORMATION PINKERTON TRAIL Fu. — II YOLAS FORMATION ILLOEY SHALE • I I I V I I I I I I I I ILLN ETRII IX.MIR —JI0LS— ,a T } NVG UO FM l I—I—^F - IIIIIIIIII�T _HAM AS L It ___ MISSISSPPIAN �_._ 0 GUERNSEY FORMATION, — IRAN Y T LEAOVILLE LIMESTONE LEADVILLE LIMESTONE IEADYILL[LM. OILMAN ARS IF 0 R - I IIIIIIIIIIIIIIIIIIIIIIIIII IIIIIIIIII VIII II IIIIIIlIIIIIIII III IIIIIIIIIIIII WILLIAMS CANYON LIMESTONE A —>Eotw UPPER [Off RT FORII MATIONN CHAFF[[ OY'P Y. CHAFFEt DYER Y WILLIAMS CANTON LIMESTONE NIL tiMES CANTON LIMESTONE DEVONIAN Apt �SL GOYP PARTING GROUP' FAR,IMP SS. LOCVOXIAM M]RfI'A T 7 SANDSTONE IO� SILURIAN r -1001q- I.I I I. OROOVICIAX ��5�5J —WOWS— UPPER RYA YI NITOU FORMATION__ IPGCRI[ tgOIRON' TAI GRUCCL[ GROUP ,•l PEERLESS FORMATION ROCAS GAYGIA. IGNACIO OUARTTITL !MATCH SANDSTONE "Ili I I I'lll111lIII I II III —I�p fp LOOM IAGITOYE II Ji I II,clivaIII rR[CRYR:- T^T'�IIIISIIIIIIInnIIIIIIIIu_ JLIT�i.,Rll5J1 YITAYDRP tllC Sa IXTR� GwPIMC Ii:q PVC NOM Awl CN p,iL111 YvgrlMlNal 11741, $1110.1 ON:OUINW Allu RI IIa tinny SMiLM Ow., IRYAD,10721 -MIIIIwI.I yaws kiwi P,RNR.I I NIKE.:ORNRO OR LRLV.INIIV,NO O!*Au FVGIIUIM1At Roland 11 WAIN.wuMn N IM am I 941079 I - ,--O4,1,4-770,Or BRIGHT0N (. A-re2 �� ?!!*� DISTRICT LAB SERVICES BRIGHTON , COLORADO EXHIBIT IV SUBJECT : WATER ANALYSIS PLEASE REPLY: 009 BASE UNECIRCLE BRIGHTON.CO X OJI l y° � FORMATION: a COMPANY NAME : as EASES . IC- WELL NO:t41th'" lj WELL DEPTH: FEET COUNTY: STATE: ADZ__ p FIELD : a � llld(GC� BHST: FO0 OF DATE : 7-12 7 -- TYPE OF WATER: - ,+_J SAMPLING. POINT: CATIONS: mg/1 ppm OTHER PROPERTIES: • Sodium,Na MA ..--- PH or' y'r �� 1 Calcium,Ca �al Specific Gravity @ OF : 7 X 2 — Magnesium,Mg O 6,2Atzfri710air /, D9L Barium,Ba NM �NM Total Hardness M 3 _L 122_ ANIONS: a Chloride,Ci . C w C 1k4 Sulfate,SO4 7/aC Carbonate,CO3 O 7) L Bicarbonate,HCOS --ad I- Iron(total ) _II L__ REMARKS & RECOMMENDATIONS: , LAB NO. / DATE ANALYZED BY : 4 _ hG SIGNED : I DISTRIBUTION: 5500 Northwest Central Drive • Houston, Texas 77092 • 713.462-4239 l 941078 ' , ,I ' 1 N JtcnorJ �r BRIGHTON DISTRICT LAB [. ...77-Y, SERVICES BRIGHTON, COLORADO SUBJECT : WATER ANALYSIS PLEASE REPLY; w0 BASE UNE CIRCLE • ERIOMTCN.CO 0901 l._. FORMATION: .cssi, • COMPANY NAME : %ra/LEASE4OM/t /N O: WELL DEPTH: : FEET COUNTY: Q%JGf. STATE: aA FIELD : BUST: of DATE : -- TYPE OF WATER: 441 SAMPLING POINT: LCATIONS: mg/1 ppm OTHER PROPERTIES: v - :PH Sodium,Na r Calcium,Ca L1o24 a Specific Gravity/ @ of // �///��, Magnesium,Mg j7 I X 27 e (9O / OBIS' Barium,Ba NM NM Total Hardness 2sc---- LANIONS: .. Chloride,C1 /a .1. Sulfate,SO4 `/-'5)v Carbonate,CO3 v�J, (JV1 Bicarbonate,HCO3 �.'v -�1k± Iron(total ) • 02 9 OZr. REMARKS & RECOMMENDATIONS:LAB NO. / DATE : 7- /7 4 / ::::T:N: ci alp-•/�G /94(6 SIGNED:L r • 5500 Northwest Central Drive • Houston, Texas 77092 • 713.462.4239 941079 Biii In BRIGHTON DISTRICT LAB SERVICE BRIGHTON, COLORADO �� S SUBJECT : WATER ANALYSIS PLEASE RELY: WO BABE UNE CIRCLE • •RIONTON,CO 10001 • FORMATION; cSS-e�C . • I,/ /� ir/ hl�COMPANY NAME :/ -1-,4i iescaLa LEASEre la, WELL NO/_WELL DEPTH: / FUEET COUNTY: /'" /% STATE: ai__ FIELD BHST: e F DATE : 2-414)7 ,_. TYPE OF WATER: 742*r9Cl.r.e_ / SAMPLING POINT: -- CATIONS: mg/1 ppm OTHER PROPERTIES: Sodium,Na PH 4,9.E Calcium,Ca --1211 Specific Gravity @ of : O ‘45,cMagnesium,Mg 17/ • I� oi C ei kaF /, 0 L Barium,Ba NM NM Total Hardness 4 ANIONS: /) .. /6 Chloride,C1 Z3°o 11 .-_ Sulfate,SO4 G /1__ Q Carbonate,CO3 0 L Bicarbonate,HCO3 Iron(total ) 4._____ �� t�L_ REMARKS & RECOMMENDATIONS: LAB NO. DATE --0 L_ ANALYZED BY : / 0 SIGNED: d/7 .-fij DISTRIBUTION: �..cXG f L-- 5500 Northwest Central Drive • Houston, Texas 77092 • 713-462.4239 [_ . 941079 ,) 11•PLJNLil' :" BRIGHTON DISTRICT LAB CAinC SERVICES BRIGHTON , COLORADO SUBJECT : WATER ANALYSIS PLEASE RELY; KY BABE UNE CIRCLE �+ BRIGHTON.CC 10101 FORMATION': L ST,c,3S'2>c` . COMPANY NAME : I D,P6 4L EASE: WELL NO: J 404/11C ',�/ / it //�� WELL DEPTH: FEET COUNTY: 11.4741 STATE: _� _ FIELD : ^ BHST: °F DATE : -- TYPE OF WATER: 7/)/LzGtC/f SAMPLING POINT: CATIONS: mg/1 ppm OTHER PROPERTIES : PH . Sodium,Na � Calcium,Ca Specific Gravity @ °F : I , /;ei 'ro'4 WI t 6a ao°F / 0 /7 Magnesium,Mq Barium,Ba NM NM Total Hardness gr c-c.' 224— ANIONS: . Chloride,C1 id, c/(% "1 -- Sulfate,SO4 rc' _SA__ Carbonate,CO3 Bicarbonate,HCO3 u.10_ _54 .. Iron(total ) O __I_— _. REMARKS & RECOMMENDATIONS: • ] q LAB NO. DATE - / c9// ANALYZED BY : h 04 SIGNED: -- DISTRIBUTION: fr 5500 Northwest Central Drive • Houston, Texas 77092 • 713.462.4239 I 941079 OGCC Form 148 Fin. 12/8S STATE OF COLORADO ".--- r OIL ID GAS CONSERVATION COMMIS:' N r •,,. i Department of Natural Resources l.,r, r.. MECHANICAL INTEGRITY REPORT ._, ._ Facility Number API Number Well Name and Number � oq O.5"M;-lit, I -v .Soc.ec.,4 1.4-,lts XNf &)Eta field Location(R Ye,Sec Twp.,Rng-)S. / }OperaS., //one.: St NLtJ !a- (t)-6:7 (4.) — Gv/P/(9f7/S DiSO4Sg'G peralor Address q/ 1 City Slate Zip Code Q4-17n1 44 GJtSrM/NSra go. WI e) oersteds presentative at Test f— Area Code Phone Number crr Az I FUZZ? (333 ) 5/u -Is// _ 1. If both Part I and Part II are not completed,the mechanical Integrity test can- 3. A pressure chart must accompany this report,it the pressure test was not wit- _ not be approved and will be returned to the operator. nessed by a state representative. _- Notice must be given to the Commission prior to performing any required 4. Facility numbers and API numbers are available at the Commission upon —. pressure test. request. 'ART I (choose one of the following options) I_. /l % I 1. Pf@SSUr@test ' (Pressure tests should be a minimum of 15 minutes,at 300 psi or minimum injection pressure whichever Is greater. A minimum 300 psi differential pressure must be maintained between tubing and tubing/casing annulus pressures.) —A Well Data at Time of Test B. Test Data 'Tubing Size c Tubing b Depth Top.Pack/err Depth Multiple Packers Test Dale Date of Last Approved Mechanical integrity Test 1'/0 9252 ft T/ ❑ Yes PI No Siff ....kg.Plug Depth Injection Zone(s),name Injection Interval(gross) Starting re Final Teat Pressure Pressure Loss or Gain During Test L/o,u5 9276, to ff4rf7 SD.C.095/' rjtOe5/ - 5 psi - acted Thru Test Witnessed by State Rep. Tubing PT9ressure During Test Well Status During Pressure Test _j Perforations 0 Open Hole cEiYes ❑ No 0 Injecting ❑ Shut-in Open ii2. Monitoring Tubing - Casing Annulus Pressure Procedure must be approved prior to initiation and only after satis- factorily passing an initial pressure test. time of Pressure Test Test Pressure Date Pressure Test Approvec Monitoring to Stan (Month,Year) n3. Alternate Test Approved by Director (see Rule 327)Attach procedures and logs with report. Procedures subject to review by EPA - 'ART II (Choose one of the following)Attach records, charts, logs where appropriate. - ❑ 1. Cementing Records - (valid only for Injection wells in existence prior to July 1,.1986) Casing Size Hole Size Depth Set Na Sirs Cement Calculated Cement Tops _Surface Casing [p•oduction Casing • ...age Tool Test Date Temperature - Test Date - n 2. Tracer Survey 5 4. Survey _ CBL or Test Date �1��lG n 5. Alternate Test Approved by Director a 3' equivalent d (see Rule 327)Attach procedures and logs with report _ Procedures subject to review by EPA ereby certify that e statement rei de are true and correct r • y p Signed Title L'.�v Date 1 / O /G • r it State Use: L_ / • S.,I. ; AEC 2 'fig Approved by \ p 91 7v/...niz? Title ( .. • Date 7/fly a_,7 Conditions of approval, if any I_ 941079 EXHIBIT V OGCC FORM STATE C. .OLORADO . R(10/88) .. .,FOR.OFFICE USE`. ,- . OIL AND GAS.CONSERVATION COMMISSION ET I FE I uc . 1. se I DEPARTMENT OF NATURAL RESOURCES 4 .. - File one copy(or Patented Federal and Indian lands. File in duplicate for State lando. - 5.TYPE OF WELL WELL COMPLETION OR RECOMPLETION REPORT AND COG ❑ OIL ❑ GAS ❑ DRY . JSI.INJECTION❑OTHER L 1.OPERATOR /�,�T4r( ^' (� ! PHONE 6.TYPE OF COMPLETION 0 commuoGLED CO 12n I0 I T /S J ) S POS1%t 303 - T�-S9) / PHEW WELL❑DEEPEN❑PLUG BACK ADDRESS F1 q ❑MULTI-COMPLETE O OTHER QQ27 ) c?,..., ( -yy)4 s - (2 H-STYY) iAmtt2. Cb. Pip03 O 7.FEDERAL OR STATE LEASE NO. 2. DRILLING CONTRACTOR PHONE - "' - e*C.eitte_ ,30. - 3to/ -018 / S.IF INDIAN,AILOITEE OR TRIBE NAME - 3. LOCATION OF WELL(Footoges from section liner) 4.ELEVATIONS 9.WELL NAME AND NUMBER KB S0 Ste. Z. SUGKC.A hh/'rn5 S.NS C.OELc- `I - At surface $(]D ZSL 2020 F' I-- ('rlt so 96,,z, 10. FIELD OR WILDCAT ... At top prod.interval reported below....S tan''f EA _ 5 Q7 A5 0L,l= At total depth S 4 M E 11. QTR.QTR SEC.T.R.AND MERIDIAN - WAS DIRECTIONAL SURVEY RUN? NOW-YES DIP YES.ATTACH COPY N tj3 f 4- I O IN N Col LC 12. PERMIT NO. 13.API NO. 14.SPUD DATE 15.DATE TD 16.I)ATE COMPL 17.COUNTY 18. STATE REAQHED ODB:A �I12(B9 CO. - 'sq. - 34+3 05 123. .1442�Jt (o/Upj.9? -7(O �B`I WREADY TO PROD • (A)..et0 19.TOTAL DEPTH : 20.,PLUG BACK TOT L PTH .. 2t. DEPTH BRIDGE PLUG SET MD C4 57/ TVD 4s-71 ' MD 9 47 4. TVD 9 4.7 6 MD N A - 22.TYPE ELECTRIC AND OTHER MECHANICAL LOGS RUN(SUBMIT COPY OF EACH) 23.WAS WELL CORED? NO pil YES 0 (SUBMIT ANALYSIS) _ TE s - b e,os i 4-!'-yr,� Cot 1 'F22 -"' N Q Ceti WAS DST RUN? NO 55 YES° (SUBMIT REPORT) 24. CASING&LINER'RECORD (Report all strings set in well) WEICHT(LEIFTI HOLE SIZE TOP(MD) BOTTOM(MD) ITAOB<eurlTSR H0.0PSKr.RTrPa SLURRY VOL MIL) TOP OF CEMENT SIZE Oerrx oP<euer+r . 85/a .:94-Ott 12114 . eia. 7s9 ,vA 400"C „ sus'-a,c.c s 1/2 20 11/x 612 966 7 N A ass C 1' Acgo(P -_ 25.TUBING RECORD SIZE DEPTH SET(IAD) PACKERDEPTH(MD) SIZE DEPJHSETWD) PACKERDEPTH(MD) .SIZE DEPTHSET(14D) PACKER DEPTH(MD) - 21/5 92S4- 92.40 sit 26. PRODUCING INTERVALS 27. PERFORATION RECORD - FORMATION TOP BOTTOM PERFORATED INTERVAL SIZE NO.HOLES PERF.STATUS A) LIONS 9,39 1Si29 9274, - q41/3 •Co 19 ite OPSVJ B) L C) D) - 28. ACID,FRACTURE,TREATMENT,CEMENT SQUEEZE,ETC. DEPTH INTERVAL AMOUNT AND TYPE OF MATERIAL - 42'79. - r154fr asoo qAk 772. % t-ICL- cere)40 nin, allS6Set it-I2 i0oo Set# ANh RA/t SeAIPt5 - 29. PRODUCTION-INTERVAL A _ DATE FIRST TEST HOURS nu OIL GAS WATER OIL GRAVITY GAS • PRODUCTION METHOD PRODUCED DATE TESTED PROD WN BBL MCF BBL CORK API DISPOSITION - NA -' CHOKE FLAW.TBCY CSO. 24 HR OIL GAS WATER GAS:OIL WELL STATUS SIZE PRESS PRESS RATE BBL MCF BBL RATIO L "• • PRODUCTION-INTERVAL B. - DATE FIRST TEST HOURS rcrr OIL GAS WATER OIL GRAVITY GAS PRODUCTION METHOD PRODUCED DATE TESTED P BBL MCF BBL CORK API DISPOSITION 'R. CHOKE FLOW.TBG: CCSC., 24HR. OIL GAS WATER - OAS:OIL WELL STATUS SIZE PRESS PRESS RATE BBL MCF . BBL RATIO I COMPLETE AND SIGN BACK PAGE 9414'73 1 DOWN HOLE Stk. 2Y Operator: WRIGHT'S DISPOSAL Well: Suckla Farms injection Well No. Legal: 500 ' FSL 2020 FWL Sec . 10 T1N R67W Weld County, Colnradn Formation: Lyons Perforations: To be determined 700' KB Surface Csg: 8 5/8" K-55 36# Cemented w/250 sxs Class C, 10% Salt Intrm Csg: NA Prod. Csg: 5k" N-80 20# API Cemented W/150 sxs Class G containing - 19% Silica Flour, 5% A-5 , 11% KCL, .6% FI-19. Tubing: 2 7/8" EUE 8rd J-55 Set in a compression packer at Top of Lyons formation. Packer: Compression Type-Baker Tbg Anchor: NA • - Seating Nipple: 2 7/8" @ Top of Pkr. L. Rod String: NA Stg EST. 9250 KB pKR '' 9255 KB Pump: NA Gas Anchor:NA Mud Anchor: NA Special Equipment: NA EST 9580 KR 941079 G -r 37. 6 x 50.6 n D 16 x 21 / J I A --1A K ' � E ► tr A - A T A - PUMP 1 - BLDG W = . . A ( L !� 24 x 24 G l_ B K A E F Trr[ri1 i i i 6x8 OFFICE A A 10 x 16 1JUI111111l! 1111111 G N _ I E G I-- 0 FILTER BLDG L- SUMP 12 x 28 L 10 x. 15 i- -- C. PAD 6 x 38 - _ I I . - - i CEMENT PAD A 400 bbl Ins . Tk 11.6 x 60 B 300 bbl Tk. C 300 bbl Ins . Tk D Porta-potty WRIGHT'S DISPOSAL E Electrical Box F Storage Bldg . Suckla F G Cement retainer arms wall - 5" Thick 12" high. 0 15 r ' 30 SE SE NW 10 -T1N - R67W SCALE 941079 --i_ - -i I I , v��p -r _ • L. • . I I i ! I I : fLrc cc A ' i ! ' ' i .... ._ I_ I .... .. ! 4 ea L . ` I .I a ... . ! 8 C. ... _ _ I I. IU .3 S p • p0 I vi I 4 l i l I• _ I I ! ! 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L 9270 Quitman I, STATE COUNTY WC tmin°tcr, CO. 8UQ� yMIT NUMBER LOCATE WELL AND OUTLINE UNIT ON CO1O Weld ( SECTION PLAT - 640 ACRES • SURFACE LOCATION DESCRIPTION I N SE'A OF NW 'A OF IA SECTION 1 O TOWNSHIP 1 N RANGE 6712 l. I I I I I I LOCATE WELL IN TWO DIRECTIONS FROM NEAREST LINES OF QUARTER SECTION AND DRILLING UNIT L —4 I 4' _.1_,......4_4_....... Surface I I I I I I LocatiorL5�.R•from(I/S)S Line of quarter section —T— 1 T T I T— and?07 Q.from(E/W) —Line of quarter section SE NW t --I- -I--I—�— TYPE OF AUTHORIZATION WELL ACTIVITY ' I I I I I bIndividual Permit )O CLASS I W I I I I 1 I E p Area Permit (.$CLASS II -LJ-L LJ-L- O Rul, O Brine Disposal I, III I I I O Enhanced Recovery ( _tI—t--1--H+— Number of Wells Hyds"f rbon Storage O C AS . -LJ-L_LJ-L- L_ I I I I I I I s Lease Name SUCKLA FARMS Well Number INJECTION WEll #1 CASING AND TUBING RECORD AFTER PLUGGING METHOD OF EMPLACEMENT OF CEMENT PLUGS I 0 The Balance Method • 1SIZE WT(LB/FT) TO BE PUT IN WELL(FT)TO BE LEFT IN WELL(FT) HOLE SIZE 0 The Dump Bailer Method 8 5/3 74# 759 • 754 193" ❑TheTwo-Plug Method 545 70# 9557 7307 7 7/8" K7 other Displacement t. • CEMENTING TO PLUG AND ABANDON DATA: PLUG#1 PLUG#2 PLUG#3 PLUG N4 PLUG#5 PLUG#6 PLUG#7 I.. Size of Hole or Pipe in which Plug Will Be Placed(inches) 511 7 7/8" R" R" Depth to Bottom of Tubing or Drill Pipe(ft.) Sacks of Cement To Be Used(each plug) 60 50 30 10 Slurry Volume To Be Pumped(cu.ft.) 79.7 66 39.6 11 9 L.ICalculated Top of Plug(ft.) 9226 7220 709 4' below AT. Measured Top of Plug(if tagged f.) ±9220 ±7210 ±690 ±4 Slurry Wt.(Lb./Gal.) 14.8 14.8 14.8 14.8 L Type Cement or Other Material(Class III) C C C C LIST ALL OPEN HOLE AND/OR PERFORATED INTERVALS AND INTERVALS WHERE CASING WILL BE VARIED(II any) From To From To L Perforated 9276 9415 Estimated Cost to Plug Wells . - C © py $5,400.00 I. CERTIFICATION LI /certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, t and complete.lam aware that there are significant penalties for submitting false information,including the possibility of fine and imprisonment. (Ref. 40 CFR 144.32) LI NAME AND OFFICIAL TITLE(Please type or print) SIG UR /t- / DATE SIGNED 7 JAMES S. WRIGHT. - PRESIDENT 9/22489 I-�PA Form 7620-14(3.84) • 941079 3. Oil Field Service, Compan. 1 Fort Lupton, Colorado 80621 hN (30 3) 857-6549 i September 25,1989 #1 Suckle Farms Injection Well Section 10 1 North 67 West Wright Disposal Inc. 21 Hrs. Rig Time @ $100.00/Hr. $2100.00 To Lay Down 2-7/8" Tubing And To Lay Down 5-i" Casing 8 Hrs. T-7 Winch Truck @ $55.00/Hr. $ 440.00 8 Hrs. Trailer @ $8.00/Hr. 64.00 Logging And Free Point And Cut Off $ 500.00 TOTAL $3104.00 These Prices Are Based At Current Rig And Truck Prices. • r 941079 ' .z •" 41079 • CEMENTING RECOMMENDATION FOR WRIGHTS DISPOSAL INC. Suckla Farms Injection Well #1 Weld County, Colorado Sec. 1/4 NW 1/4 Sec. 10-T1N-R67W Prepared for: Prepared by: Robert Fullop Ray Lynch BJ Titan Services P.O. Box 536 Brighton, CO 80601 . September 25, 1989 I-" Service Point Brighton, Colorado (303) 659-0864 Mary Kaufman District Manager CI BJ TITAN SERVICEW41.®79 Wright Disposal Inc. September 25, 1989 COST ESTIMATE Pump unit to 9, 220 ft. 8 hrs on location $ 2, 915.00 Mileage on pump truck 15 ji. @ $1.12/mi RT 33. 60 150 sacks Class "G" Cement @ $6.00/sk. 900.00 Mixing & Handling 150 cu. ft. @ $ .95/cu.ft. 142.50 Drayage of 7 tons 15 ji. @ $ . 75/tm 78. 75 Book Price ; $ 4, 069.85 DISCOUNTED PRICE: $ 2, 604. 70 r- r- r- C • 941079 Wright Disposal, Inc. September 25 , 1989 CEMENTING RECOMMENDATION The recommended plugs are as follows : ± 9220-9226 - 60 sacks Class "G" ± 7210-7220 - 50 sacks Class "G" ± 690-709 - 30 sacks Class "G" ± 4-4 below GL- 10 sacks Class "G" 941079 The First Security Bank P. O. Box 228 Ft. Lupton, CO 80621 L- - IRREVOCABLE STANDBY LETTER OF CREDIT U.S. Environmental Protection Agency Underground Injection Control Financial Responsibility Requirement L To: Regional Administrator C 0 I '11 Environmental Protection Agency Region Q l7 scat coo Co. 8o?AZ (address of EPA Regional Office) t._ Dear Sir or Madam: We hereby establish our Irrevocable Standby Letter of Credit No. 3b' in your favor, at the request and for the account of WRIGHT' S DISPOSAL INC. (legal name of owner or operator) 9270 Ouitman. Westminster, CO. 80030 (business address of owner or operator) up to the aggregate amount of FIVE THOUSAND FOUR HUNDRED AND NO/100 (dollar amount in words) U.S. dollars ($ 5 ,400.00 ), available upon presentation of: • 1 . Your sight draft, bearing reference to this letter of credit No. 3% , and 2. Your signed statement reading as follows: "I certify that the amount t__ of the draft is payable pursuant to regulations issued under authority of the Safe Drinking Water Act." This letter of credit is effective as of (date) 9/24/89 and shall expire on (date at least 1 year later) 9/23/94 but such expiration date shall be automatically extended for a period of (at least one year) 'Five years on (date) ' 9/24/94 and each successive expiration date, unless, at least 120 days before the L_ current expiration date, we notify both you and (owner's or operator's L 9410'79 For Sample Ilse Only cmparable Wording Acceptable I _ ' lame) WRIGHT'S DISPOSAT. TNC. by certified mail that we have I_ decided not to extend this letter of credit beyond the current expiration date. In the event you are so notified, any unused portion of the credit l_ shall be available upon p presentation of your sight draft for 120 days after the date of receipt by both you and (owner's or operator's l.. name) WRIGHT'S DISPOSAL INC. , as shown on the signed return receipts. Whenever this letter of credit is drawn on under and in compliance with the terms of this credit, we shall duly honor such draft upon presentation to us, and we shall deposit the amount of the draft directly into the standby trust fund of (owner's or operator's name) WRIGHT' S DISPOSAL INC in accordance with your instructions. FIRST SECURITY B ltc. d 4.Q,u4:L) 0. IM4LktqlL4-r 81 ?��. (Signet (Date) L (Name) (Title) This credit is subject to: (.61 the most recent edition of the Uniform Customs and Practice for Documentary Credits, published by the International Chamber of Commerce, OR ( ) the Uniform Commercial Code. • L. 9410'79 STANDBY TRUST AGREEMENT U.S. Environmental Protection Agency Underground Injection Control Financial Responsibility Requirement TRUST AGREEMENT, the' "Agreement," entered into. as of 9/26/$9 (date) by and between WRIGHT'S DISPOSAL. INC. (name of owner or operator) a Colorado Corporation , the "Grantor," „(name .of state) (corporation, partnership, association, or proprietorship) and The First Security Bank (X ) incorporated in the ;name of ._orporatf trustees • State of Colorado or ( ) a national bank, the "Trustee." WHEREAS, the United States Environmental Protection Agency, "EPA ," an agency of the United States Government , has established certain regulations applicable to the Grantor, requiring that an owner or operator of an injection well shall provide assurance that funds will be r— available when needed for plugging and abandonment of the injection well, and WHEREAS, the Grantor has elected to obtain ( ) a surety bond ( x ) a letter of credit and establish a standby trust to provide all or part of such financial assurance fcr the facility(ies) identified herein, and WHEREAS, the Grantor, acting through its duly authorized officers, 1 has selected the Trustee to be the trustee under this Agreement, and the Trustee is' willing to act as trustee, . F NOW, THEREFORE, the Grantor and the Trustee agree as follows: r Section 1 . Definitions. As used in this Agreement: r- (a) The term "Grantor" means the owner or operator who enters into this Agreement and any successors or assigns of the Grantor. 941079 (o) The ter- "Trustee" means the Trustee who enters into tnis Agreement and any accessor Trustee. (c) "Facility" or "activity" means any underground injection well or any other facility or activity that is subject to regulation under the Underground Injection Control Program. Section 2. Identification of Facilities and Cost EEstimates. ' Th.Y Agreement pertains to the, facilities and cost estimates identified Schedule A (attached) . (Schedule A lists, for each facility, the EPA identification number, name, address, and the current plugging and abandonment cost estimate, or portions thereof, for which financial assurance is demonstrated.) Section 3. Establishment of Fund . The Grantor and the Trustee hereby establish a trust fund, the "Fund," for the benefit of EPA. The Grantor and the Trustee intend that no third party have access to the Fund except as herein _ provited. The Fund is established initially consisting of the property, 'which is acceptable to the Trust described in schedule B attached hereto. Such property and any otter property subsequently transferred to the Trustee is referred" to as the Fund, together with all earnings and profits thereon, less any payments or distributions made by the Trustee pursuant to this Agreement. The Fund shall be `held by the' Trustee, IN TRUST, as hereinafter provided. The Trustee shall not be responsible nor shall it undertake any responsibility for the amount or adequacy of, nor any duty to collect from the Grantor, any payments necessary to discharge any liabilities of the Grantor established by EPA. Section 4. Payment for Plugging and Abandonment. The Trustee shall make-. payments from the Fund as the EPA Regional Administrator shall direct, in writing, to provide 'for the payment of the costs of plugging and abandonment of the injection wells covered by this Agreement. Trustee shall reimburse the Grantor or other persons as specified .by EPA Regional Administrator from the Fund for plugging and abandonment expenditures in such amounts as the EPA Regional Administrator shall direct in ,writing. In addition, the Trustee shall refund to 'theGrantor such amounts as the EPA Regional Administrator specifies in writing. Upon, refund, such funds shall no longer constitute part of the Fund as defined herein. i Section 5. Payments Comprising the Fund . Payments made to the Trustee for the Fund shall consist of cash or securities' acceptable to the Trustee: 941079 r. Section 6. Trustee Management. The Trustee shall invest and reinvest the principal and income of the Fund and keep the Fund invested as a single fund, without distinction between principal and income, in accordance with general investment policies and guidelines which the Grantor may communicate in writing to the Trustee from time to time, subject, however, to the provisions of this Section. In investing, reinvesting, exchanging, selling, and managing the Fund, the Trustee shall discharge 'his duties with respect , to the trust. fund solely in the interest of the beneficiary and with the care, skill, prudence, and diligence under the circumstances then prevailing, which persons of prudence, acting in a like capacity and familiar with such matters, would use in the conduct of an enterprise of a like character and with like aims, except that: I— (a) Securities' or other obligations of the Grantor, or. any other owner or operator of the facilities, or any of their affiliates as defined in the Investment Company Act of 1940, as amended, 15 USC 80a- 2.(a) , shall not be acquired or held, unless they are securities or other obligations of the Federal or a State government; C (b) The Trustee is authorized to invest the Fund in time or demand deposits of the Trustee, to the extent insured by an agency of the I- Federal or State government; and (c) The Trustee is authorized to hold cash awaiting investment or distribution uninvested for a reasonable time and without liability for the payment of interest thereon. 1 Section 7. Commingling and Investment. The Trustee is expressly authorized in its discretion: (a) To transfer from time to time any or all of the assets of the Fund to any common, commingled, or collective trust fund created by the Trustee in which the Fund is eligible to participate, subject .to all of the provisions thereof, to be commingled with the assets of other trusts participating therein; and (b) To purchase shares in any investment company registered under the Investment Company Act of 1940, 15 U.S.C. 80a-1 et 1m. , including one which may be created, managed, underwritten, or to which investment advice is rendered or the shares of which are sold by the Trustee. The Trustee may vote such shares in its discretion. r- 941079 cxoress :rowers of Trustee. Without in any way limiting the powers and discretions conferred upon tr Trustee by the other provisions of Es Agreement or by law, t. Trustee is expressly authorized and empowered: '' (a) To sell, exchange, convey, transfer, or otherwise dispose of any property held by it, by public or private sale. No person dealing with the Trustee shall be bound to see to the application of the purchase money or to inquire into . the validity or expediency of any ,such sale or other disposition; (b) To make, execute, acknowledge, and deliver any and all. documents of transfer and conveyance and any and all other instruments that may be necessary or appropriate to carry out the powers herein granted; (c) To register any securities held in the Fund in its own name or in the name of a nominee and to hold any security in bearer form or in book .entry, or to combine certificates representing such securities with certificates cf the same issue held by the Trustee in other fiduciary capacities, or to deposit or arrange for the deposit of any securities issued by the United States Government, or any agency or instrumentality thereof, with a Federal Reserve bank, but the books and records of the Trustee shall at all times show that all such securities are part of the Fund; (d) To deposi.. any cash in the Fund in interest-bearing accounts maintained or savings certificates issued by the Trustee, in its separate corporate capacity, or in any other banking institution affiliated with the Trustee, to the extent insured by an agency of the Federal or State government; and (e) To comprom'.se or otherwise adjust all claims in favor of or against the Fund. Section 9 . Taxes and Expenses. All taxes of any kind that may be assessed or levied against or in respect of the Fund and all brokerage commissions incurred by the Fund shall be paid from the Fund'.' :All other • expenses incurred"'Dy the Trustee in conneLLion with the administration of this Trust, 'ii.cluding fees for legal services rendered to the Trustee, the compensation of the Trustee to the extent not paid directly by the Grantor, and all other proper charges and disbursements of the Trustee, shall be paid from the Fund. • 941079 • Section 10. Annual Valuation. Commencing after initial funding of the trust, the Trustee shall annually, at least 30 days prior to the anniversary date of establishment of the Fund, furnish to the Grantor and to the appropriate EPA Regional Administrator a statement confirming the value of the Trust. Any securities in the Fund shall be valued at _ the market value as of no more than 60 days prior to the anniversary date of establishment of 'the Fund. The failure of the Grantor to object in writing to the Trustee within 90 days after the statement has been furnished to the Grantor and the EPA Regional Administrator shall constitute a conclusively binding assent by the Grantor, barring the Grantor from asserting any claim or liability against the Trustee with respect to matters disclosed in the statement. • Section 11 . Advice of Counsel. The Trustee may from time to time consult with counsel, who may be counsel to the Grantor, with respect to any question arising as to the construction of this Agreement or any action to be taken hereunder. The Trustee shall be fully protected, to r the extent permitted by law, in acting upon the advice of counsel. Section 12. Trustee Compensation. The Trustee shall be entitled to reasonable compensation for its services as agreed upon in writing from time to time yith, the Grantor. Section 13. Successor Trustee. The Trustee may resign or the Grantor may replace the Trustee, but such resignation or replacement shall not be effective until the Grantor has appointed a successor trustee and this successor accepts the appointment. The successor trustee shall have the same powers and duties as those conferred upon the Trustee hereunder. Upon the successor trustee's acceptance of the 1— appointment, the Trustee shall assign, transfer, and pay over to the successor trustee the funds and properties then constituting the Fund. If for any reason the Grantor cannot or does not act in the event of the resignation of the Trustee, the Trustee may apply to a court of competent jurisdiction for the appointment of a successor trustee or for instructions. The successor trustee shall specify the date on which it assumes administration of the trust in a writing sent to the Grantor; the EPA Regional Administrator, and the present Trustee by certified mail 10 days before such change becomes effective. Any expenses incurred by the Trustee as a result of any of the acts contemplated by this Section shall be paid as provided in Section 9. Section 14. Instructions to the Trustee. All orders, requests, and instruction by the Grantor to the Trustee shall be in writing, signed by such persons as are designated in the attached Exhibit A, or such other designees as the Grantor may designate by amendment to Exhibit, A. The Trustee shall be fully protected in acting without inquiry in accordance with the Grantor's orders, requests, and _instructions . All orders, requests, and instructions by the EPA Regional Administrator to the Trustee shall be in writing, signed by the EPA Regional Administrators 941079 of the Regions in which the facilities are located, or their designees , and the Trustee shall act and shall be fully protected' in acting in accordance with such 'orders, requests, and instructions. The Trustee shall have the right to assume, in the absence of written notice to the contrary, that no event constituting a change or a termination of the authority of any person to act on behalf of the Grantor or EPA hereunder has occurred. The Trustee shall have no duty to 'act in the absence of such orders; requests, and instructions from the Grantor and/or EPA , except as provided for herein. Section 15. Amendment of Agreement. This Agreement may be amended by an instrument in writing executed by the Grantor, the Trustee, and the appropriate EPA Regional Administrator, or by the Trustee and the appropriate EPA Regional Administrator if the Grantor ceases to exist. Section 16. Irrevocability and Termination. Subject to the right of the parties to amend this Agreement as provided in Section 16, this Trust shall be irrevocable and shall continue until terminated at the written agreement of the Grantor, the Trustee, and the EPA Regional Administrator, or by the Trustee and the EPA Regional Administrator if the Grantor ceases to exist. Upon termination of the Trust, - remaining trust property, less final trust administration expe:.:: < . shall be delivered to the Grantor.. Section 17 . Immunity •and Indemnification. The Trustee shall not incur personal liability of any nature in connection with any act or omission, made in good faith, in the administration of this Trust, cr in carrying out any directions by the Grantor or the EPA Regional Administrator issued in accordance with this Agreement. The Trustee shall be indemnified and saved harmless by the Grantor or by the Trust 1 Fund, or both, from and against any personal liability to which Trustee may be subjected by reason of any act or conduct in its of!' capacity, ,including all expenses reasonably incurred in its defense _.. the event the Grantor fails to provide such defense. Section 18. Choice of Law. This Agreement shall be administered , construed, and enforced according to the laws of the State of COLORADO . Section 19. Interpretation. As used in this Agreement, words in the singular include .the plural and words in the plural include the singular. The descriptive headings for each Section of this Agreement shall not affect the interpretation or the legal efficacy of this . Agreement. J 941079 CERTIFICATE OF ACKNOWLEDGMENT FOR ( STANDBY TRUST FUND AGREEMENT STATE OF COLORADO COUNTY OF WELD On this 26th day of September , 19 89 , before me personally came James S . Wright to me known, who, (owner or operator) being by me duly sworn, did depose and say that she/he resides at 9270 Quitman, Westminster, CO. 80030 (address) that she/he is President of WRIGHT'S DISPOSAL, INC. (title) , the corporation (corporation) described in and which executed the above instrument; that she/he knows the seal of said corporation; that the seal affixed to such instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that she/he signed her/his .-ra.Ce , thereto by like order. (Notary Public) 03/01114,...-0 r l (Seal) 941079 IN WITNESS WHEREOF, the parties below have caused this Agreement to be executed by their respective officers duly authorized and the corporate seals to be hereunto affixed and attested as of the date first above written. By: n(-y / A d (Signature of G tor) nr5/;:iricir -- �J (Title) Attest: /e4 �0�/�, - (Ac€. Peaerewr (Title) (SEAL) By: ' y '�-�--CJ. (Signatuure,, of Trustee) (Title) alYfr Attest: (Title) (SEAL) - • yl 9410751 • SCHEDULE A F' Identification of Facilities and Cost Estimates Schedule A is referenced in the trust agreement dated 9/26/89 F: by and between WRIGHT' S DISPOSAL, INC. (name of owner or operator) the "Grantor," and The First Security Bank (name of trustee) the "Trustee." EPA identification number Name of facility Suckle Farms Injection Well Address of facility. WCR 19 & HQhwv 52 Ft. Lupton, CO. (10-1N-67W) _ Current plugging and . abandonment cost estimate $5 ,400.00 Date of estimate 9/25/89 EPA identification number Name of facility Address of facility Current plugging and abandonment cost estimate Date of estimate • f _. 941079 9/9- estykkUNITED STATES ENVIRONMENTAL PROTECTION/AGENCY ft:cern T1 REGION VIII • 999 18th STREET - SUITE 500 DENVER, COLORADO ;:9020212486 ::: ?: `[I . '" RECEIVED JUN 19 1992 -- s NlroT,ou olwSIQN • JUN 2 31992 Ref: 8WM-DW E9s! 'J9 CD F( HEALTH DEPT. CERTIFIED MAIL RETURN RECEIPT REOUESTED To All Commenters: RE: UNDERGROUND INJECTION CONTROL (UIC) Final Decision: Class I Permit Wright' s Disposal, Inc. Suckla Farms No. 1 Injection Well EPA Permit No. CO1516-02115 Weld County, Colorado Dear Commenter: This letter is in response to your comments concerning the issuance by the Environmental Protection Agency (EPA) of a UIC Class I Permit for the Suckla Farms No. 1 injection well. Enclosed is a Responsiveness Summary which addresses your comments as well as those expressed by other members of the public. Following a review and evaluation of all comments received, it is the decision of EPA to issue a Final Class I Permit to Wright's Disposal, Inc. Please be advised that any 'person who commented on the Draft Permit or participated in the Public Hearing at Greeley has the right to petition the Administrator of EPA for a review of Region VIII's decision to issue the Final Permit. A petition must be submitted within thirty (30) days of receipt of this letter. The procedure for such a petition is described in the enclosed Administrative Review document (40 CFR Part 124.19) . If you have any questions concerning this action, you may contact John. Carson at (303) 293-1435 or Thomas Pike at (303) 293-1544. Also, Blease direct all correspondence to the attention of John Carson at Mail Code 8WM-DW. Sincerely, Thoma J. Pike, Chief . UIC TAmplementation Section • Enclosures � 941079 C;G -P i, / 1 J 1 L Printed on Recycled Paper Ltral . `a'�`t8, UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION VIII 999 18th STREET - SUITE 500 DENVER, COLORADO 80202-2466 RESPONSIVENESS SUMMARY - PUBLIC HEARING: DECEMBER 5 . 1991 UNIVERSI'T'Y OF NORTHERN COLORADO. GREELEY. COLORADO WRIGHT'S DISPOSAL, INC. SUCKLA FARMS NO. 1 CLASS I INJECTION WELL EPA PERMIT NO. CO1516-02115 • WELD COUNTY, COLORADO As a result of significant public interest in the issuance of a Class I Draft Permit to Wright's Disposal, Inc. for the Suckle Farms No. 1 injection well, the Environmental Protection Agency (EPA) conducted a Public Hearing in Greeley, . Colorado, on December 5, 1991. The Public Hearing was conducted by Mr. Al Smith, EPA Region VIII Presiding Officer. Mr. Thomas Pike, Chief of the Underground Injection Control .(UIC) Implementation Section, described the role of the UIC Program. Mr. John Carson, UIC Petroleum Geologist, explained the technical construction and operational issues addressed in the Draft Permit, which had been issued on August 14, 1991. EPA had made the determination to issue the Draft Permit in accordance with the UIC Program regulations, as indicated in the Public Notice which was published in The Denver Post, Longmont Daily Times Call, and Fort Lupton Farmer & Miner on August 21, 1991. During the public notice period following the issuance of the Draft Permit, sixteen (16) commenters expressed their views. in writing concerning the permit. At the Public Hearing, twenty- one (21) members of the public stated their views orally, and thirteen (13) additional comments were received in writing following the Public Hearing. The issues addressed and the number of comments received on each issue during the public notice period following issuance of the Draft Permit, as well as during and following the Public Hearing are listed in Table 1. 941079 Printed on Recycled Paper • • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 2 TABLE 1 . SUMMARY OF ISSUES AND COMMENTS Source of Comments Issues and Comments Written Oral Total Requests for a public hearing 9 9 • A Weld County permit should also be 3 5 8 required Colorado Oil and Gas Commission 2 2 lacks authority for injection wells The lease agreement with the landowner 8 9 17 specifies disposal of brine water only . Regulatory authority at the surface 1 1 above the well head Risk assessment for land use, waste 2 2 injection and transport to the well Dust created by truck traffic on roads 7 6 . 13 Speeding trucks-safety of children 3 3 Brine spills on roads from trucks 10 8 18 Brine spillage at the well site 1 7 8 Wright' s has been poor operator of 6 4 10 the injection well to date Injection wells are unsafe-technology 3 5 8 still considered to. be poor Fluids other than brine have been 1 1 2 injected in the well Nonhazardous fluids to be injected 5 3 8 have not yet been identified Injected nonhazardous fluids may 2 . 2 react with brine in the injection zone Possible contamination of ground water 18 2 20 and water wells due to injection 941079 Wright' s Disposal, Inc. Class I Injection Well - Responsiveness Summary Page 3 (TABLE 1, Continued) Issues and Comments Written Oral Total Abandoned coal mines in the area provide 4 4 8 a path for injected fluids to ground water Abandoned oil wells in the area provide 4 4 path(s) for injected fluids to ground water Faults in the area provide path for 1 4 5 injected fluids to ground water zones Faults in the area may initiate seismic 13 8 21 (earthquake) activity from injection Possible future movement of injected ' 4 4 8 fluids away ,from the well site Operator's surety bond does not 2 7 9 cover damage from surface spills Request that the comment period 1 1 following hearing be extended Injection of fluids during an appeal 1 1 of a final permit decision - Determination of nonhazardous and 2 2 hazardous waste fluids Monitoring of injected fluids and 11 11 frequency of sampling Payment of damages from catastrophic 2 2 events related to injection operations Future change of well classification for 1 1 the disposal of hazardous waste fluids Permitting of additional disposal wells 1 1 Monitoring of the well following termination 1 1 of injection of Class I fluids Devaluation of property values in the area 1 1 • TOTAL COMMENTS 209 941079 • • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 4 RESPONSE TO ISSUES AND COMMENTS : COMMENT: Requests for a public heari g. During the public notice period following the issuance of the Class I draft permit for the Suckla Farms No. 1 injection well, nine written requests for a public hearing were received. RESPONSE: EPA conducted a public hearing during the evening of December 5, 1991, in the University Center at the University of Northern Colorado, Greeley, Colorado. COMMENT: A Weld County permit should also be required. Several commenters indicated that the disposal well is subject to state, county, and local permits, and that EPA should not issue a UIC permit until approval is obtained from all regulatory entities. RESPONSE: Part III, A. of the UIC permit states - -- "Issuance of this permit does not convey property rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. " EPA' s decision to issue the permit in no way diminishes the obligation of the permittee to comply with all applicable state and local requirements. No change in the draft permit was made in response to these comments. • COMMENT: Colorado Oil and Gas Conservation Commission lacks authority for injection wells. Several commenters stated that the Colorado Oil and Gas Conservation Commission was not authorized to regulate injection wells in Colorado. RESPONSE: On April 2, 1984, the Commission was granted primacy by EPA to regulate Class II injection wells in Colorado, except on Indian Lands. The Suckla Farms No. 1 well was permitted as a Class II injection well by the Commission on August 2, 1989, for the disposal of waste oil field fluids and has injected waste fluids from oil and gas operations since being permitted. Under the state permit the well is authorized to receive produced fluids, drilling fluids, waste well completion, treatment and stimulation fluids, gas plant dehydration waste, gas plant sweetening wastes, and any other fluids associated with the primary production of oil and gas . These fluids are usually combined at the point of origin and transported to a disposal site as "produced water" or "oil field exploration and production waste. " • Authority •€or Class I injection wells in Colorado, however, remains under EPA jurisdiction. In order to inject nonhazardous fluids from non-oil and gas production operations, • - 941079 • Wright' s Disposal, Inc. Class I Injection Well . Responsiveness Summary Page 5 a Class I permit is required. When EPA issues a Class I non- hazardous permit, the Suckla Farms No. 1 will remain authorized as a Class II well until it completes the conditions of the Class I permit issued by EPA and begins to inject under the authority of the EPA permit. CO7T: The lease agreement with the landowner specifies disposal of brine water only. Several commenters indicated that the permit should not be issued because the lease covering the site facilities and operation does not specifically mention the disposal of industrial fluids. RESPONSE: The EPA's issuance of this permit does not constitute a binding legal determination concerning the rights, privileges, duties, and liabilities of the parties of the lease. According to 40 CFR Section 144.51 (g) , the EPA' s permit does not convey any property rights of any sort or any exclusive privilege. It is • the responsibility of the operator to assure right of access to dispose on nonhazardous industrial waste. EPA believes that the issue of right of access for the purpose of disposal is between the operator and the landowner. EPA' s review of the information submitted indicates that the permittee's right of access to dispose of waste not generated from oil or gas production does not appear to affect the ability of the operator to access the leased facility to carry out required monitoring and downhole testing of the well. Although EPA' s permit decision does not determine whether the applicant' s lease allows disposal of Class I fluids, it appears prima facie that the applicant's lease does not prohibit access for the purpose of complying with any of the environmentally protective provisions of this permit. EPA reiterates that obligations under the permit are binding on the permittee regardless of any dispute concerning the permittee's right of access to the well site and that it is the permittee's responsibility to arrange for whatever access is necessary to prevent violations of the permit. EPA . will not recognize questions regarding the right of access as a defense to any instance of noncompliance. No change to the draft permit was made in response to these comments. COMMENT: Regulatory authority at the surface above the well head. Several commenters indicated that EPA should utilize its UIC Regulatory authority, under 40 CFR 144.52 (a) (9) , to require a liner under the surface storage tanks and truck unloading area. The commenters also wanted ground water monitoring for the detection of spills to be performed under the authority of 40 CFR 144.27 (b) (1) . 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 6 RESPONSE: The primary concern relating to surface facilities was seepage into shallow ground water zones as a result of truck spills, leaking tanks, etc. Commenters were especially concerned that such seepage' would contaminate their major drinking water source, the Laramie-Fox Hills aquifer. A review of data indicates that surface activities such as spillage could not affect the Laramie-Fox Hills aquifer because of its depth and hydrologic conditions . However, because surface spillage and leaks could impact shallower sands in the vicinity, EPA has modified the permit to require that the operator obtain an environmental audit using a third party contractor (designated by EPA) from a list furnished by the operator twice a year. The audit will look at the operation of the facility to determine if it poses a problem to shallow ground water sands and surface water. The results of the audit and EPA inspections will be utilized in determining if: 1) action under conditions of the permit is warranted; 2) a change in the permit is warranted; or 3) action under Section 1431 of the Safe Drinking Water Act (SDWA) is warranted. EPA agrees that the authority of 40* CFR 144.52 (a) (9) does apply to surface activities in addition to the well head, such as plant leaks and spillage that could result in migration into underground sources of drinking water (USDW) ; however, the review of information on the facility indicates that the truck unloading tanks and berm are adequate for containing spillage. Thus, EPA has determined that no changes relating to well construction or the facility are needed to assure that migration of injected fluids into USDWs is prevented. The permit has, however, been modified to require the operator to properly maintain and operate the facility, including pumps, piping, tanks, and the unloading station to prevent surface spillage. The operator will be required to report and repair any problems. It is important to stress that the requirements of 40 CFR 144.27 apply only to requesting additional information relating to existing rule-authorized facilities to determine if the well may be endangering an underground source of drinking water. The Suckle Farms No. 1 well is, of course, not a rule-authorized well. Thus, the authority under 144.27 is not relevant. COMMENT: Risk assessment for land use, waste injection and transport to the well. Commenters expressed concern regarding a variety of surface impacts and suggested development of a risk assessment or an environmental impact statement. RESPONSE: 40 CFR 124.9 (b) (6) states " . . .UIC. . . permits are not subject to the environmental impact statement provisions of Section 102 (2) (C) of the National Environmental Policy Act, 42 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 7 U.S .C. 4321. " The Statement of Basis, which is issued with a draft permit and this Responsiveness Summary, are the functional equivalent of an environmental analysis of the proposed j.niection activities . It is, however, important to emphasize that the regulations of other federal and state programs such as the National Pollutant Discharge Elimination System (NPDES) may apply. If such regulations are or become applicable they must be • observed. The regulatory requirements for Class I and Class II Injection wells are based on the assumption that Class I wells have a higher risk than Class II wells . Hence, the construction, operating, and reporting standards for a Class I (nonhazardous) well are more stringent as a way to offset the risk. - No change was made to the draft permit in response to these comments. COMMENT: Dust created by truck traffic on roads; Speeding trucks -safety of children; Brine shills on roads from trucks; and Brine spillage at the well site. Several commenters expressed concern regarding surface impacts from truck traffic such as dust, and brine spills on the roads and brine spills at the well. RESPONSE: The primary purpose of the UIC Program is the protection of underground sources of drinking water. To EPA' s knowledge, EPA' s authority to regulate non-groundwater impacts by means of UIC permits has not been addressed in reported case law. Notwithstanding the issuance of this permit, it will remain the • permittee's responsibility to comply with all federal, state, • and local environmental requirements. A major environmental concern relating to surface facilities was seepage into shallow ground water zones from truck spills, leaking tanks, etc. Commenters were especially concerned that such seepage would contaminate their major drinking water source, the Laramie-Fox Hills aquifer. Statements made at the public hearing indicated the Laramie aquifer surfaced within 3 miles of the well where it is recharged. A review of information from the U.S. Geological Survey and the Colorado Division of Water Resources indicates that the Laramie-Fox Hills aquifer does not recharge in the vicinity of the well. Flow in the Laramie-Fox Hills is to the northeast, where the aquifer discharge area is located about 8 to 10 miles away. Even in the discharge area the Laramie aquifer is not exposed at the surface. The aquifer within a radius of at least 8 miles is confined under artesian pressure. Thus, water in the aquifer has an upward component of flow, which prevents downward migration of water through the silts and shales which overlie the aquifer. The closest point at which fluids could enter the Laramie-Fox Hills is on the edge of its northern outcrop near Platteville where it discharges . The aquifer has become partially saturated in that area in response to local pumping, and is no longer under artesian pressure. More 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 8 information on the Laramie-Fox Hills aquifer can be obtained in the Hydrologic Investigations Atlas No. HA-650, "Geologic Structure, Hydrology, and Water Quality of the Laramie-Fox Hills Aquifer in the Denver Basin, Colorado" published by the U.S . Geological Survey. Although available data. indicate that surface spills at the site do not pose a threat to the Laramie-Fox Hills, there are shallower aquifers overlying the Laramie-Fox Hills (such as shallow alluvial aquifers of limited extent) . EPA's review of information on the facility indicates that the truck unloading tank and the berm around the area are adequate for containing spillage. Proper maintenance of the facility, especially the unloading facility, will be an ongoing item for planned • inspections and audits. If EPA learns of any surface problems that could endanger shallow 'drinking water wells, EPA could seek appropriate relief to the extent allowed by applicable statutes and regulations, e.g. , Section 1431 of the SDWA. This relief would stipulate any monitoring and corrective action deemed necessary to eliminate the problem and prevent further occurrences. As indicated in a previous response, the permit has been modified under the general provision of the permit which stipulates adequate maintenance and operation of the facility. As to surface impacts that do not relate to groundwater, e.g. , dust, truck traffic, safety, these are primarily regulated by state and county authorities. EPA would reiterate that irrespective of this permit, the permittee has an obligation to comply with all state and local requirements. No change to the draft permit was made in response to these comments. COMMENT: Wright's has been Door operator of the injection well to date. Several commenters provided anecdotal information regarding on.-site spills and operational problems at the well. RESPONSE: The Suckle Farms No. 1 well has operated as a Class II injection well since. July, 1989, as authorized by the Colorado Oil and Gas Conservation Commission (COGCC) . Any complaints regarding on-site problems during the period covering 1989 to the present would be handled by COGCC staff. To determine the extent of actual reported problems at the facility, EPA requested information from COGCC pertaining to Wright's compliance history as the operator of this well. The Commission has conducted inspections at the facility eight times since 1989; two inspections were for the purpose of verifying repairs of the injection tubing, and two inspections were related to a citizen complaint. The. citizen complaint concerned surface runoff of brine water from- the well site onto adjacent fields. The operator was instructed to correct the situation and promptly 941079 • • • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 9 complied. The two inspections relative to tubing repair dealt with a hole in the tubing and a leaking tubing collar. These tubing problems were noted by the operator, reported, and promptly repaired. As a result of the two incidents relating to the injection tubing, the operator decided to switch over to lined tubing to avoid a recurrence of the problem. The other four visits were normal compliance inspections during which no instances of noncompliance were noted. Based on this information, EPA concludes that the well operator has been operating the well in a prudent manner, and no changes were made to the draft permit. COMMENT: Infection wells are unsafe-technology still considered to be poor. Several commenters opposed the issuance of a UIC Permit for the disposal of nonhazardous waste on the grounds that experience indicates that injection wells are an unsafe method to • dispose of fluids . RESPONSE: There are over 170, 000 deep injection wells in the United States associated with the production of oil and gas. As of 1990, there were /75 Class I hazardous waste wells at 85 facilities and 310 nonhazardous Class I wells in operation in the United States . Based on numerous studies from 1985 to 1988 carried out as part of an effort to modify Class I well construction, operating, and monitoring regulations, the EPA believes that injection wells are environmentally safe when properly constructed, operated and monitored according to the requirements of the UIC Program. As discussed in the studies, the construction and testing methods utilized for drilling and completing both Class I and Class II wells have improved dramatically since the early days of underground injection. Data in the studies indicate that the construction and testing standards used today are adequate to prevent problems if a well is operated as designed. These studies are referenced in the "Technical Overview of the UIC Program" by Paul Osborne which was handed out at the public hearing. Additionally, the Office of Emergency and Remedial Response conducted a study in 1989 to look at the comparative risks posed by various waste management practices. This study involved experts in: acute events, health effects, ecological effects, welfare (resource impacts) effects, ' and ground water impacts. The results of this effort were published in November, 1989, in EPA/540/1-89/003 as "Executive Summary and Overview-OSWER Comparative Risk Project. " The results of this study indicate that the risk of underground injection of waste is low. The low risk is based on current construction practices, well testing and well monitoring standards, and on the criteria for assuring adequate containment of the injection. reservoir. A copy of the Summary Table from • • 9410'79 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 10 this study, comparing risks associated with various waste management practices, is attached as Exhibit A. No change to the draft permit was made in response to these comments . COMMENT: Fluids other than brine have been injected in the well. Two comments were received stating that fluids other than oil field brine have been injected in the Suckla Farms No. 1 well. RESPONSE: Information obtained from the applicant and from COGCC inspections indicates that material injected in the Suckla Farms No. 1 well to date has been limited to fluids produced in conjunction with oil field operations, primarily produced water. These _.fluids may, however, include associated oil field wastes such as workover fluids and gas plant waste from oil and gas production in surrounding oil fields (these fluids are commonly referred to generically as "oil field exploration and production waste" , "salt water" , or "brine") . The general categories presently defined as Class II fluids are: 1) Produced water from oil and gas production; 2) Waste fluids from the actual drilling operation; 3) Pigging fluids from the cleaning of collection and injection lines within the field; 4) Used workover and stimulation fluids recovered from - production, injection, and exploratory wells; 5) Gas, such as methane, CO2 or nitrogen used for enhanced recovery/pressure maintenance of production reservoirs; 6) Brine reject from water softeners associated with enhanced recovery; 7) Waste fluids from methane sweetening and dehydration, which is blended with produced water, as long as it is not hazardous at the point of injection; 8) Waste fluids from circulation during well cementing; 9) Waste oil and fluids from cleanup associated with primary production (but not the transportation) of oil within the oil field; 10) Fresh water used for enhanced recovery makeup; and 11) Water containing chemicals such as polymers for the purpose of enhanced recovery. The operator presently obtains laboratory analyses of injected fluids on a bi-weekly basis which indicate that the brine contains small amounts of benzene, toluene, ethylbenzene, and xylene. It is important to emphasize that oil field wastes, such as produced water, may sometimes contain levels of benzene which are in excess of criteria established by the toxicity characteristics rule of the Resource Conservation and Recovery Act (RCRA) , covered by 40 CFR 261. .These substances, however, 941079 • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 11 are normal constituents of oil field production and development wastes, and are classified as exempt wastes under RCRA regulation 40 CFR Section 261.4 (b) (5) . Thus, oil field waste would not be defined as a hazardous waste regardless of benzene levels. - Several commenters suggested applying the standards for injection of hazardous waste to the Suckla Farms No. 1 well because of the presence of benzene, under authority of 40 CFR 144 .52 (a) (9) . Because the fluids presently going to the well do not meet the definition of hazardous waste, RCRA Subtitle C requirements do not apply. However, the construction of the well and the proposed monitoring program are considered adequate to protect USDWs from all injected wastes, including those exempted from RCRA; therefore, no additional construction or monitoring requirements are warranted to prevent the migration of injected fluids out of the injection zone. No change to the draft permit was made in response to these comments. COMMENT: Nonhazardous fluids to be infected have not yet been identified. Several commenters were concerned that the types of nonhazardous fluids to be injected in the Suckla Farms No. 1 well were not specifically identified in the draft permit. RESPONSE: The Class I Draft Permit for the Suckla Farms No. 1 • well specifies that all sources of fluids proposed for. injection must be analyzed prior to injection. EPA will then determine if the fluids. are nonhazardous or hazardous according to RCRA regulations. Fluids presently identified for disposal at the Suckla Farms No. 1 may contain low levels of constituents which may be toxic at certain levels. Although many waste streams contain toxic constituents, the fluids may not meet the definition of hazardous waste under Subtitle C of RCRA. A waste may be defined as hazardous if: 1) it is not exempt from definition of a hazardous waste; 2) it fails one of four characteristic tests; or 3) it is a listed waste. Waste streams which do not meet the definition of a hazardous waste are pot regulated under Subtitle C of RCRA and may be injected into a . Class I nonhazardous waste well, even if constituents which may be considered toxic are present. The operator will be authorized to inject only fluids that are classified as nonhazardous . To date, the only identified nonhazardous industrial fluids proposed for injection are: fluid recovered during the clean up of leaking underground storage tanks; water from oil field wash pits; and contaminated water from construction sites. These fluids are classified as nonhazardous industrial wastes, but as previously stated, the wastes will be analyzed to ensure that nothing hazardous is injected in the well. 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 12 The permittee is required to maintain records for three years concerning: (1) the location, date and time, and type of fluids to be delivered to the injection well; (2) laboratory analysis of the composition of the fluids, including all physical, chemical, radiological, and biological constituents; and (3) all monitoring records of injection pressures and volumes of fluids injected. These reports and records are to be submitted Eo EPA for review and approval. In addition, EPA will conduct at least one inspection of the facility per year during which fluids being injected will be sampled. No change to the draft permit was made in response to these comments. COMMENT: Injected nonhazardous fluids may react with brine in the infection zone. Two comments concerned the possibility of toxic reactions within the injection zone as a result of mixing nonhazardous fluids with the native formation fluids. RESPONSE: Adverse reaction between injected nonhazardous fluids and brine water in the Lyons injection zone, possibly resulting in the formation of toxic substances, is not anticipated. The permit does not allow injection of any wastes classified as "hazardous" under 40 CFR Part 261. Any waste that is classified as "reactive" under 40 CFR Section 261.23 is considered "hazardous" and therefore is not authorized to be injected under this permit. At the well site, the nonhazardous fluids are to be commingled with brine in holding tanks prior to injection; sampling of the commingled fluids will also verify overall compatibility with reservoir fluids. Analyses of the data submitted indicate that most of the proposed injection fluid is similar in composition to the native formation water. Additional studies performed for EPA by several universities (between 1985 and 1990) indicate that over time, complex organic compounds react under the high temperature and pressure found in deep reservoirs to become simpler and less toxic compounds (see Assessing the Geochemical Fate of Deep-Well Injected Hazardous Waste: USEPA Office of Research and Development, June, 1990: EPA/625/6-89/025a) . Thus, small traces of organics being injected into this well, such as benzene, will undergo degradation with time. No change to the draft permit was made in response to these comments. COMMENT: Possible contamination of ground water and water wells due to injection. Numerous comments .were received regarding the potential for contamination of shallow ground water zones and domestic water wells in the vicinity of the Suckla Farms No. 1 well as a result of injection operations. 941479 • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 13 RESPONSE: The underground sources of drinking water (USDW) in this area are within the Arapahoe and Laramie-Fox Hills Formations, which extend to a maximum depth of 700 feet below ground surface. These USDWs are isolated from the weilbore by cemented surface casing, which is set at a depth of 759 feet in the underlying Pierre Shale. The Pierre Shale is a major regional impervious confining zone some 6, 600 feet in thickness . Within the surface casing is a second casing (long string) which extends from the surface to the total depth of the well; inside the long string casing is the tubing through which the injected fluids flow to the injection zone in the Lyons Formation. The base of the tubing is anchored in the long string casing by a packer set at a depth of 9 , 240 feet, just above perforations in the casing at the injection zone. The diagram attached as Exhibit B provides the construction details and indicates the depths of the major geologic units. Immediately overlying the porous Lyons Sandstone injection zone is a confining zone composed of 300 feet of impervious shales and interbedded siltstones. A confining zone below the injection interval is also composed of impervious shales . The long string casing is cemented throughout the confining zones, with cement extending 880 feet above the injection interval as verified by a cement bond log. The bond log indicated that the cement appears to have adequate strength and bonding to isolate the injection zone. Thus, this method of well completion assures that all injected fluids enter and remain within the injection zone, and therefore, are not expected to migrate into USDWs. Upon completion of the Suckla Farms No. 1, the static fluid level of the Lyons Sandstone injection reservoir was determined in order to estimate the existing reservoir pressure. The reservoir fluid level at that time was 1,562 feet below ground surface which is 862 feet below the base of the Laramie-Fox Hills aquifer (base of USDWs) . This indicates that the Lyons is a very underpressured formation and is not being actively recharged. Thus, water from the Lyons would not be expected to flow upward via an unplugged well into the Laramie-Fox Hills or overlying aquifers under pre-injection (static) condition. In fact, the direction of flow would be from the Laramie into the Lyons. • Prior to receiving approval from EPA to commence injection, confirmation of reservoir confinement must be obtained by conducting downhole tests designed to detect any escape of fluids from the injection interval, or breach of the confining zones . These tests include a mechanical integrity pressure test, an oxygen-activation log, and temperature log performed at the time the well is initially permitted. Thereafter, mechanical integrity pressure tests of the well must be repeated at two-year 94107 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 14 intervals, and a radioactive tracer survey or temperature log must be performed at least every five years. The tests will be witnessed and evaluated by an EPA representative; any indication of well failure will result in the immediate shut-in of the well until appropriate repairs are made. Additionally, the operator will be required to maintain a positive pressure on the casing/tubing annulus utilizing a continuous pressure recorder. Failure of the tubing, casing or packer will result in a significant loss in pressure which will be noted by monitoring. In the event of failure, the operator must shut-in the well, notify EPA, determine the nature of the problem, and take appropriate measures to correct the problem. No change to the draft permit was made in response to these comments. COMMENT: Abandoned coal mines in the area provide a path for infected fluids to ground water. Several commenters expressed concern about abandoned coal mines, such as those near Erie, Colorado, and the potential for mines to act as pathways into overlying underground sources of drinking water. RESPONSE: Abandoned mines are confined to coal seams within the Upper Cretaceous Laramie Formation which occurs at a depth of approximately 250 feet; the Laramie overlies the Fox Hills aquifer. Therefore, the mines are much shallower than the Lyons injection zone, being separated by over 8,500 feet of intervening rock strata consisting mainly of shales. Furthermore, abandoned mines, as mapped by the USGS, are located at least five miles to the west of the injection well site. Based on a review of the information, EPA has concluded there is no connection between the mines and the Lyons Formation in the vicinity of the well, and no change was made to the draft permit in response to these cO ments. COMMENT: Abandoned oil wells in the area provide path(s) for injected fluids to ground water. Commenters expressed concern about the potential for movement of injected fluids out of the . injection zone via abandoned or improperly completed wells in the vicinity of the Suckla Farms No. 1 facility. RESPONSE: The applicant submitted information on deep wells within a 1/4-mile area of review (AOR) surrounding the Suckla Farms No. 1 well which was used in the initial stages of investigation. Subsequently, EPA obtained additional data from public files. Oil wells in the vicinity of the Suckla Farms No. 1, including abandoned, active injection, and producing wells, do not penetrate to the depth of the Lyons injection zone. Total depths of.. the deepest wells within a one-mile radius of the Suckla Farms No`. 1 are approximately 1, 000 feet above the depth of the Lyons. There are no water wells in the area which are 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 15 deeper than 700 feet. EPA has reviewed the files of the Colorado Oil and Gas Conservation Commission (COGCC) to determine the completion status of all wells (including recent completions) within a ten-mile radius of the injection well. This review indicates there are no wells that penetrate to the depth of the Lyons. A copy of the completion status (as of January, 1992) of all wells in the same township (36 square miles) has been included in the official record. Also included in the official record is a •copy of a listing of all of the Lyons completions in Weld County and their status. The closest completion reaching the Lyons Formation is approximately 16 miles north of the Suckla Farms No. 1 well. As a result of the review of the files of the COGCC of all wells which penetrate the Lyons, EPA has concluded that abandoned oil wells do not provide an avenue for fluid migration. No change to the draft permit was made in response to these comments . COMMENT: Faults in the area Provide path for injected fluids to ground water zones. Several commenters expressed concern that known faults in the area of the injection well could provide a pathway for injected fluids to migrate upward from the injection zone to shallow ground water zones. • RESPONSE: Approximately two miles to the west of the injection well, a series of northeast trending faults has been mapped at • the surface. Extensive geophysical seismic data and well control throughout the area reveal that the subsurface extent of these faults is to a depth of approximately 5, 000 feet, where they terminate in bedding planes of the Pierre Shale. The base of this thick shale section at the injection well is at a depth of 7, 360 feet, ,or some 2, 000 feet above the Lyons injection zone. Correlation of the electrical log of the Suckla Farms No. 1 well with logs of nearby wells does not reveal any significant amount of missing section that would indicate the presence of faults. If faults do exist in the immediate vicinity of the injection well, they would be quite small in nature, and as such, would not present a significant threat regarding the possible escape of injected fluids from the Lyons injection zone through overlying confining strata. No change to the draft permit was made in response to these comments. COMMENT: Faults in the area may initiate seismic (earthquake) activity from injection. Commenters referred to the history of the deep well at the Rocky Mountain Arsenal where injection increased the frequency of small magnitude earthquakes (most of these earthquakes were less than 3.0 on the Richter Scale) . Commenters were' concerned that injection into the Suckla Farms No. 1 disposal well would also result in earthquakes . 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 16 RESPONSE: As discussed in the paragraph above, significant faulting in the vicinity of the Suckla Farms No. 1 is not indicated. Therefore, all injected fluids will enter and remain confined within the Lyons injection zone. In order to initiate seismic activity, the fluids, which are injected under pressure, would have to flow preferentially in one direction such as along a fault plane or fracture system. The earthquakes associated with the Rocky Mountain Arsenal well were caused by preferential flow. The Arsenal injection well was completed in the fractured granite basement rock which had no porosity or permeability, other than that provided by fractures. The high injection pressure initiated movement along the fractures resulting in : ow magnitude earthquakes. The Lyons injection reservoir is a traditional porous sandstone reservoir in which one directional preferential flow is not likely. Reference was also made to a letter (February 9 , 1990) from William P. Rogers of the Colorado Geological Survey regarding earthquakes caused by injection into faults, and the potential for similar problems with the Suckla Farms No. 1 well which had commenced injection under a Class II permit from the Colorado Oil and Gas Conservation Commission (COGCC) . Mr. Rogers indicated that in the absence of details on the intensity and orientation of fractures and faulting at depth, a microseismic monitoring program could be initiated at the site. A two year period of monitoring was recommended. This would allow for the assessment of subsurface fractures which could cause problems as a result of injection. No action was taken as a result of the letter, as the COGCC made a determination that no changes in permit conditions were warranted. Reliance on regional seismic monitoring was deemed adequate for determining if a problem is occurring. The United. States Geological Survey (USGS) operates a seismic monitoring station out of Golden, Colorado which is capable of detecting earthquakes within the Front Range corridor. This seismic monitoring network will allow precise location of any earthquakes with a magnitude of 2.5, and an approximate location for those quakes with a magnitude of less than 2.0. Injection into the Lyons formation at. the Suckla Farms No. 1 has occurred for nearly three years with no reported seismic problems. Additionally, there are numerous wells in the area injecting into the Dakota Sandstone (a similar type reservoir) with no problem. EPA reviewed the earthquake data for the area within a radius of 300 kilometers of the Suckla Farms No. 1 disposal well for a period covering the past five years. This review indicated there was no significant seismic activity in the vicinity, of the well either before or after injection commenced. 'EPA has concluded that site specific seismic monitoring is presently unwarranted, given the absence of 941079 • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 17 increased earthquake activity in the vicinity of the well. If earthquakes began occurring in the vicinity of the well, EPA would require the operator to install local seismic monitoring equipment to determine if the activity is associated with the injection well. A specific provision of the permit is that a pressure fall- off test is to be performed prior to operation as a Class I well, with subsequent tests performed on an annual basis . These tests are designed to reveal if the injected fluids are flowing outward from the wellbore in a uniform manner as anticipated, or are flowing predominantly in a preferred direction. No changes to the draft permit were considered necessary in response to these comments. COMMENT: Possible future movement of injected fluids away from the well site. Several commenters were concerned about the potential for the movement of injected fluids beyond the designated 1/4-mile area of review (AOR) surrounding the injection well, at the present time as well as following the termination of injection operations. RESPONSE: The distance outward from the wellbore of the injected fluids (injection plume) , and possible movement of the plume away from the injection site in future years have been assessed. The initial phase of the analyses was to calculate the volume of native fluid which could be displaced from the Lyons reservoir within the 1/4-mile fixed AOR provided by the regulations [40 CFR 147.305 (e) ] . The total volume of voids or pore space in the Lyons Sandstone available for displacement with injected fluid within a 1/4-mile radius surrounding the wellbore, was calculated by using an average porosity value of 6% and the perforated Lyons Sandstone interval which is 142 feet. A reservoir porosity of 6% is considered conservative and was obtained from the density log of the well. Information obtained from a Lyons Sandstone enhanced oil recovery project indicates that porosity can be 9% or greater. The total thickness of the Lyons Sandstone zone showing porosity is greater than 200 feet; however, the thickness of only the perforated interval was used for reservoir volume calculations to give a conservative estimate of reservoir storage. This calculation indicates that approximately eight million barrels of fluids can be contained within the AOR, assuming no movement of fluid due to formation flow. To date, 1.2 million barrels of brine have been injected, leaving a remaining capacity of 6.8 million barrels. The operator' s proposed rate of injection (brine plus nonhazardous fluid) is less 'than 1,700 barrels per day. This rate of injection, if consistently maintained, will amount to a 941079 • • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 18 cumulative volume of 6 .2 million barrels of fluid over a period of ten years for which the Class I permit is issued. This volume of fluid, plus the volume of brine already injected, is less than the 8 million barrel capacity of the AOR. Assuming completely radial flow, a porosity of 6%, and a thickness of 142 feet, injection in the Suckla Farms No. 1 for approximately 13 years will displace native reservoir fluid from an area around the well with a radius of 1, 300 feet. An indication of the lateral extent • of the plume will also be monitored by periodic pressure fall-off tests. Additionally, these tests will provide more data on reservoir permeability which can be used to re-assess reservoir pressura changes away from the well. Thu total volume of infected fluids is not expected to move much beyond the AOR following termination of injection operations . In order for an injection plume to move much beyond the immediate vicinity .(AOR) of an injection well, there must be active flow within the injection zone. The rate of flow would be dependent on reservoir permeability and the hydraulic gradient. The permeability is a function of the makeup of the reservoir, while the hydraulic gradient is. the driving force that causes water to move and is a function of the amount of recharge entering the unit and the amount of discharge from the unit. At the 9,300 foot depth of the Lyons Sandstone at the Suckla Farms No. 1, the rate of fluid movement is limited for the following reasons: (1) the nearest surface exposure or recharge area of the Lyons Sandstone is along the base of the Front Range, approximately 25 miles west of the well. Surface recharge exerts very little influence over this great a distance; (2) geophysical data indicate the well is located near the structural axis or deepest part of the Denver basin, where no wells have been drilled to the Lyons, and therefore, no formation waters have been withdrawn; (3) actual recharge to and discharge from the Lyons Formation appears to be very limited. The reservoir conditions encountered when the well was drilled provide evidence that recharge and fluid movement associated with the formation are limited. The Lyons reservoir was very underpressured when • the well was initially drilled and completed, as indicated by the reservoir fluid level which was 1,562 feet below ground surface. This contrasts with the artesian aquifers, w'iich serve as USDWs in the area and which flowed at the surface when they were initially developed. The nearest well that penetrates the Lyons is over 16 miles away and beyond any area of influence surrounding the injection well. Additionally, data from the COGCC indicate there is little production of oil and water from the Lyons in Eastern Colorado. There are 14 active and shut-in Lyons producing wells in Weld County, and there is little or no oil and water production from the Lyons in other counties . 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 19 Thus, man-made discharge from the Lyons is insignificant; (4) the permeability of the Lyons reservoir is low. The permeability of the reservoir is approximately 10 millidarcies (md) or 2 .72 X 10'' ft/day. This estimate is based on data from the wells in the Pierce Unit, the analysis of drill cuttings, and pressure buildup calculated using injection volume and reservoir pressure buildup data from the Suckla Farms No. 1 collected since injection commenced; (5) the Lyons Formation has a very small change in elevation with distance from the well. The unit slopes upward to the east at about 1 degree, and does not outcrop. The absence of a surface discharge area and significant pumpage indicate that pressures within the Lyons Formation have long since reached equilibrium; and (6) the volume of fluids intended for injection during the permitted life (10 years) of the well is • insignificant compared to the existing volume of fluids already in place. In summary, available data indicate that the hydraulic gradient within the Lyons is very small, resulting in a very low rate of ground water movement under natural conditions. The small volume of injected fluids compared to the existing volume of native fluid in storage and the absence of nearby pumping will result in a return to equilibrium conditions in a very short time after injection ceases. A second phase of reservoir analyses was utilized to evaluate the impact of the injection activity on the Lyons reservoir. This involved use of the reservoir pressure buildup equation (see report on "Radius of Pressure Influence of Injection Wells" by Don L. Warner, EPA-600/2-79-170, August, 1979) to calculate the change in reservoir pressure as a result of operation of the well. An injection rate (1, 625 BPD) for the entire life of the well (4, 600 days) including operation of the well to date was used along with estimated permeability (10 md) and porosity (0 . 06) to estimate the increase in reservoir pressure at' certain distances from the well. The most significant estimated pressure increases occur within one-half mile of the Suckla Farms No. 1. At a radius of 1/4-mile, the pressure is estimated to increase by about 500 psi. At this radius, the pressure increase would result in fluid movement through an open well completed in the Lyons to a level which is approximately 250 feet above the base of the lowermost USDW. At the radius of one-half mile, however, the pressure increase is estimated to be in a range between 150 and 350 psi. This would cause fluid to rise at that radius to a level which is below the base of the lowermost USDW. 941079 Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 20 The impact of injection activity drops off quickly beyond a radius of one mile. The estimated pressure increase at 4 miles is less than 100 psi, while the estimated increase at 10 miles is less than 25 psi. The hydraulic gradient beyond 10 miles will be essentially undisturbed during injection. Although the hydraulic gradient near the well will be greater than normal during injection, the pressure will undergo a rapid fall in pressure after cessation of the project. The gradient will approach normal within a very short interval. Also, as noted earlier, there are no wells penetrating the injection zone within one mile of this well . In response to the comments received and a re- evaluation of the capacity of the AOR surrounding the well, the draft permit has been changed to limit the cumulative volume of injected brine and nonhazardous fluids to 8,300, 000 barrels, during the 10-year period for which the permit will be in effect. COMMENT: Operator's surety bond does not cover damage from surface spills . Several commenters expressed concern that the amount of the operator's surety bond is insufficient to cover any damages as a result of ,surface spills. • RESPONSE: UIC regulations require that the operator of an injection well provide financial resources to cover the cost of plugging and abandonment of the well, in case of default at the time injection operations are terminated. The regulations do not provide bonding for restoration of the surface. Any surface - damages incurred as a result of injection are the responsibility of the operator and are beyond the EPA requirement of utilizing a bond for plugging the well. As indicated previously, however, the EPA could require corrective action for any activity or surface damage which poses a threat to a USDW. No change to the draft permit was made in response to these comments. COMMENT: Request that comment period following public hearing be extended. At the public hearing on December 5, 1991, one request was made to extend the public notice period to February 5, 1992 . RESPONSE: A public notice period of 15 days, to December 20, 1991, was set by EPA's Presiding Officer. During this period numeroi.s additional written comments were submitted to EPA. COMMENT: Iniection of fluids during an appeal of a final permit decision. One question raised at the public hearing concerned the operation of the well and the type of fluids authorized for injection in the event the issuance of this Class I Permit was appealed. • 941079 • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 21 RESPONSE: During an appeal following the issuance of a final permit, the operator will not be authorized to inject Class I fluids . The operator may, however, continue to inject fluids produced in conjunction with oil and gas production as provided for by the Class II permit with the Colorado Oil and Gas Conservation Commission. COMMENT: Determination of nonhazardous and hazardous waste fluids . Two comments pertained to the method in which fluids approved for injection were to be ascertained. That is, how are nonhazardous and hazardous waste defined. RESPONSE: All fluid sources proposed for injection are to undergo laboratory analysis which is submitted to EPA. A determination will then be made according to 40 CFR Part 261 whether the fluids are nonhazardous or hazardous. The operator will be authorized to inject nonhazardous fluids only; No change to the draft permit was made in response to these comments . COAT: Monitoring of injected fluids and frequency of samplings. Several commenters were concerned about the frequency of monitoring and the reliance on operator monitoring and reporting. RESPONSE: All industrial waste fluids intended for injection will be sampled at the source for fluid analysis prior to delivery to the well site, or prior to being transferred to on- site holding tanks . The analyses will be submitted to EPA along with a description of the source to verify that injected fluids are not hazardous. The fluids will be analyzed for chemical, physical, radiological, and biological constituents, including pH and conductivity. If the analyses from several loads from the same source indicate little or no change, the requirement that each load be sampled may be waived by EPA. Periodic sampling and analysis of source and/or on-site fluids intended for injection will also be conducted by EPA. The operator is required to keep records of: the location, date and time, and type of fluids picked up for transport to the injection well; the nature and composition of the fluids; and the information from the laboratory relating to the analyses of the samples. These records are to be submitted to EPA on a quarterly basis for evaluation. The operator is also required to monitor injection rate, injection pressure and annulus pressure on a continuous basis, utilizing recording charts. Summaries of this information must be submitted on. a quarterly basis to EPA for evaluation. Additionally, the operator must maintain all of the charts along with the records of fluid sample analyses for three years . 9410'79 • Wright' s Disposal, Inc. Class I Injection Well Responsiveness. Summary Page 22 During EPA inspections, the calibration of the monitoring equipment will be evaluated to assure that pressures and rates are being accurately recorded. The charts of pressure and injection rate data and fluid quality will also be reviewed to insure that the information reported to EPA was representative. Although the sampling requirement that each load of industrial waste coming from the same source (where the process • is not likely to change) may be waived, the permit has been modified to make it clear that one load must be tested each month prior to being transferred to on-site storage tanks. COMMENT: Payment of damages from catastrophic events related to injection operations. Several commenters inquired about payment or reimbursement for any damages incurred as a result of the operator injecting Class I nonhazardous fluids. RESPONSE: There are no provisions in the UIC Program covering damages as a result of underground injection. If damages occur as a demonstrable result of injection activity, the damaged party must deal directly with the owner/operator of the well who is accountable. No change to the draft permit was made in response to these comments. COMMENT: Future change of well classification for the disposal of hazardous waste fluids. One issue raised at the public hearing was the possibility of the well being authorized in the future for the disposal of hazardous waste fluids. RESPONSE: The Suckla Farms No. 1 well cannot be utilized for the disposal of hazardous waste because the construction of the well does not meet UIC standards for the disposal of hazardous waste. To be permitted for hazardous waste injection, a well must have all strings of casing cemented from the ground surface to the base of each casing string. The long string casing in the Suckla . — Farms No. 1 well is cemented only part way back to surface. No change to the draft permit was made in response to this comment. CONVENT: Permitting of additional disposal wells. One comment pertained to the possibility of additional disposal wells being permitted in the vicinity of the Suckla Farms No. 1 well . RESPONSE: Additional disposal wells in the area may be permitted under the UIC Program, if the permittee meets all program requirements . The permittee must also obtain approval and/or any permits required by state and local law. 941079 • Wright' s Disposal, Inc. Class I Injection Well Responsiveness Summary Page 23 COMMENT: Monitoring of the well following termination of infection of Class I fluids. One comment dealt with the type of well monitoring that would be done after the injection well had been plugged and abandoned. RESPONSE: At the termination of injection operations, the well is plugged and abandoned according to an EPA approved procedure designed to adequately protect all underground sources of drinking water. There is no required monitoring of the well following the plugging and abandonment operation, and no change was made to the draft permit in response to this comment: COMMENT: Devaluation of property values in the area. Concern was expressed by owners of property in the vicinity of the injection well regarding any decrease in property values. RESPONSE: There are no provisions in the UIC Program that pertain to, or provide compensation for, any devaluation of property that may occur adjacent to an injection well. This concludes a review and response to comments received relative to the issuance of a UIC Class I Permit to Wright' s Disposal, Inc. for the Suckla Farms No. 1 injection well. EPA has made the decision to issue a Final Permit for the well with the following modifications: Part II, Section C. 5 . Injection Volume Limitation. The cumulative injected volume of Class II produced oil field water, plus Class I nonhazardous industrial waste fluids is reduced from approximately 27, 000, 000 barrels and shall be limited to 8,300, 000 barrels. Part II, Section D. 1. Iniection Well Monitoring Program. If the fluid analysis of several loads of industrial waste from the same source indicate little or no change, the Director may elect to waive the requirement that each load be sampled. However, one load of industrial waste coming from the same source (where the process is not likely to change) must be tested each month prior to being transferred to on-site storage tanks. Part III, Section E, 6. Surface Leak Prevention. In order to supplement EPA monitoring, the permittee shall contract for an environmental audit of the facility, twice each year with an , independent firm. The audit will be for the purpose of evaluating the adequacy of facility operations and maintenance in preventing ground water pollution. The permittee will provide EPA with a list of three firms capable of conducting an audit; EPA will then select one firm to conduct the audit. 941079 APPENDIX A' • COMPARISON OF WORKGRCUP RANKINGS OF OSWER PRCELEM AREAS . Workgroup Raridng • . - Acute OCier Ecobgical Welfaie .Grand-Water • Events t Reacts Effects Effects YaWadai Mu icipal Landfmi s L M X H .271 Industrial Facfities H H M H - T Hazardous Waste Storage Treatment'larks. A H .4i H — C Drums. and Containers Petroleum Underground Storage larks H M .NZ H - Land Disposal of Hazardous Waste A .W. X H U. Superfund Sites - H — H H� Remedial Activities 2 — .XC — Transportation of Hazardous Materials .7C 2' .fLZ L . - Chemical and Industrial L .£12 L — Manufactring Fadlties Underground Storage larks — . — — H Oi Spa Response H L 412 L — Cf and Gas Operations H S M M Scud Waste Management Units M iC ML At -It c Exempt Storage larks M M SZ At — Mining Wastes L -IL .4...X Ai. _di Other Treatment. Storage. .GL M M M Z and Disposal Faciftles RemovarActvities A — — — — Combustion of Hazardous Waste .Gi J! .Gl L L Municipal Waste Combustion 2 sit MH L L Hazardous Substance/Product M M .GL L - Underground Storage larks PCS Wastes ' 14 L MH L — Land Treatment of Hazardous Wastes 2 AL M L — Underground NjectiorrotHazardous-Wastr At L ML L r 42 Mixed Wastes L L M L f Ocean Dumping L L ` $ L Ocean Incineration t L — .li t L — _ 941.079 • APPENDIX A (continued) • • Notes on the Comparison Table Letters reflect relative risk rarid ngs judged for problem areas get High or higher relative risk•potenttal .,A(ie Moderately high relative risk potential U. Medum a moderate relative risk potential suet, Moderately low relative risk potential Low or lower relative risk potential — The warkgroup dd not consider this problem area. Uncertainty is reflected it lettering as H Low uncertainty(Mgh confidence) X Median uncertainty(median confidence) H High uncertainty(bw confidence) . No attempt was made to'adds risks across Workgrcups or compare the 6npatance . of me wakootp as more significant than another. Note that dfferences h problem areas addressed is due to a cant:hada!of avaiede data and scope. 9 .t• 941079 • APPENDIX B - • Wk�GHT'S DISPOSAL, INC. SUCZLA FARMS No. 1 Injection Pressure ) .' Gauge -C Injected Fluids 04 .. . Valves Wellhead . Annulus Pressure * Gauge. -"' Arapahoe • (` Cement Laramie-Fox Hills'.' • Aquifers -,1 - Base USDWs @ 700/ Surface Casing I @ 759/ Annular Fluid Pierre Shale I { S Injection Tubing . ' ' k I . Long String Casing l Base Pierre Shale ) S @ 7362/ L.__ _ell( Top of Cement @ 8398/ VC. Interbedded 4. Sands & Shales E... ''1 - .:',; � Packer " -�i - @ 9240' Confining Layer {~ "" 300, Impervious Shale � ,-j & Siltstones L- - 1- ' Lyons ) Perforations cC4 92761 - 9418 Injection Zone 1 -7 U= 9410'79• . ,:•, • . . •. ..•�, Total Depth Diagramma is 95711 Not to Scale Y.. • ADMINISTRATIVE REVIEW (40 CFR c124 . 19) 1. Any person who filed comments on the tentative permit decision or participated in any public hearing on such decision may petition the Administrator to review any condition of the final permit decisions. 2. Any person who failed to file comments or participate in any public hearing on the tentative permit decision may petition for administrative review only to the extent of the changes from the tentative to the final permit decision. 3 . The petition must include a statement of the reasons supporting that review, including a demonstration that any issues being raised in the petition were previously raised during the public comment period or during any public hearing and, when appropriate, a showing that the condition in question is based on: a. A finding of fact or conclusion of law which is clearly • erroneous; or b. An exercise of discretion or an important policy consideration which that Administrator should, in his or her discretion, review. 4 . Such a request must be made within thirty (30) days of service of notice of the Regional Administrator's action, and shall be mailed to: U.S. Environmental Protection Agency Office of the Administrator Environmental Appeals Board (A-101) 401 M Street, SW Room 1145 (West Tower) Washington, D.C. 20460 • ,A 941079 a'`°n"$s. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY g�tl 3 REGION VIII �M/`/ 999 18th STREET - SUITE 500 DENVER, COLORADO 80202-2466 UNDERGROUND INJECTION CONTROL PROGRAM Final Permit Class I Nonhazardous Industrial Waste Disposal Well Permit No. CO1516-2115 Well Name: Suckla Farms #1 Field Name: Spindle County & State: Weld County, Colorado issued to: Wright's Disposal, Inc. P. O. Box 233 Fort Lupton, Colorado 80621 Page 1 of 39 EPA Final Permit No. CO1516.-02115 Print94linger • TABLE OF CONTENTS TITLE SHEET 1 TABLE OF CONTENTS 2 PART I. AUTHORIZATION TO INJECT 4 PART II . SPECIFIC PERMIT CONDITIONS 6 A. WELL CONSTRUCTION REQUIREMENTS 6 1. Casing and Cementing 6 2 . Tubing and Packer Specifications 6 3 . Monitoring Devices 6 4 . Proposed Changes and Workovers 7 5 . Formation Testing 7 6 . Postponement of Conversion 8 • B. CORRECTIVE ACTION 8 C. WELL OPERATION 8 1. Prior to Commencing Iniection 8 2 . , Mechanical Integrity 9 3 . Injection Interval 10 4 . Injection Pressure Limitation 11 5 . Iniection Volume Limitation 11 6 . Injection Fluid Limitation 11 7 . Annular Fluid 12 D. MONITORING, RECORDKEEPING, AND REPORTING OF RESULTS 12 1. Injection Well Monitoring Program 12 2 . Monitoring Information 14 3 . Recordkeeping 14 4 . Reporting of Results 15 E. PLUGGING AND ABANDONMENT 15 1. Notice of Plugging and Abandonment . . . 15 2 . Plugging and Abandonment Plan 15 3 . Cessation of Iniection Activities 16 4 . Plugging and Abandonment Report 16 • Page 2 of 39 EPA Final Permit No. CO1516-02115 • 941079 F. FINANCIAL RESPONSIBILITY 16 1 . Demonstration of Financial Responsibility 16 2 . Insolvency of Financial Institution . . . 17 3 . Cancellation of Demonstration by Financial Institution 17 PART III. GENERAL PERMIT CONDITIONS 18 A. EFFECT OF PERMIT 18 B. PERMIT ACTIONS 18 1 . Modification. Reissuance. or Termination 18 2 . Conversions 18 3 . Transfers 19 4 . Operator Change of Address 19 C. SEVERABILITY 19 D. CONFIDENTIALITY 19 E. GENERAL DUTIES AND REQUIREMENTS 19 1. Duty to Comply 19 2 . Penalties for Violations of Permit Conditions 20 3 . N ed to Halt or Reduce Activity not a Defense 20 4 . Duty to Mitigate 20 5 . Proper Operation and Maintenance 20 6. Surface Leak Prevention 20 7. Duty to Provide Information 20 8 . Inspection and Entry 21 9 . Records of Permit Application 21 10 . Signatory Requirements 21 11. Reporting of Noncompliance 21 APPENDIX A (CONSTRUCTION DETAILS) 24 APPENDIX B (REPORTING FORMS) 26 APPENDIX C (PLUGGING & ABANDONMENT PLAN) 32 APPENDIX D (INJECTION FLUID SOURCES) 34 • Page 3 of 39 EPA Final Permit No. CO1516-02115 941079 PART I . AUTHORIZATION TO INJECT Pursuant to the Underground Injection Control Regulations of the U. S . Environmental Protection Agency codified at Title 40 of the Code of Federal Regulations, Parts 124, 144, 146, and 147, Wright' s Disposal, Inc. P. 0. Box 233 Fort Lupton, Colorado 80621 is hereby authorized to operate a Class I disposal well, commonly known as Suckle Farms #1, located in the SE 1/4 of the NW 1/4, 2, 140 feet from the north line and 2, 020 feet from the west line of Section 10, Township 1 North, Range 67 West in Weld County, Colorado. Injection shall be for the purpose of disposing of industrial waste fluids and produced water from oil and gas fields, in accordance with conditions set forth herein. Injection activities shall not commence until the operator has fulfilled all applicable conditions of this permit and has received written authorization from the Director. "Prior to Commencing Injection" requirements are set forth in Part II, Section C. 1. of this permit. All conditions set forth herein refer to Title 40 Parts 124, 144, 146, and 147 of the Code of Federal Regulations and are regulations that are in effect on the date that this permit becomes effective. This permit consists of a total of 39 pages and includes all items listed in the Table of Contents . Further, it is based upon representations made by the permittee and on other information contained in the administrative record. This permit and the authorization to inject are issued for a period of ten (10) years, unless terminated (Part III, Section B) ; authorization to inject shall automatically expire due to prolonged postponement of conversion to a Class I injection well (Part II, Section A. 6 . ] . The permit will be reviewed by EPA at least once every five (5) years to determine whether action under 40 CFR 144 .36 (a) is warranted. The permit will expire upon delegation of primary enforcement responsibility for Class I wells of the UIC Program to the State of Colorado, unless that State has adequate authority, and chooses, to adopt and enforce this permit as a State permit. Page 4 of 39 EPA Final Permit No. CO1516-02115 941079 Issued this 16th day of June 1992 . This permit shall become effective July 21, 1992 ACILA ti/. * Max H. Dodson, Director t Water Management Division *NOTE: The person holding this title is referred to as the "Director" throughout this permit. Page 5 of 39 EPA Final Permit No. C01515-02115 941O79 PART II. SPECIFIC PERMIT CONDITIONS A. WELL CONSTRUCTION REQUIREMENTS 1. Casing and Cementing. The construction details submitted with the application are hereby incorporated into this permit as Appendix A, and shall be binding on the permittee. Cement bonds between the wellbore and casing are as follows : (1) cement extends from the base of the long string casing up to a depth of 8, 398 feet; and (3) cement extends from the base of the surface casing to the top of the surface casing. Injection between the outermost casing protecting underground sources of drinking water (USDW) and the wellbore is prohibited. 2 . Tubing and Packer Specifications . An injection tubing of two and seven-eighths (2 and 7/8) inches diameter shall be utilized. A packer is set at a depth of 9 , 240 feet; in no instance shall the packer be set more than 50 feet above the top of the perforated interval. 3 . Monitoring Dev' ces . Prior to beginning Class I nonhazardous injection operation, the -operator shall install and maintain in good operating condition the following equipment: (a) a tap on the suction line for the purpose of obtaining representative samples of the injection fluids; (b) two (2) , one-half (1/2) inch Female Iron Pipe (FIP) fittings, isolated by plug or globe valves, and located: 1) at the wellhead on the tubing; and 2) on the tubing/casing annulus, and positioned to allow attachment of 1/2 inch Male Iron Pipe (MIP) pressure gauges; (c) pressure gauges shall be attached to the FIP fittings of the: 1) the tubing to allow injection pressure monitoring; and 2) tubing/casing annulus to allow for monitoring of the annulus fluid pressure. It is recommended that the tubing/casing annulus be maintained full of fluid under a positive pressure, with a minimum pressure of 200 psig. The standard method for doing so involves use of an above- ground fluid reservoir with a nitrogen gas cap to maintain positive pressure. Pressure gauges shall be certified for at least ninety-five (95) percent accuracy, throughout the range of anticipated injection pressures; Page 6 of 39 EPA Final Permit No. C01516-62115 941079 (d) a flow meter with cumulative volume recorder that is certified for at least ninety-five (95) percent accuracy, throughout the range of injection rates allowed by the permit; and (e) finally, installation of suitable equipment for the continuous monitoring and recording of injection pressure, annulus pressure, flow rate, and volume. A continuous recording of injection volume can be accomplished by use of a cumulative volume totalizer. 4 . Proposed Changes and Workovers . The permittee shall give advance notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted well . Major alterations or workovers of the permitted well shall meet all conditions as set forth in this permit. A major alteration/workover shall be considered any work performed, which affects casing, packer(s) , or tubing. The permittee shall provide all records of well workovers, logging, or other test data to EPA within sixty (60) days of completion of the activity. Appendix B contains samples of the appropriate reporting forms. Demonstration of mechanical integrity (tubing/casing annulus pressure test) shall be performed within thirty (30) days of completion of workovers/alterations and prior to resuming injection activities, in accordance with Part II, Section C. 2 . (a) . 5 . Formation Testing. The permittee shall conduct appropriate tests during the conversion of the well, and during the operating life of the well . (a) The injection zone fluid pore pressure shall be measured (static bottom-hole pressure) . (b) The permittee shall perform a controlled injectivity (step rate) test to determine the fracture pressure of the injection zone. (c) The permittee shall perform a pressure fall-off test of the injection zone prior to beginning Class I nonhazardous injection operations, and thereafter on an annual basis. Each test is to be conducted in the same manner, and the results are to be analyzed in report form for comparison with previous year results . Page 7 of 39 EPA Final Permit No. CO1516-02115 941079 6 . Postponement of Conversion. If the well is not converted to 'Class I injection status within one (1) year from the effective date of this permit, the authorization to inject as a Class I well will automatically expire; unless the permittee requests an extension. The request shall be made to the Director in writing, in lieu of the annual reporting requirements of Part II, Section D. 4 . , and shall state the reasons for the delay in conversion and confirm the protection of all USDWs. The extension under this section may not exceed one (1) year. Financial responsibility shall be maintained during the period of inactivity in accordance with Part II, Section F. Once authorization to inject as a Class I well expires under this part, the full permitting process, including opportunity for public comment, must be repeated before authorization to inject will be reissued. B. CORRECTIVE ACTION The operator is not required to take any corrective action before the effective date of this permit. C. WELL OPERATION 1. Prior to Commencing Injection. Injection operations as a Class I well may not commence until the permittee has complied with (a) , (b) , and (c) as follows : (a) Conversion is complete and logging and testing requirements have been fulfilled. (i) The Director has inspected or otherwise reviewed the new injection well and finds it is in compliance with the conditions of the permit; or (ii) The permittee has not received notice from the Director of his or her intent to inspect or otherwise review the injection well within thirteen (13) days of the effective date of this permit, in which case prior inspection or review is waived and the permittee may commence injection. Note: However, in all circumstances, item (b) below must be satisfied. (b) The permittee demonst, ates that the well has mechanical integrity and has received notice from the Director that such a demonstration is satisfactory. Demonstration of mechanical Page 8 of 39 EPA Final Permit No. CO1516-02115 941079 integrity shall consist of two parts : (1) a tubing/casing annulus pressure test in accordance with 40 CFR 146. 8 and Part II, Section C. 2 . (a) , below, and (2) verification that no flow of fluid exists adjacent to the casing, in accordance with Section C. 2 (b) , below. The permittee shall notify EPA two (2) weeks prior to conducting these tests so that a representative may be present to observe the tests. Results of the tests shall be submitted to the Director as soon as possible but no later than thirty (30) days after the demonstrations. 2 . Mechanical Integrity. (a) Method of Demonstrating Mechanical Integrity. A demonstration of the absence of significant leaks in the casing, tubing and/or packer must be made by performing a tubing/casing annulus pressure test. This test shall be for a minimum of forty-five (45) minutes at a pressure of at least 200 pounds per square inch gauge (psig) above the injection tubing pressure while the well is shut-in. The tubing/casing annulus shall be filled with a non-corrosive fluid (either a non-toxic liquid or the injection liquid) at least twenty-four (24) hours in advance of the test . Pressure values shall be recorded at five- minute intervals. A well passes the mechanical integrity test if there is less than a ten (10) percent decrease/increase in pressure over the forty-five (45) minute period. (b) A demonstration of the absence of any significant flow of fluid adjacent to the casing must be made by initially performing an oxygen activation log and temperature survey during injection to determine if there is (1) any movement of fluid out of the injection zone, and (2) any movement of fluid between uncemented formations up hole. The log shall be run at predetermined locations extending from the base of the long string casing to the base of the surface casing. At a minimum, stations should be located at: (1) the base of the long string casing, (2) the top of the confining zone, (3) the top of cement behind the long string :acing, and (4) adjacent to all water bearing zones above the cement. The logging plan is to be submitted to the Director for approval, prior to running the log. Page 9 of 39 EPA Final Permit No. CO1516-02115 941075 (c) Schedule for Demonstrating of Mechanical Integrity. A demonstration of mechanical integrity shall be made at regular intervals, no less frequently than every two (2) years from the effective date of this permit, in accordance with 40 CFR 146. 8 and paragraph (a) above, unless otherwise modified. Initiation of mechanical integrity demonstrations will be according to the following provisions : (i) It shall be the permittee' s responsibility to arrange and conduct the routine two-year tubing/casing annulus pressure test demonstration, and radioactive tracer survey and/or temperature log at five-year intervals . The permittee shall notify the Director of his intent to demonstrate mechanical integrity at least thirty (30) days prior to such demonstration. Results of the test shall be submitted to the Director as soon as possible but no later than sixty (60) days after the demonstration. (ii) In addition to any demonstration made under paragraph (i) above, the Director may require a demonstration of mechanical integrity, as described in Part II, Section C. 2 . (a) and (b) , at any time during the permitted life of the well . (d) Loss of Mechanical Integrity. If the well fails to demonstrate mechanical integrity during a test, or a loss of mechanical integrity as defined by 40 CFR 146 . 8 becomes evident during operation, the permittee shall notify the Director in accordance with Part III, Section E. 10 . of this permit. Furthermore, injection activities shall be terminated immediately; and operation shall not be resumed until the permittee has taken necessary actions to restore integrity to the well and EPA gives approval to recommence injection. 3 . Injection Interval . Injection shall be limited to the Lyons Formation in the subsurface interval between the depths of 9 , 276 feet and 9, 418 feet. Page 10 of 39 EPA Final Permit No. CO1516-02115 941079 4 . Injection Pressure Limitation. (a) Injection pressure, measured at the surface, shall not exceed 2, 397 pounds per square inch gauge. (b) The pressure limit in paragraph (a) may be modified by the Director if it is necessary to ensure that the surface injection pressure will not exceed the injection formation fracture- pressure or if the permittee requests the pressure change. This demonstration shall be made by performing a step-rate injection test, using fluid normally injected, to determine both the instantaneous shut-in pressure (ISIP) and the formation breakdown pressure. The Director will determine the allowable pressure modification based upon the test results and other parameters reflecting actual injection operations . (c) The permittee shall give thirty (30) days advance notice to the Director if an increase in injection pressure will be sought . Details of the proposed test shall be submitted at least seven (7) days in advance of the proposed test date so that the Director has adequate time to review and approve the test procedures . Results of all tests shall be submitted to the Director within ten (10) days of the test. Injection at the increased pressure must be approved in writing by the Director. 5 . Infection Volume Limitation. Cumulative injection volume of oil field water, plus Class I nonhazardous waste fluid will be limited to 8 , 300, 000 barrels. This volume is based on the amount of fluid necessary to fill up the portion of the reservoir within a 1/4-mile radius around the injection well . The injection rate will not be limited, but in no instance shall the injection pressure exceed that listed in Part II, Section C, Item 4, above. When the maximum cumulative volume is reached, EPA will make a decision whether to extend the limits of the injection zone or to terminate the permit; however,_ analysis of monitoring records and annual pressure fall-off test data may dictate otherwise at the time of the scheduled five-year review. 6 . Injection Fluid Limitation. The permittee is authorized to inject only Class II oil an gas related fluids, Class I fluids from underground storage tank (UST) cleanup sites, and other nonhazardous industrial wastes as approved by the Page 11 of 39 EPA Final Permit No. CO1516-02115 941079 Director and listed in Appendix D. Injection of any hazardous waste as identified by EPA under 40 CFR 261 .3 is prohibited. Additions to this list in Appendix D shall be made a binding part of this permit following the procedures outlined below: For Class II and UST fluid sources: a) Request that a new source of fluid be accepted for disposal . Include the source name, location, operator, and type of operation. b) The request shall be accompanied by a water analysis consisting of Total Dissolved Solids, pH, Specific Gravity, and Specific Conductivity. c) Any approval for injection may be granted verbally, with subsequent written approval from the Director. For nonhazardous fluid sources : a) Request that a new source of fluid be accepted for disposal . Include the source name, location, operator, and type of operation. b), Since these wastes may not be exempted, include an analysis of the fluids, includingBTEX, EP Corrosivity, EP Toxicity using the Toxicity Characteristic Leaching Procedure (TCLP) , EP Ignitability, and EP Reactivity. c) Any approval for injection may be granted verbally, with subsequent written approval from the Director. 7 . Annular Fluid. The annulus between the tubing and the casing shall be filled with fresh water treated with a corrosion inhibitor, or other fluid as approved, in writing, by the Director. D. MONITORING, RECORDKEEPING, AND REPORTING OF RESULTS 1. Infection Well Monitoring Program. The permittee submitted with the application a monitoring program, parts of which are incorporated into the permit as specified below. Samples and measurements shall be representative of the monitored activity. The permittee shall utilize the applicable analytical methods described in Table 1 of 40 CFR 136 .3, or in Appendix III Page 12 of 39 EPA Final Permit No. CO1516-02115 941079 of 40 CFR Part 261, or in certain circumstances, by other methods that have been approved by the EPA Administrator. Monitoring shall consist of: (a) FOR FLUIDS WHICH MAY VARY IN CHEMICAL COMPOSITION. Analysis of industrial waste fluids received at the well site is to be performed prior to delivery, or prior to being pumped from individual delivery trucks into on-site storage tanks. Fluid samples shall be analyzed for chemical, physical, biological, and radiological constituents, including pH and conductivity. If, however, the analyses of four (4) loads from the same source indicates the material is not hazardous and the quality has little variability, the Director may waive the requirement for analyzing every load. Subsequent to this waiver, a minimum of one load in four must be analyzed. (b) FOR FLUIDS ASSOCIATED WITH A SPECIFIC PROCESS. WHICH DO NOT VARY IN CHEMICAL COMPOSITION. Analysis of industrial waste fluids received at the well site is to be performed once per month. Fluid samples shall be analyzed for chemical, physical, biological, and radiological constituents, including pH and conductivity. If, however, the analyses of the monthly samples shows variability in chemical composition, the frequency of analyses may be increased to that specified in item (a) above. (c) Analysis of commingled injection fluids prior to injection to be performed at random, but not less than once every three months, for total dissolved solids, pH, specific conductivity, specific gravity, major cations and anions, oil and grease, and total organic carbon. (.d) Continuous monitoring of flow rate to be recorded on a continuous recording chart. Daily observation of the well head flow meter shall be made as a means of assuring the accuracy of the continuous recording chart. The permittee shall report the minimum and maximum daily injection rate for each month and the day on which it occurred. Cumulative volume shall be measured by a volume totalizer. Page 13 of 39 EPA Final Permit No. CO1516-02115 941074 (e) Continuous monitoring of injection pressure and casing/tubing annulus pressure to be recorded on a continuous recording chart . Daily observations of the wellhead pressure gauges shall be made as a means of assuring the accuracy of the continuous recording chart . The permittee shall report the minimum and maximum daily injection pressure and annulus pressure for each month and the day on which each occurred. 2 . Monitoring Information. Records of any monitoring activity required under this permit shall include: (a) The dates, exact place, and the time interval of sampling, monitoring, or field measurements; (b) The name of the individual (s) who performed the sampling or measurements; (c) The exact sampling method(s) used to take samples; (d) The date (s) laboratory analyses were performed; (e) The name of the individual (s) who performed the analyses; (f) The analytical techniques or methods used by laboratory personnel; and (g) The results of such analyses . 3 . Recordkeepinc. (a) The permittee shall retain records concerning: (i) the nature and composition of all injected fluids until three (3) years after the completion of plugging and abandonment which has been carried out in accordance with the Plugging and Abandonment Plan shown in Appendix C, and is consistent with 40 CFR 146 . 10 . (ii) all monitoring information, including all calibration and maintenance records and all original chart recordings for continuous monitoring instrumentation and copies of all reports required by this permit for a period of at least five (5) years from the date of Page 14 of 39 EPA Final Permit No. CO1516-02115 9410'79 the sample, measurement or report throughout the operating life of the well . (b) The permittee shall continue to retain such records after the retention period specified in paragraphs (a) (i) and (a) (ii) unless he delivers the records to the Director or obtains written approval from the Director to discard the records. (c) The permittee shall maintain copies (or originals) of all pertinent records [Part II, Section D. 1. (a) , (b) , (c) , and (d) ] available for inspection at the office of Wright' s Disposal, Inc. , P. O. Box 233 , Fort Lupton, Colorado 80621. 4 . Reporting of Results . The permittee shall submit Quar :erly Reports to the Director summarizing the results of the • moni:oring required by Part II, Section D. 1. (a) , (b) , (c) , (d) and (e) of this permit. Copies of all records of injected fluids, and any major changes in characteristics or sources of injected fluid shall be included in the Quarterly Report . The first Quarterly Report shall cover the period from the efeective date of the permit through the end of that quarter. Sdosequent Quarterly Reports shall cover the periods of : January 1 through March 31; April 1 through June 30; July 1 through September 30; and, October 1 through December 31. Each Quarterly ?Report shall be submitted to the Denver Office by the 15th of the following month. Appendix B contains Form 7520-8 which may be 'copied and used to submit the quarterly summary of monitoring. E. PLUGGING AND ABANDONMENT 1, Notice of Plugging and Abandonment. The permittee shall notify the Director forty-five (45) days before abandonment of the well . 2 . Plugging and Abandonment Plan. The permittee shall plug and abandon the well as provided in the Plugging and Abandonment Plan, Appendix C. EPA reserves the right to change the manner in which the well will be plugged if the well is modified during its permitted life, or if the well is not made consistent with EPA requirements for construction and mechanical integrity. The Director may ask the permittee to periodically update the estimated plugging cost, based upon costs which a third party would incur to plug the well according to the plan, and a revised demonstration of financial responsibility if necessary. Page 15 of 39 EPA Final Permit No. CO1516-02115 94107', 3 . Cessation of Iniection Activities . After a cessation of operations of two (2) years, the permittee shall plug and abandon the well in accordance with the Plugging and Abandonment Plan, unless the permittee: (a) has provided notice to the Director; and (b) has demonstrated that the well will be used in the future; and (c) has described actions or procedures, satisfactory to the Director, that will be taken to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. 4 . Plugging and Abandonment Report . Within sixty (60) days after plugging the well, the permittee shall submit a report on Form 7520-13 to the Director. The report shall be certified as accurate by the person who performed the plugging operation and the report shall consist of either: (1) a statement that the well was plugged in accordance with the plan; or (2) where actual plugging differed from the plan, a statement that specifies the different procedures followed. F. FINANCIAL RESPONSIBILITY 1. Demonstration of Financial Responsibility. The permittee is required to maintain continuous financial responsibility and resources to close, plug .and abandon the injection well as provided in the plugging and abandonment plan. (a) A Letter of Credit in the amount of $5, 400 . 00 underwritten by First Security Bank, P.O. Box 228 , Fort Lupton, Colorado 80621, which names EPA as beneficiary in the event of permittee default in the plugging and abandonment requirements, is hereby incorporated as part of this permit. The Standby Trust Agreement established by the permittee shall remain in effect for the duration of this permit, unless part (b) , below, has been complied with. (b) The permittee may, upon written request to EPA, change the type of financial mechanism or instrument utilized., A change in demonstration of financial responsibility must be approved by the Director. A minor permit modification will Page 16 of 39 EPA Final Permit No. CO1516-02115 941079 be made to reflect any change in financial mechanisms, without further opportunity for public comment. 2 . Insolvency of Financial Institution. In the event that an alternate demonstration of financial responsibility has been approved under (b) above, the permittee must submit an alternate demonstration of financial responsibility acceptable to the Director within sixty (60) days after either of the following events occur: (a) The institution issuing the trust or financial instrument files for bankruptcy; or (b) The authority of the trustee institution to act as trustee, or the authority of the institution issuing the financial instrument, is suspended or revoked. 3 . Cancellation of Demonstration by Financial Institution. The permittee must submit an alternative demonstration of financial responsibility acceptable to the Director, within sixty (60) days after the institution issuing the trust or financial instrument serves 120-day notice to the EPA of their' intent to cancel the trust or financial instrument. Page 17 of 39 EPA Final Permit No. CO1516-02115 941079 PART III. GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The permittee, as authorized by this permit, shall not construct, operate, maintain, convert, plug, abandon, or conduct any other injection activity in a manner that allows the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR, Part 142 or otherwise adversely affect the health of persons . Any underground injection activity not authorized in this permit or otherwise authorized by permit or rule is prohibited. Issuance of this permit does not convey property rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. Compliance with the terms of this permit does not constitute a defense to any enforcement action brought under the provisions of Section 1431 of the Safe Drinking Water Act (SDWA) or any other law governing protection of public health or the environment for any imminent and substantial endangerment to human health, or the environment, nor does it serve as a shield to the permittee' s • independent obligation to comply with all UIC regulations. B. PERMIT ACTIONS 1 . Modification. Reissuance. or Termination. The Director may, for cause or upon a request from the permittee, modify, revoke and reissue, or terminate this permit in accordance with 40 CFR Sections 124 . 5, 144 . 12, 144 .39 , and 144 .40 . Also, the permit is subject to minor modifications for cause as specified in 40 CFR Section 144 .41. The filing of a request for a permit modification, revocation and reissuance, or termination or the notification of planned changes or anticipated noncompliance on the part of the permittee does not stay the applicability or enforceability of any permit condition. 2 . Conversions. The Director may, for cause or upon a request from the permittee allow conversion of the well from a Class I injection well to a non-Class I well . Requests to convert the injection well from its Class I status to a non-Class I well, such 'as, a production well, must be made in writing to the Director. Conversion may not proceed until a permit modification indicating the conditions of the proposed conversion • is received by the permittee. Conditions of the modification may include such items as, but is not limited to, approval of the proposed well rework, follow up demonstration of mechanical Page 18 of 39 EPA Final Permit No. C01516-02115 9410'79 integrity, and well specific monitoring and reporting following the conversion. 3 . Transfers . This permit is not transferrable to any person except after notice is provided to the Director and the requirements of 40 CFR 144 .38 are complied with. The Director may require modification, or revocation and reissuance, of the permit to change the name of the permittee and incorporate such other requirements as may be necessary under the SDWA. 4. Operator Change of Address . Upon the operator' s change of address, notice must be given to the appropriate EPA office at least fifteen (15) days prior to the effective date. C. SEVERABILITY The provisions of this permit are severable, and if any provision of this permit or the application of any provision of this permit to any circumstance, is held invalid, the application of such provision to other circumstances, and the remainder of this permit shall not be affected thereby. D. CONFIDENTIALITY _ In accordance with 40 CFR Part 2 and 40 CFR 144 . 5 , any information submitted to EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time of submission by stamping the words "confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the validity of the claim will be assessed in accordance with the procedures in 40 CFR Part 2 (Public Information) . Claims of confidentiality for the following information will be denied: - The name and address of the permittee; and - Information which deals with the existence, absence or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1 . Duty to Comply. The permittee shall comply with all conditions of this permit, except to the extent and for the duration that such noncompliance is autho'.ized by an emergency permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action, permit termination, revocation and reissuance, or modification. Such noncompliance Page 19 of 39 EPA Final Permit No. CO1516-02115 94107c may also be grounds for enforcement action under the Resource Conservation and Recovery Act (RCRA) . 2 . Penalties for Violations of Permit Conditions . Any person who violates a permit requirement is subject to civil penalties, fines, and other enforcement action under the SDWA and may be subject to such actions pursuant to the RCRA. Any person who willfully violates permit conditions may be subject to criminal prosecution. 3 . Need to Halt or Reduce Activity not a Defense. It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 4 . Duty to Mitigate. The permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit . 5 . Proper Operation and Maintenance. The permittee shall at all times properly operate and maintain all facilities and systems of treatment and control (and- related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures . This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. 6 . Surface Leak Prevention. The permittee shall operate and maintain the surface facility, including tanks, pumps, piping, and truck unloading area in a manner that prevents fluids delivered for disposal from contaminating ground water. Therefore, the permittee is required (a) to report to EPA and correct any problems that could cause groundwater contamination, and (b) to contract with an outside firm for an environmental audit of the facility twice each year, but no more frequent than four months apart. The audit contract shall require the outside firm to report audit results to EPA. The audit will be for the purpose of evaluating the adequacy of facility operations and maintenance in preventing groundwater contamination. No later than thirty (30) days from the effective date of this permit, the permittee must submit for EPA approval a proposed plan for the environmental audit; EPA must approve the plan prior to the first audit. No later than sixty (60) days after the effective date of this permit, the permittee will provide EPA with a list of three Page 20 of 39 EPA Final Permit No. CO1516-02115 941079 ,firms that are capable of carrying out an audit and that the permittee will contract with. EPA will then select the firm to conduct the audit. 7 . Duty to Provide Information. The permittee shall furnish the Director, within a time specified, any information which the Director may request in order to determine whether cause exists for modifying, revoking and reissuing, or terminating this permit, or to determine compliance with the permit. The permittee shall also furnish to the Director, upon request, copies of records required to be kept by this permit. 8 . Inspection and Entry. The permittee shall allow the Director, or an authorized representative, upon the presentation of credentials and other documents as may be required by law, to: (a) Enter upon the permittee' s premises where a regulated facility or activity is located or conducted, or where records must be kept under the conditions of this permit; (b) Have access to and copy, at reasonable times, any records that must be kept under the conditions of this permit; (c) Inspect at reasonable times any facilities, equipment (including monitoring and control equipment) , practices, or operations regulated or required under this permit; and (d) Sample or monitor, at reasonable times, for the purpose of assuring permit compliance, or as otherwise authorized by the SDWA, any substances or parameters at any location. 9 . Records of Permit Application. The permittee shall maintain records of all data required to complete the permit application and any supplemental information submitted for a period of five (5) years from the effective date of this permit. This period may be extended by the Director at any time. 10 . Signatory Requirements . All reports or other information requested by the Director shall be signed and certified according to 40 CFR 144 .32 . 11. Reporting of Noncompliance. (a) Antic 'pated Noncompliance. The permittee shall give advance notice to the Director of any planned changes in the permitted facility or Page 21 of 39 EPA Final Permit No. CO1516-02115 941079 activity which may result in noncompliance with permit requirements . (b) Compliance Schedules . Reports of compliance or noncompliance with, or any progress reports on, interim and final requirements contained in any compliance schedule of this permit, shall be submitted no later than thirty (30) days following each schedule date. (c) Twenty-four Hour Reporting. (i) The permittee shall report to the Director any noncompliance which may endanger health or the environment. Information shall be provided orally within twenty-four (24) hours from the time the permittee becomes aware of the circumstances, by telephoning EPA at (303) 293-1413 (during normal business hours) or at (303) 293-1788 (for reporting at all other times) . The following information shall be included in the verbal report: (A) Any monitoring or other information which indicates that any contaminant may cause endangerment to an underground source of drinking water. (B) Any noncompliance with a permit condition or malfunction of the injection system which may cause fluid migration into or between underground sources of drinking water. (ii) A written submission shall also be provided within five (5) days of the time the permittee becomes aware of the circumstances . The written submission shall contain a description of the noncompliance and its cause; the period of noncompliance, including exact dates and times, and if the noncompliance has not been corrected, the anticipated time it is expected to continue; and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. Page 22 of 39 EPA Final Permit No. CO1516-02115 941079 (d) Other Noncompliance. The permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted. The reports shall contain the information listed in Part III, Section E. 10 . (c) (ii) of this permit . (e) Other Information. Where the permittee becomes aware that any relevant facts were not submitted in the permit application, or incorrect information was submitted in a permit application or in any report to the Director, the permittee shall submit such correct facts or information within two (2) weeks of the time such information becomes known. Page 23 of 39 EPA Final Permit No. CO1516-02115 • 541079 C;.z_---=• TR 7 r__ n-:.r.c - lj I I f I WCL_: • . -a--<- T a.- - .._ 7.7a- NT- - fit .. 77.7 .:=_^ r-,._- . - --,.:- be i _ — -- _ 71*;" -__ --- - • • C�� rs._..___ti (; It_ •;.-.—__- r Ni. �� . u ILI J-� -if c -?q ' : Page 25 of 39 • EPA Final Permit No. CO1516-02115 • 941079 APPENDIX B (REPORTING FORMS) 1 . EPA Form 7520- 7: APPLICATION TO TRANSFER PERMIT 2 . EPA Form 7520- 8 : INJECTION WELL MONITORING REPORT 3 . EPA Form 7520-10 : COMPLETION REPORT FOR BRINE DISPOSAL . . . WELL 4 . EPA Form 7520-12 : WELL REWORK RECORD 5 . EPA Form 7520-13 : PLUGGING RECORD Page 26 of 39 EPA Final Permit No. CO1516-02115 941079 Form-'•Droved. OMB No.2000-0042.Aoorovel noires 9.30.9( UNITED STATES ENVIRONMENTAL PROTEC .AGENCY A WASHINGTON,DC 20460 j %E PA APPLICATION TO TRANSFER PERMIT NAME AND ADDRESS OF EXISTING PERMITTEE NAME AND ADDRESS OF SURFACE OWNER I. STATE COUNTY PERMIT NUMBER LOCATE WELL AND OUTUNE UNIT ON SECTION PtAT - 640 ACRES 1 SURFACE LOCATION DESCRIPTION N• I I I I I I % IA OF %SECTION TOWNSHIP RANGE I I I I I I LOCATE WELL IN TWO DIRECTIONS FROM NEAREST LINES OF QUARTER SECTION AND DRILLING UNIT I I I I I I I Surface • I I I I I I I Location_.from WS)—Line of quarter section I I 1 I I I I end—h.from IE/WI_Line of coiner section 1 I I WELL ACTIVITY WELL STATUS TYPE OF PERMIT W i t I 1 E C Class I C Operating C Individual I I I I I C Class II ❑Modification/Conversion C Area _:Brine Disposal C Proposed Number of Wells— I I I I I I C Enhanced Recovery C 1 Hydrocaroon Storage Gass 111 I I I I C Otner I 1 I 1 I I I I Lease Name Well Number L 5 NAME(S)AND ADDRESSES)OF NEW OWNERISI NAME AND ADDRESS OF NEW OPERATOR • Attach to this application a written agreement between the existing and new permittee containing a specific date for transfer of permit responsibility, coverage, and liability between them. The new permittee must show evidence of financial responsibility by the submission of surety bond, or I_ Other adequate assurance, such as financial statements or other materials acceptable to the director. L • • CERTIFICATION /certify under the penalty of law that 1 have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete.lam aware that there are significant penalties for submitting false information,including . the possibility of fine and imprisonment. (Ref. 40 CFR 144.32) NAME AND OFFICIAL TITLE(Please type or pant! SIGNATURE DATE SIGNED EPA Form 7520-7(2.84) Page 27 of 39 EPA Final Permit No. CO1516-02 11941079 m UNITED ST. 3 ENVIRONMENTAL PROTECTION AGENCY For: Approved WASHINGTON,DC 20460 On Mc. 2040-0042 Approval azp]rea 9-30-91 'EPA INJECTION WELL MONITORING REPORT YEAR I MONTH I MONTN I MONTH Injection Pressure IPSI) . I.Minimum 2.Average T.Maximum Injection Rate(Gal/Min) I I. Minimum _2.Average I.Maximum Annular Pressure IPSII Minimum F Ii :.Average I .1. Maximum Infection Volume(Gap I ' .Monthly Total i '..Yearly Cumulative noerature IF.) i 1 Minimum I.Average 1. Maximum L j I • 1. Minimum • _.Average I � L !. Maximum ( rot • Permit Number 1 N-me and Adorns of Permits* IIIF Name anc Official Tiue(Please type or pnnr Signature Date Signet 9d107q I EPA Form 752041 (2.84) Page 28 of 39 ED STATES ENVIRONMENTAL PROTECTION AGENCY form Approved WASHINGTON.DC 20460 OMB No.2040-0042 6 EPA Approval expires 9-30.86 COMPLETION REPORT FOR BRINE DISPOSAL. HYDROCARBON STORAGE, OR ENHANCED RECOVERY WELL NAME AND ADDRESS OF EXISTING PERMITTEE NAME AND ADDRESS OF SURFACE OWNER STATE COUNTY PERMIT NUMBER LOCATE WELL AND OUTLINE UNIT ON SECTION PUT — 640 ACRES SURFACE LOCATION DESCRIPTION N `A OF `A OF 'A SECTION TOWNSHIP RANGE I i I I I LOCATE WELL IN TWO DIRECTIONS FROM NEAREST ONES OF QUARTER SECTION AND DRIWNG UNIT I I I I I I I Surface Location—ft.from(N/SI—Line of quarter section I V I I I I I I I I 1 and_ft.from IE/WI_Line of curter section I I I ICI �I— WELL ACTIVITY TYPE OF PERMIT W E ❑ Brine Disposal 0 Individual Estimated Fracture Pressure I I I I 0 Ennanced Recovery ❑ Area of Injection Zone I I I I I I I I I I I I I I ❑ Hydrocarbon Storage Number of Walls I Anticipated Daily Inject=Volume(8b1s1 I Injection Interval I I I I I I q"ef°g° I Maximum I Feet to Feet I I I ; I I I I S Antic:oated Daily Infection Pressure(PSI' I Deotn to Bottom of Lowermost Fresnwater Formation Average I Maximum (Feet) Type of Infection Fluid(Check the appropriate blark(s) Lease Name I Well Number II 0 Salt Water 0 Brackish Water- 0 Fresh Water 0 Liquid Hydrocarbon 0 Other Name of Injection Zone Date Drilling Began Date Wall Completed Permeability of Injection Zone Date Drilling Completed Porosity of Injection Zone CASING AND TUBING CEMENT HOLE OD Size I Wt/Ft—Grade—New or Used Daom I Sacks Class I Deism I Bit Diameter — I I I • f I I —J I I I I I I I I I I I INJECTION ZONE STIMULATION I WIRE UNE LOGS.LIST EACH TYPE _I Interval Treats I Materials and Amount Used I Log Tees Logged Intervals I I I I I I I I I I = Complete Attachments A—E listed on the reverse. CERTIFICATION i I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate. andcomp/ere./errs aware that there ere significantpene/tiesforsubmitungfalse information,including the possibility of fine and imprisonment. (Ref. 40 CFR 144.32). i NAME AND OFFICIAL TITLE(Please type or pnntl DATE SIGNED 1 • Page 29 of � • EPA Final Permit No. COB1S- 0211 41079 cob cane TF2r,.1012• 4.1 - --- Form Aoprovl WS No.2000-0042.Approval expires 9.30-86 UNITED STATES yENI MTDL PROTEPROTECTION AGENCY WASHINGTON. .EPA WELL REWORK RECORD NAME AND ADDRESS OF CONTRACTOR NAME AND ADDRESS OF PERMITTEE . STATE COUNTY PERMIT NUMBER - LOCATE WELL AND OUTLINE UNIT ON UN SECTION PLOT—640 SURFACE LOCATION DESCRIPTION N V OF 'A OF 'A SECTION TOWNSHIP RANGE I I l i I i l l LOCATE WELL IN TWO DIRECTIONS FROM NEAREST LINES OF QUARTER SECTION AND DRILLING UN FT 1. I Surface ill I I I Location__h from IN/S)_—Line of owner section V I I I I I I I I i a-: !rpm'E/WI—'Line of curter section I --t I I I I i WELL ACTIVITY Total Depth Before Rework TYPE OF PERMIT I I I I I I I ❑Individual C Brine[cad R al C Area W I I I I I E C Enhanced Recovery Total Depth After Rework Numoer of Wells I I I I I C Hydrocarbon Storage - !, I I I Lease Name Date Rework Commenced Well Number I I II IIIIIII I I Date Rework Completed I I I I I I i S WELL CASING RECORD— BEFORE REWORK Casing Cement 1 Perforations - Acid or Fracture — I From I To Treatment Record Size I Death Sacks T"pe I I I I — I I I I r I I • I I I I I I I I I WELL CASING RECORD—AFTER REWORK(Indicate Additions end Changes Only) Perforations Acid or Fracture Casing Cement I To Treatment Record Deotn Sacks I Type From Size I I I I I I I I I I I I WIRE LINE LOGS.LIST EACH TYPE DESCRIBE REWORK OPERATIONS IN DETAIL . Logged TY Intervals USE ADDITIONAL SHEETS IF NECESSARY Log Types I CERTIFICATION • r /certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals • immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete.lam aware that there are significant penalties for submitting false information,including the possibility of fine and imprisonment. (Ref. 40 CFR 144.32). SIGNATURE - DATE SIGNED NAME AND OFFICIAL TITLE(Please type or prim') 941.079 , Page 30 of 39 J pan Final_ Parini t, No. C015.16__O2115_ . Form reel. CDS .'o. 2000-SAC2 Aooroval exolr es ?-a,-SI UNITE)STATES ENVIRONMENTAL PROTECTION AGENCI • WASHINGTON.OC 20-460 ,aEPA PLUGGING RECORD • NAME AND/..:70.CS5 OP __MtNtlhO C-.✓'al thl NAME ANO ADDRESS OF PERMIT TEE EE • PERMIT NUMBER S.A. ,CUNI' . LOCATE WE-L AND OUTLINE UNIT ON SECTION PLAT — 640 ACRES SURFACE LOCATION DESCRIPTION H 'A OF 'A OF 'A SECTION TOWNSHIP RANGE I I I I I I I LOCATE WELL IN TWO DIRECTIONS FROM NEAREST UNES OF QUARTER SECTION AND DRILLING UNIT I $educe ' I I I I I I I Lecanan_—.`-from IN/S1— Line of teener secnan I I I I I 1 I ant H.from fE eM —:one of coon!!art"n ,,,,c. n wescn> m entail T,r Nqn t e /Wig ns m.c« " I ��.�� TYPE OF:.UTriORIZATiON !Ns «cvw «« a mara,aw,m; uu a, «H .I I � ! I I I I I I I _ !naividuai Permit I re t :Area Permit I' 1 I I I I t ! I ! I ❑Rua I 1 Numner of Weil: I 1 I I 1 I ! I • i i I I I i 1 I Lease Name • • CASING AND TUBING RECORD AFTER PLUGGING WEL ACTIVTrr Mcmct 00,Yh.ACEM1,n Co Wahl PU:p3 I 0-^.ASS I -The anal°Metnec I ' S/FTI !TO SE PUT IN wE IFn ITO eE...Erne WEL' IA1I HOLE SIZE I C CLASS II I Tie own"gaoler Me:nee SSE i wIL 1Lt I pone Mandl ,. f TM TwPlUe menet G laments.Recown I I I C„ °+erera07.1Wan Steens U O I 1 ! C C.JSS te I I I • 1 ! PLUG x1 *LUG :t ! PLUG :] PLUG a . ...G ss PLUG r6 - ___ 27 I CEMENTING-Q PLUG ANC)ABANDON DATA: I Eireor^o.*or rice,n wryer,Flue Will Se Placed Oncneel I :wet to Barmen of:uomo or Drill P,.e rt.) I I I I J Snort;ea of Cement To 84,Used luen meal I I I I _ I Volume To Be Pumped icy.G.1 • i i I 1 I•(yvu°a Too el Phi,'lit) i I I ! pnaaurea Toe el Plug Of neaea It.) ( _ ;,ore w:.DAL/G.0.1 i I '-+a Carmine or CTner Material(Class MI _I "ST A_-CPCN �.CLE ANO/OR "5RATED INTERVALS -.I Te cram To — I • I I I I I I J Bremen of Cementer or AUNonhW Representative Sign.wre of EPA Reoresentative l CERTIFICATION • - I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified person- nel :nearly Bather and evaluate the information su'anitted. Based on my ina_iry of the person or persons who manage the system, Dr those persons directly responsible for gathering the intonation, the information sutmitted is, to the best of my knowledge and belief, true. accurate. and tinplate. Ian aware that there are significant penalties for sumnit:ing false information, including the possibility of fine 'and imprinsonhlent for knowing violations. (REF. 10 cn 122.22) .V I DATE SIGNED Q ry .VANE ANC OFFICIAL I°(Please type or pang SIGNATURE 9410'If Pace 31 of 39 _ APPENDIX C (PLUGGING & ABANDONMENT PLAN) Page 32 of 39 EPA Final Permit No. CO1516-02115 941079 Plugging and Abandonment Plan Plug #1 - Within the 5-1/2 inch casing, set a 60-sack Class "G" cement plug from 9 ,220 feet to 9 , 476 feet, the plug back depth of the well . Plug #2 - Within the 7-7/8 inch borehole, set a 50-sack Class "G" cement plug from 7, 220 feet (or a minimum of 50 feet above the 5-1/2 inch casing stub) , to a depth of 7, 400 feet (or a minimum of 50 feet below the casing stub) . Plug #3 - Within the 8-5/8 inch surface casing and the 7-7/8 inch borehole, set a 30-sack Class "G" cement plug from 709 feet (50 feet above the surface casing shoe) to 820 feet, or to a minimum of 50 feet below the surface casing shoe. Plug #4 - Within the 8-5/8 inch surface casing, set a 20- sack Class "G" cement plug from the surface to a minimum depth of 50 feet. Page 33 of 39 EPA Final Permit No. CO1516-02115 941079 APPENDIX D (INJECTION FLUID SOURCES) Page 34 of 39 EPA Final Permit No. CO1516-02115 9?:1079 Injection Fluid Sources The following sources of fluids are approved for injection into the Wright' s Disposal , Inc. Suckla Farms #1 well . This listing may be appended according to the terms of Part II, Section C. 6 . of this permit. Class II fluid sources (exempt) : 1415 Corporation B 1415 Corporation C 1415 Corporation D GU 1415 Corporation GU Ackerson, Doris GU B Ackerson, Ellanora M GU Adams, Ted GU Adler, Carl B GU Amoco-Charter-Schneider Amoco-Energy-Smits C Unit Anderson Family Trust C Anderson Trust 1-A Anderson Trust 2-A Anderson, Maude GU Anderson, Mel GU Annis #1 / Narco Baldwin, Robert E A Unit Bangert 2-19 / Narco Bangert 3-19 / Narco Beebee Draw Bell, Charles C Berger 32-23C . Berger A Berger, Jack Berger, Jack C Unit Bergman Berry, Florence Unit Bohlender 8-5 Boock #1 Boulder Bank Boulder Bank 3-7 Box Elder #1 Box Elder 27-1 Box Elder 27-2 Brewer, J Pooling Unit Bromley Estates #1 Brown, Charles M Burch, Robert M Caldwell "H" Unit #1 Calhoun, James T Unit Camenish, Phillip GU Camp, Lloyd & Mel UT-True Carter, Keith A Unit Chadburn Warren Unit-True Champlin (Sec 10) Champlin (Sec 14) Champlin 86 "Q" #1 / Amoco Champlin 86 UT "D" #1 Champlin 203 "A" #1 / Amoco Chikuma, Harry S "B" -True Christensen, Nels Unit Clark, Francis Doughty B Conner 24-34 Consolidation #1 Cosslett E GU Cundall #2 / Basin Damiana, Frank Unit Damstedt 1-4 Deepe, Carl R #1 Deepe, Carl R #2 Deepe, Carl R C Degenhart #3 Degenhart #4 Delventhal, Emma GU Devore Devore 3-34 Dier #1Dodero, Louis A Unit B Doversberger Unit A Drew Dry Creek #1 / Basin Eastman, Jack W Edith Ann #1 / Narco Edkam 4-33 Edwards, William J GU Ehler #1 / Basin Ehler, John H Eichthaler, Margaret Eichthaler, Margeret "B" Elkhorn Co B Elkhorn Company Elliot, Karl GU - True Emerson 2-29J Page 35 of 39 EPA Final Permit No. CO1516-02115 9410'79 Emerson 3-29J Emerson 34-29 Erie Eight "E" Unit 1 Fee 3- 6 / Coors Fiechtner Pooling Unit Findlay, Marie A #1 Fonay / Vessels Foreman #4 Franklin-Wallace #1 Freeman / Resource Tech Fri 2-18 Frisbie 1 Frisbie 2 Frisbie 3 Frisbie, Norman D Unit Frisbie, Norman D Unit-TrueFt St Vrain #4 Ft St Vrain #11 Futura Horse Village 41-3 Gee, William GU #2 Geist Unit "A" #1 Geitz, Helmer Unit Gerhardt, George H Gerhardt, Marie #2 Gerhardt, Marie B Godding Gulch #1 Gordon Turkey Farms Gordon Turkey Farms Unit D Gould, Lee G Jr Unit Graham, Elizabeth Unit C Grant Grant Brothers 33-23C Grattan #1 / Narco Greeley Nat' l Bank #1 Greeley Nat' l Bank #2 Greeley National Bank B Green #1 Green #1 Guadasnoli 1 Guadasnoli 2 Guertner, Frank . Gunzner, John Unit Gurtler #1 / Narco Guthrie #4 Guthrie #7 Guthrie #8 Guthrie 2-3 Hagans, Vern Hanks, Dwight 6 B Hanks, Dwight G Pooling Unit Hanse, Castor Hansen, Glen GU "B" Hart A Hart GU "A" - True Hart, Martin T Hart, Martin T "E" #1 Hart, Martin T B Unit Hart, Martin T F Unit Hart, Martin T H Hart, Martin Unit C Hein, Willard G U #2 Heinze-Herbers "B" Unit Heit, Antone C Unit Hinsley #2J Hopp, Conrad Jr. GU Horst 43-21 Horst 44-21 Horton, Glen Hosmer 34-43 Howard, David Unit C Hubert, Noel Unit - True Huett, Joseph "B" #1 Huron H-1 / Vessels Hurt #1 Jacobucci #1 Jacobucci #2 Jacobucci #2 Jacobucci 2 Jacobucci 4 Jacobucci 5 Jacobucci, Paul Jillson Gas Unit Jim Creek 1-29 Johnson, Rolland B Unit Johnson-Niven 1-13 Jones #1 Jones #2 Jones #3 Jones #4 Karma 126 / Garrett Kiefer Pooling Unit Kortum #1 Kortum #2 Kortum #3 Kortum #4 Kortum #5 Kortum #6 Kortum #7 Kugel 1-18 Kuipers Pooling Unit Page 36 of 39 EPA Final Permit No. CO1516-02115 • 9410'79 Kunzman, John A Kurtz, Albert Unit C - True Lambrecht, August GU Lanson' s Farm Lauridson Eti #1 Lauridson Eti #2 Leonard 3-21J Leonard 4-21J Longmont Farms GU B Lower Latham Res 2- 8G Mathisen, James H Unit B Matushima, George Mayer, Walter GU McCoy, Phillip S GU "D" McCoy, Phillip Unit #1 McCoy, Phillip Unit B McElwain #3 Mcelwain, Mark #1 Mcelwain, Mark #2 Mcelwain, Mark #3 Mcelwain, Mark #4 Mcelwain, Mark #5 Mcelwain, Mark #6 Mcelwain, Mark #7 Mcelwain, Mark #8 Mcelwain, Mark #9 Mcelwain, Mark #10 Mcelwain, Mark #11 Mcelwain, Mark #12 Mcelwain, Mark #13 Mcelwain, Mark #14 Mcelwain, Mark #15 Mcelwain, Mark #16 McHale, Hazel McHale, Merle Unit McKay Lake McMillen Trust 19-4/5 / Snyder Merideth #2 / Basin Milheim #1 Millard Miller 4-20J Miller, Carl A Unit F Miller, Carl C #2 Miller, Donald E Unit c Miller, Niles S Unit Milton Lake Montoya, Pete Montoya, Pete B Moore 3-1 Moore 31-24C Morrison #3 / Basin Morrison #4 / Basin Moser "C" Unit #2 Musick Gas Unit #1N Colorado #8 / Basin N. York #3 / Basin Naeve, D. K. GU Nelson 41-33 Nelson 42-33 Nelson, Harold Unit A Nishimoto, George GU Norgren, Donald K C - True Norgren, Donald K Unit E North Colo Blvd #1 North Colo Blvd #2 North Quebec #1 North Quebec #2 North Quebec #3 North Quebec #4 Northstar 24-1 Northstar 24-2 Olin Oster-Molander "A" Patricia / Oaks Res Pehr Pooling Unit Peltier Perrin B Pete Rock #1 / Narco Peterson, Carl A Premium Turkey Farms B Premium Turkey Farms C Purse, Helen Marie Purse, Helen Marie Unit B Quinn, Thomas F "B" Rademacher, Albert GU Rademacher, Edward Unit Rademacher, Louis J GU Rademacher, Theo J Unit Ranchero #1 Ranchero #2 Reed, Williams D "B1" Rocky Mountain Fuel C Rocky Mountain Fuel D Rocky Mountain Fuel F Rocky Mountain Fuel G Rocky Mountain Fuel Pool Rocky Mtn Coors Spring Wa Rocky Mtn Fuel Co E Rural Land 32-31 #2 Russell, T L Unit C - True Page 37 of 39 . EPA Final Permit No. CO1516-02115 941079 Russell, Thomas L E Russsell, T L Unit C 1 Sack, Albert GU Sakata 11-36 / Bataa Sarchet, Raymond B Scheidt State 5-16 Scheidt State 6-16 Schiedt - State 1-16 Schmidt 30-13/14 / Snyder Schmidt, William F G U Schutt, Marvin E Sebold, Sebold, Dorothy "B" #1 Sebold, Dorothy - True #1 Shaw, Floyd C Unit Spindle Consolidation #2 Spindle Consolidation #3 Spindle Consolidation #4 Spindle Consolidation #5 Spindle Consolidation #6 Spindle Consolidation #7 Spindle Plant / Amoco Sprague #2-9 Starks #1 State of Colorado AS #1 State of Colorado AS #2 Steiber, George "B" Stermole, Franklin Unit Stolz, John Henry Jr. Stolz, John Jenry Jr. B Stonehocker 8-5 Strear, Sidney Suckla A Unit Suckla Farms E Suckla Farms Inc "B" Suckla Farms Inc F Suckla, Frank J Teets Unit Teets, Bernard E Teets, Bernard E "B" Tipperary #1 Trunza, Benjamin GU Twombley #1 Twombley, Margaret B1 UPRC 21-5J UPRR 17-16J / Snyder UPRR 22 Pam Am "D" #2 UPRR 22 Pam Am GU "B" True 1 UPRR 22 Pan Am GU U UPRR 38 Pam Am "S" True UPRR 38 Pan Am UT /W/ UPRR 41 Pan Am "I" #1 UPRR 41 Pan Am "K" #1 / Amoco UPRR 42 Pam Am AF UPRR 42 Pam Am G UPRR 42 Pan Am "D" - True #1 UPRR 42 Pan Am "D" - True #1 UPRR 42 Pan Am "L" #2 UPRR 42 Pan Am "M" UPRR 42 Pan Am "M" UPRR 42 Pan Am "X" True UPRR 42 Pan Am A UPRR 42 Pan Am AD UPRR 42 Pan Am AD UPRR 42 Pan Am AL UPRR 42 Pan Am AS UPRR 42 Pan Am B UPRR 42 Pan Am D UPRR 42 Pan Am J #2 UPRR 42 Pan Am K UPRR 42 Pan Am S UPRR 42 Pan Am/"AM" True UPRR 43 Pan Am "M" True UPRR 43 Pan Am "V" UPRR 43 Pan Am "Y" UPRR 43 Pan Am "Z" UT #1 UPRR 43 Pan Am AA #1 UPRR 43 Pan Am GUD UPRR 43 Pan Am J #1 UPRR 43 Pan Am J #2 UPRR 43 Pan Am K UPRR 43 Pan Am L #1 UPRR 43 Pan Am R UPRR 43 Pan Am T UPRR 43 Pan Am W UPRR 43 Pan Am X UPRR 50 Pan Am E UPRR 50 Pan Am G - True UPRR 50 Pan Am UT "M" #1 UPRR 51 Pan Am "H" #1 / Amoco Van Scoyk #1 Vincent #3 , Rollie J Vincent, Rollie J #1 Vincent, Rollie J #2 Vonasek, Alvin GU B Vonasek, Alvin Unit "C" Vynckier, Donald M Wagner #1 Wagner, Herman GU Walking, Cary Unit "A" Page 38 of 39 EPA Final Permit No. CO1516-02115 941079 Wardell 18-12J / Snyder Watada Farms, Inc True #1 Wattenberg Gas Plant / Coors Webber, Elmer "A" #1 _ Weld County Pooling Unit Wethington, William Wierman #1 Wierman #2 Wierman #3 Wiggett, Alice Wolff Gardens 23 Wolff Gardens 24-30 Wyman #1 / Basin YB-2 / L. P. Moore Yoxall Farms Yoxall Farms Inc B #2 Yoxall Farms Inc Unit C Yurk, Norman GU B UST cleanup sites (exempt) : Nonhazardous industrial fluid sources : Page 39 of 39 EPA Final Permit No. CO1516-02115 • 9.410'x' REVISED STATEMENT OF BASIS • WRIGHT' S DISPOSAL, INC. SUCKLA FARMS #1, CLASS I WELL, WELD COUNTY, COLORADO EPA PERMIT NUMBER: CO1516-02115 CONTACT: John A. Carson U.S . Environmental Protection Agency UIC Implementation Section, 8WM-DW 999 18th Street, Suite 500 Denver, Colorado 80202-2466 Telephone: (303) 293-1435 DESCRIPTION OF FACILITY AND BACKGROUND INFORMATION: On September 21, 1989 , Wright' s Disposal, Inc. , Westminster, Colorado, made application for a Class I underground injection control permit for injection of nonhazardous industrial waste fluids into the Lyons Formation, between the depths of 9 , 276 feet and 9 , 418 feet. Total dissolved solids (TDS) content of this formation is 33 , 240 milligrams per liter (mg/1) in the vicinity of the injection facility; therefore, an aquifer exemption is not required. The Suckla Farms #1 has been in operation as a commercial Class II salt water disposal well since July 15 , 1989 , under a permit issued by the Colorado Oil and Gas Conservation Commission (COGCC) . The injection zone is the Lyons Formation, within the same interval as noted above; all fluid injected to date has been produced water from oil and gas fields in Adams, Arapahoe, Boulder, and Weld Counties . This permit application is for a Class I well, which will also authorize the Suckla Farms #1 to dispose of nonhazardous industrial fluids . These fluids will consist of reclaimed water associated with the removal of underground fuel storage tanks, pit water from oil field wash pits, contaminated surface water from construction sites, stored fuels, and other nonhazardous industrial waste fluids from the same counties as above, plus the Denver and Colorado Springs areas . The permittee has requested that a maximum injection rate be set at 2, 100 barrels of water per day (oil field water plus industrial waste fluid) , with an average rate of 1, 700 BWPD. Anticipated maximum surface injection pressure is 2, 000 pounds per square inch gauge (psig) , wit:. an average injection pressure of 900 psig. The operation covered by the application is in a portion of the Spindle Field, located in the SE 1/4 of the NW 1/4 of Section 10, TIN, R67W, in Weld County, Colorado. The applicant has notified all surface landowners within one-quarter (1/4) mile of the disposal well of their intent to apply fr a Class I permit. 911,01S Prior to commencement of injection as a Class I well, the Suckla Farms #1 must demonstrate mechanical integrity. The demonstration must be performed and witnessed by representatives of the EPA and shall consist of two parts : (1) a casing/tubing annulus pressure test to verify the absence of leaks in the casing, tubing, and packer, and (2) an oxygen activation log and temperature log to verify that no movement of fluids exists outside the casing. Written authorization to begin injection as a Class I well will be given subsequent to the mechanical integrity demonstrations . Wright' s Disposal, Inc. has submitted all required information and data necessary for permit issuance in accordance with 40 CFR Parts 124, 144, 146 and 147, and a final permit has been prepared. The permit will be issued for a period of ten (10) years; no reapplication will be necessary during this period, unless the permit is terminated for reasonable cause (40 CFR 144 .39 , 144 .40 and 144 .41) . However, the permit will be reviewed at least once every five (5) years. _ This Statement of Basis gives the derivation of the site- specific permit conditions and reasons for them. The referenced sections and conditions correspond to the sections and conditions in Permit C01516-02115 . The general permit conditions for which the content is mandatory and not subject to site specific differences (based on 40 CFR Parts 124, 144, 146 and 147) , are not included in the discussion. PART II, Section A WELL CONSTRUCTION REQUIREMENTS Casing and Cementing (Condition 1) Casing and cementing details were submitted with the permit application. For the injection well, construction is as follows : (1) Surface casing (8-5/8 inch) is set in a 12-1/4 inch diameter hole to a depth of 759 feet below Kelly Bushing (KB) . The cement used to secure the casing was circulated to the surface, isolating the casing from the wellbore. (2) Long string casing (5-1/2 inch) is set in a 7-7/8 inch diameter hole to a depth of 9 , 557 KB. A cement bond log of the well indicates good cement bonding from 8, 398 feet to total depth; this includes 875 feet of • section above the injection zone. 2 9410'743 Underground sources of drinking water (USDW) in this area consist of the Arapahoe and Laramie-Fox Hills Formations, which extend from a few feet below ground surface to a depth of approximately 700 feet; both formations are behind cemented surface casing. There are two domestic water wells within a one-mile radius of the injection well, the deepest being completed in the Arapahoe Formation at a depth of 54 feet. The confining zone above the Lyons injection interval consists of 300 feet of shale and interbedded siltstones; the entire confining zone is cemented behind long string casing. Correlation of well logs in the area and seismic data indicate that no faulting is present above the injection zone in the vicinity of the well . Based on the construction and cementing details of the well, it appears that all USDWs in this area are adequately protected. Tubing and Packer Specifications (Condition 2) The tubing information (2-7/8 inch) submitted by the applicant is incorporated into the permit and shall be binding on the permittee. The depth of the packer is 9,240 feet, which is 36 feet above the top of the perforated interval of the injection zone. In no instance is the packer to be more than 50 feet above the uppermost perforations. Monitoring Devices (Condition 3) The permittee shall install, within thirty (30) days of the effective date of this permit, continuous recording devices which will monitor the operation of the well; these devices shall be maintained for the operating life of the well . The monitoring devices shall continuously monitor: (1) injection pressure; (2) casinghead pressure of the tubing/casing annular space; and (3) flow rate and volume. The tubing/casing annulus is to be filled with fluid and maintained under a minimum positive pressure of 200 psig. This may be achieved through the use of an above-ground fluid reservoir with a gas cap of nitrogen to maintain the positive pressure. A continuous recording of injection volume is to be accomplished by use of a cumulative volume totalizer. The permittee shall provide and maintain in good operating condition: a 1/2 inch fitting with a cut-off valve at the wellhead on the tubing, and a similar fitting and cut-off valve for the casing/tubing annulus. These valves -shall be positioned to allow the attachment of pressure gauges certified for ninety- five (95) percent accuracy, or better, throughout the range of 3 94107' The pressure fall-off tests shall involve injecting fluids at a constant rate for a sufficient period of time until the reservoir pressure reaches stability, followed by a shut-in period of sufficient duration to establish a valid observation of a pressure fall-off curve as the reservoir reaches ambient pressure. It is important that the initial and subsequent tests follow the same test procedure, in order that valid comparisons of reservoir pressure, permeability, and porosity can be made. The permittee shall analyze test results and provide an annual report which compares the results with previous test data. PART II, Section B CORRECTIVE ACTION There are no other wells within the 1/4-mile area of review that penetrate the injection zone; therefore, no corrective action is required. PART II, Section C WELL OPERATION Prior to Commencing Injection (Condition 1) Class I nonhazardous injection operations will not be allowed to commence until mechanical integrity tests have been performed and witnessed according to the guidelines discussed in the permit. These integrity tests are to include a standard tubing/casing annulus pressure test, and an oxygen activation log and temperature log of the well. Additional tests to be performed prior to commencement of injection operations are a step-rate test and a pressure fall-off test. These logs and tests will be planned, and must be approved by the Director, prior to being conducted in the well. Mechanical Integrity (Condition 2) A tubing/casing annulus pressure test must be repeated at least every two (2) years in order to demonstrate continued tubing, packer, and casing integrity. The absence of any flow behind casing must also be demonstrated; this shall be initially accomplished by performing an oxygen activation log and a temperature log, with subsequent tests being a radioactive tracer survey and/or temperature log performed at five (5) year intervals. Use of a temperature log in lieu of a radioactive tracer survey will be dependent on previous logging results . Injection Interval (Condition 3) Injection will be limited to the Lyons Formation, through perforations between the depths of 9 , 276 and 9 , 418 feet. Total perforated interval is 142 feet, with the entire interval being available for fill up. Injection Pressure Limitation (Condition 4) Surface injection pressure shall be limited initially to 2, 397 psig, slightly less than the 2, 475 psig limit previously established for the well by the COGCC. Actual maximum injection pressure will be determined on the basis of a step-rate injectivity test which is required for the Lyons injection zone. Permit provisions have been made that allow the operator to request an increase in the injection pressure. The surface injection pressure for this well was established on the basis a formation fracture pressure value oif 0 . 70 psig/ft submitted by the permittee. Using this value, a theoretical maximum allowable surface injection pressure was calculated as shown below: ' 5 941079 FPS = (FG) (h) - (S g) (0 .433) (h) Where, FPS = Fracture Pressure at the Surface (psig) FG = fracture gradient = ,assumed to be 0 . 70 psig/ft h = height of fluid column = 9276 feet (top Lyons perfs) Sg = specific gravity of fluid = 1.02 FPS = (0 .70) (9276) - (1. 02) (0 .433) (9276) FPS = 6493 - 4096 = 2397 psig Injection Volume Limitation (Condition 5) Cumulative injection volume of oil field produced water and nonhazardous fluids will be limited to 8, 300, 000 barrels. This volume was calculated using the formula shown below, which indicates the amount of fluid required to fill up the portion of the reservoir within a 1/4-mile radius around the injection well . The calculation also gives an indication of the lateral extent of the injection plume when the cumulative volume has been injected; however, a more definitive plume boundary will be determined from the evaluation of pressure fall-off tests and monitoring records of injection operations at the time of scheduled five-year reviews . V = (irr2hn) /5 . 615 Where, V = maximum cumulative Volume (bbl) r = radial distance of 1/4-mile (ft) h = height of injection zone available for fill up (ft) n = porosity of injection zone (decimal percent) 5 . 615 = conversion factor (barrels and ft ) Calculation of the total, theoretical volume available (V) is accomplished by substituting 1320 for "r" , 142 for "h" , and 0 . 06 for "n" . V = ( (ir) (1320) 2 (142) (0 . 06) 1 /5 . 615 = 8, 301, 706 barrels The injection rate will not be limited, but in no instance shall the injection pressure exceed that listed in Part II, Section C, (Condition 4) , above, or a pressure determined by subsequent step-rate tests. When the maximum cumulative volume is reached, EPA will make a decision whether to extend the limits of the injection zone, or to terminate the permit . 6 941479 Injection Fluid Limitation (Condition 6) Fluids injected into the Suckle Farms #1 shall be limited to produced oil field waters, as authorized under the provisions of the previously issued Class II permit, plus nonhazardous industrial waste fluids, as provided for in this Class I permit. The only industrial fluids approved for injection are as follows: (a) reclaimed water associated with the removal of underground fuel storage tanks; (b) pit water from oil field wash pits, if analyzed as nonhazardous; (c) contaminated surface water from construction sites; (d) stored fuels, if analyzed as nonhazardous; and (e) nonhazardous industrial waste fluids that have been approved for disposal by the Director and listed in Appendix D of the permit. PART II, Section D MONITORING, RECORDKEEPING AND REPORTING OF RESULTS Iniection Well Monitoring Program (Condition 1) EPA regulations (40 CFR Part 146 . 13) require continuous monitoring and recording of injection pressure, flow rate, volume, and tubing/casing annulus pressure. The permittee is also required to analyze water quality of the injected fluids . All Class I industrial waste fluids delivered to the facility will be sampled for fluid analysis prior to delivery, or prior to being transferred to on-site 500-barrel storage tanks . These fluid samples shall be analyzed for chemical, physical, radiological, and biological constituents, including pH and conductivity. If the analyses of several loads from the same source indicate little or no change, the Director may elect to waive the requirement that each load be sampled. However, one load of industrial waste coming from the same source (where the process is not likely to change) must be tested each month prior to being transferred to on-site tanks . A flow meter will measure the quantity )f Class I fluids pumped from the storage tanks to the Class II injection system. The commingled fluids will be sampled for analysis at random, but not less than once every three months. This final analysis shall include a determination of total dissolved solids, pH, specific gravity, specific conductivity, major cations and anions, oil and . grease, and total organic carbon. 7 911079 The permit requires that the average, maximum, and minimum monthly values of injection pressure, flow rate and volume, and annular pressure be reported quarterly, along with the data from fluid analyses . In addition to routine quarterly reporting, the permittee is required to report the results of any mechanical integrity test, well workover, logging, or testing of the well or injection zone. These reports are due within sixty (60) days of the completion of the activity, or at the time of the next scheduled quarterly report, whichever is sooner. The permittee is being required to keep records concerning: (1) the location, date and time, and type of fluids picked up for transport to the injection well, (2) the nature and composition of injection fluids, (3) all monitoring data including the continuous pressure monitoring charts, and (4) copies of all reports sent to EPA, in accordance with the minimum recordkeeping regulatory requirements for Class I wells. PART II, Section E PLUGGING AND ABANDONMENT Plugging and Abandonment Plan (Condition 2) The plugging and abandonment plan (Appendix C) submitted by the permittee, with revisions by EPA, is as follows: Plug #1 - Within the 5-1/2 inch casing, set a 60-sack Class "G" cement plug from 9 , 220 feet to 9 , 476 feet, the plug back depth of the well . Plug #2 - Within the 7-7/8 inch borehole, set a 50- sack Class "G" cement plug from 7, 220 feet (or a minimum of 50 feet above the 5-1/2 inch casing stub) , to a depth of 7, 400 feet (or a minimum of 50 feet below the casing stub) . Plug #3 - Within the 8-5/8 inch surface casing and the 7-7/8 inch borehole, set a 30-sack Class "G" cement plug from 709 feet (50 feet above the surface casing shoe) to 820 feet, or to a minimum of 50 feet below the surface casing shoe. Plug #4 - Within the 8-5/8 inch surface casing, set a 20-sack Class "G" cement plug from the surface to a minimum depth of 50 feet. 8 9?10'79 PART II, Section F FINANCIAL RESPONSIBILITY Demonstration of Financial Responsibility (Condition 1) The permittee has chosen to demonstrate financial responsibility through a Letter of Credit and Standby Trust Agreement, both of which have been evaluated and approved. Part III, Section E GENERAL DUTIES AND REQUIREMENTS Surface Leak Prevention (Condition 6) The permittee shall operate and maintain the surface facility, including tanks, pumps, piping, and truck unloading area in a manner which prevents fluids delivered for disposal from contaminating ground water. The permittee shall contract with an outside firm for an environmental audit of the facility twice each year, but no more frequent than four months apart. The audit will be for the purpose of evaluating the adequacy of facility operations and maintenance in preventing ground water contamination. Within thirty (30) days of the effective date of this permit, the permittee must submit for EPA approval a proposed plan for the environmental audit. Within sixty (60) days of the effective date of the permit, the permittee will provide EPA with a list of three firms capable of carrying out an audit . EPA will then select the firm to conduct the audit. 9 941079 Class I Injection Test Design and Analysis July 8-July 12, 1993 EPA Final Permit No. CO1516-02115 Suckle Farms Injection Well #1 Section 10 - T 1 N - R 67 W Weld County, Colorado Operator Wright's Disposal, Inc. Report Prepared by: Peterson Energy Management, Inc. 911079 PETERSON ENERGY MA TAGEMENT, INC. 1805 MORNING DRIVE (303) 669-7411 LOVELAND, CO 80538 August 28, 1993 John A. Carson Environmental Engineer Environmental Protection Agency 999 18th Street Denver, Colorado 80202-2405 Re: EPA Final Permit No. CO1516-02115 Wright's Disposal, Inc. Suckla Farms Injection Well #1 NE Sec. 10-T1N-R67W, Weld County, Colorado Dear Mr. Carson: On the following pages we have detailed and analysed the tests performed on the subject well July 8, 1993, through July 12, 1993. The test design is essentially that outlined by Wright's Disposal, Inc. (WDI) in their June 23, 1993 proposal to your agency. A pressure falloff test was conducted from steady-state injection conditions. This was followed by an annular mechanical integrity test and step-rate injection test. A radioactive tracer and temperature survey from the base of surface casing to total depth concluded the test procedure. Hard copies of the field data have been sent to the EPA by the service companies performing the tests. Our conclusion, after witnessing the tests in the field and subsequently reviewing the test data, is that the well casing, injection tubing string, tubing/casing injection packer, and cement bond in the near wellbore region are all mechanically competent. The test data shows conclusively that all injected fluids are presently being confined to the Lyons formation in the perforated interval from 9276' to 9418'. There is no indication from any of the test data that any fraction of the injected volume is exiting the wellbore at any point other than the presently perforated interval. We therefore recommend that the Suckla Farms Injection Well #1 be approved for Class I injection service. _._ The final portion of this report deals with the expected radius of influence of the fluids to be injected into the subject well. It is our conclusion, again after reviewing the available data, that the maximum permitted injection volume for the Suckla Farms #1 could be safely increased above the current 8,301,706 barrels. While this is not a matter of immediate concern to the present investigation, the issue will need to be addressed in the near future. 911079 Environmental Protection Agency CO1516-02115 August 27, 1993 Page 2 It has been a pleasure working with you on this project. Please advise us if your agency requires further information. Respectfully submitted, Andrew S. Peterson President ASP/sd Attachments 941079 Environmental Protection Agency CO1516-02115 August 27, 1993 Page 3 MECHANICAL INTEGRITY TEST This test was conducted on July 9, 1993. The tubing pressure at the start of the test was 300 psi. The tubing/casing annulus was pressured to 610 psi using a pump truck. Permit stipulations called for a differential of at least 200 psi between tubing and casing pressures. This was exceeded by 110 psi. The pump truck was then isolated from the annulus by a closed valve and the pump line was disconnected. Tubing and annulus pressures were then monitored with a continuous recording strip chart for the specified 45 minute interval, at which time the annulus pressure remained 610 psi. No annular pressure decrease was observed during the test. The shut in tubing pressure had declined to 250 psi at the conclusion of the mechanical integrity test. No communication between tubing and annulus was observed. A pressure drop on the annulus of ten percent (or 61 psi) would have been permissible during the 45 minute test interval, per EPA guidelines. There was no pressure drop noted on this test, indicating that there are no leaks in the injection system. This test shows conclusively that the injection tubing string, the well casing, and the packer that seals the annular space between the tubing and casing are all holding pressure and are not leaking. All injected fluids are therefore confined to the injection interval in the Lyons formation. The mechanical integrity test is scheduled to be repeated at two year intervals following Class I approval. STEP-RATE INJECTION TEST This test immediately followed the mechanical integrity test on July 9, 1993. The step rate injectivity test was designed to determine the formation breakdown pressure, fracture pressure, and instantaneous shut-in pressure. A maximum injection rate of 8 barrels-per-minute (BPM) was anticipated, and injection rates were chosen to span a range of 5%, 10%, 20%, 40%, 60%, 80%, and 100% of maximum. The test began at 0.4 BPM at 360 psi. No breakdown pressure was observed. Figure 1. shows the stabilized injection pressures plotted as a function of injection rate. The graph would be expected to show a decrease in slope at injection pressures exceeding the formation fracture pressure, since fracture propagation pressure is normally less than fracture initiation pressure. This test does not show a decrease in slope at any time. To quantify the change in slope, Figure 2. shows the change in slope per BPM, or the first derivative of the injection pressure graph. This graph shows a leveling off as the slope increases at a lesser rate, but the curve never develops a negative slope. This is shown also in Figure 3., the second d - 9 " 1"44" j 49 ' Suckle Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 6-021 1 5 4000 Figure 1 . 3500 -..._.._................._... a 3000----- Step Rate Injection Test - ------ w j 2500Lu — 2000 — a ¢ 1500— w ---- -- -- J 1000-..- ---- — - -- — — 500-- — — -- -- — — - la 0 1 2 3 4 5 6 7 8 RATE (bbl/min) 941079 Suckle Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 800 Figure 2. 700— co _ U 600 Slope Change-1st Derivative cc 500- w w n 400- w cc 300 — — w cc o_ 200- 100 0 j 2 3 4 5 6 7 8 RATE (bbl/min) 941079 Suckla Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 350 — — — — — -- Figure 3. 300 - z 250 -- - Q Slope Change-2nd Derivative O w 200- a. O J _ w 150- -- - -- O Q 100 cc50 - -- 0 I I I I I 0 1 2 3 4 5 6 7 8 RATE (bbl/min) 911079 Environmental Protection Agency CO1516-02115 August 27, 1993 Page 4 derivative of Figure 1., otherwise defined as the rate of change of the slope curve. The second derivative never goes below zero. This indicates that formation fracturing pressures were not reached at the rates and pressures achieved on this test. The final point on all graphs, at 8 BPM, is anomalously high. Friction pressures are evidently high enough at this pumping rate that they begin to mask the formation effects. The instantaneous shut-in pressure following the injectivity test was 610 psi. This test shows conclusively that an injection rate of 6.0 BPM, at a corresponding pressure of 2460 psi, will not cause formation fracturing. The exact value of formation fracturing pressure remains unknown at this time. While it is unlikely that formation fracturing occurred at the final 8 BPM rate, this cannot be proved conclusively due to the friction effects seen. Further refinement of the upper end of the step-rate curve, if deemed necessary at a later date, could be accomplished by incorporating friction reducers in the injection fluid. Until further investigation is warranted, the maximum permitted surface injection pressure should be set at no less than 2460 psi. RADIOACTIVE TRACER AND TEMPERATURE SURVEY On July 12, 1993, Oil Well Perforators, Inc., conducted a radioactive tracer and temperature survey. The well had been shut in 42 hours prior to commencement of the test. A static temperature pass was run from surface to 9424' plug-back-total-depth (PBTD). No anomalies were noted in the uphole intervals. The first indication of fluid storage was in the Lyons formation at 9320'. This indicated that no significant volume of injection water had accumulated at any place in the wellbore other than the permitted interval. Following the static temperature pass from surface, a high-definition static temperature pass was run from 9000' to 9424'. Again, no anomalies were noted. At this point one injection pump was turned on at a rate of 1.1 BPM (65 bbl/hr). A slug of water soluble radioactive tracer material was injected from the logging tool in the injection tubing string at 700' from surface. This slug was tracked with a gamma ray detector as it traveled down hole. The position of the slug was recorded on a continuous recording chart. The velocity at each point was calculated and compared to the velocity at the previous point to determine whether any fraction of the injection stream had exited the tubing. The velocities in the tubing string remained constant within experimental error, ranging from 189 ft/min to 204 ft /min. The expected theoretical velocity at 1.1 BPM would be 190 ft/min. Once the slug exited the tubing string at the injection packer, slug velocity in the casing ranged from 45 to 52 ft/min, compared to a theoretical value of 49 ft/min. After all radioactive material from the first slug had been pumped onto the formation, the isotope detectors were repositioned immediately above the injection zone. Another radioactive slug was ejected from the tool and the tool remained stationary for 10 minutes. No trace of radioactive material was detected coming back up the outside of the well casing. This shows conclusively that no upward channelling exists on the exterior of the well casing. The cement bond between the formation face and the casing is competent and shows no evidence of uphole communication. 941079 Environmental Protection Agency CO1516-02115 August 27, 1993 Page 5 If such communication had existed, the detectors would have picked up the presence of radioactive material coming back up the outside of the casing string. Following the radioactive tracer survey, with the well still injecting, a temperature survey was run from surface to PBTD. At this time the well had been on injection three hours. Again, no anomalies were noted. Following a further one hour wait while the well remained on injection, a final injection temperature profile was run, this time from 8300' to PBTD. No anomalies were noted. Total water injected during the survey was 243 bbls. The temperature and tracer surveys confirmed the results of the mechanical integrity test. All injected fluids are exiting the wellbore in the Lyons formation perforated interval from 9276' to 9418'. None of the testing performed July 8, 1993 to July 12, 1993, shows any evidence that injected fluids are exiting the wellbore at any point other than the permitted injection interval. A temperature survey will be performed at five year intervals following Class I approval. If deemed necessary, a radioactive tracer survey is to accompany the temperature survey. Should the results of the biennial mechanical integrity test continue to show no anomalies, it is hereby recommended that a radioactive tracer survey not be required. PRESSURE FALLOFF TEST The pressure falloff test was conducted July 8, 1993 to July 9, 1993. The well had been on injection all year at a recent average of 914 BWPD. A continuous recording pressure gauge accurate to .01 psi was installed at the surface. A stabilized surface injection pressure of 360.47 psia was recorded. The well was shut in for a 23-hour period at which time a surface shut-in pressure of 273.71 psia was recorded. This corresponds to a static bottom hole pressure of 4371 psia at 9276'. Table 1. shows a detailed pressure readout (psig). Figure 4. is a plot of the shut-in pressures (psia). The following analysis procedure is employed in this report: 1) Plot log op vs log at. Identify wellbore storage region. 2) Plot pressure vs log shut in time. Pick correct semi-log straight line portion. 3) Calculate permeability and skin factor. 4) Identify and interpret any anomalies. 9?1079 Suckla Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 370 360— Figure 4. 350 -- •c7) Pressure Falloff Test a 340- w rx 330 cocc — — — — — w n. 320 — — 310--w — --- --- J 300----- — : T" — — --- — — ------ -- — — 2700 2 4 6 8 10 12 14 16 18 20 22 24 SHUT-IN TIME (hrs) 911Q99 7 Table 1. LIGHTNING WIRELINE, INC . P.O. BOX 1531 • LOVELAND, COLORADO 80539 • 303-222-0922 • FAX 303.669-4077 Well Name : Suckla Farms Injection Well #1 Location: Section 10-t-T1N-R67W . Weld County . Colorado Operator : Wright ' s 0isposal , Incorporated Reference : Permit #C01516-02115 Time(min) Press Time(hrs) Press 0 348 . 47 3 311 . 99 5 345 . 59 4 307 . 46 10 342 . 91 5 302 . 51 15 340 . 13 6 299 . 63 20 337 . 96 7 297 . 36 25 336 . 52 8 294 . 27 30 334 . 25 9 290 . 36 35 333 . 02 10 287 . 88 40 332 . 19 11 286 . 44 45 330 . 34 12 284 . 58 50 329 . 31 13 282 . 73 55 328 . 28 14 280 . 87 60 327 . 04 15 279 . 02 70 325 . 18 16 276 . 34 80 323 . 54 17 274 . 69 90 321 . 89 18 273 . 25 100 319 . 83 19 271 . 19 110 318 . 59 20 268 . 10 120 317 . 15 21 266 . 45 22 264 . 80 23 261 . 71 941079 Environmental Protection Agency CO1516-02115 August 27, 1993 Page 6 Figure 5. shows a plot of log op versus log at. The unit-slope wellbore storage region ends at 0.3 hours. Figure 6. is a semi-log plot of shut-in pressure versus log at, after Miller, Dyes and Hutchinson (1950). The slope of the semi-log straight line immediately following the wellbore storage region is 25 psi/cycle. Figure 7. is a semi-log plot of shut-in pressure versus log(TP + At/at), after Homer (1951), where Tp is injection time and at is shut-in time. The slope of the correct semi-log line on the Homer plot is 26 psi/cycle. This information is used to calculate system permeability and skin factor (damage coefficient) as follows: Permeability 162 . 6 q u b where: k = permeability, and k = q = injection rate, BPD m h u = viscosity, cp b = volume factor, bbl/bbl m = slope, psi/cycle h = height, ft ( 162. 6) (-914) ( 1) ( 1) k = (-26 ) ( 142) k = 40 millidarcies Skin Factor f Piny - Po I k s = 1. 15 I - log + 3 . 23 m � uC rw2 where: pm, = shut in pressure @ 1 hr, psi po = producing pressure, psi 0 = porosity C, = total system compressibility, psi/psi rw = wellbore radius, ft 339 - 360 40 s = 1. 15 ! log + 3 .23 - 26 ( . 06) ( 1) ( 6x10-6) ( . 412) s = 1. 15 { .81 - 8. 82 +3 . 23 } s = -5.50 941079 Suckla Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 100 Figure 5. ch -- — d w CC -- -- - - - cr 0) a 1 p-- — log dp vs log dt w a 1 I I I I I III I I I hip! I 1 I I I 1 1 1 I I IIIII 0.01 0.1 1 10 SHUT IN TIME (hrs) 100 9ti079 Suckla Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 360 350--- --- Figure 6. 6 340-- — a c 330 — _ MDH Plot _--------__._-- u) 320 ------------- w cc 310— O = 300- _J - — — J in 290 --— - —280 --- - -- - ---------- 270 1 I 1 1 1 1111 I I 1 1 1 1 1 1 1 I I 1 1 1 1 1 110 I 1 1 1 1 1 1 001 0.01 0.1 1 1 SHUT IN TIME (hrs) 9'.11079 Suckla Farms Injection Well #1 Wright's Disposal, Inc. - CO1516-02115 360- 350— Figure 7. N 340-- a _ 330- Horner Plot . coo 320- — -- — - w e= a. 310 rn = 300 -- J -- J L 290 — — - - 280 - — — —.._..--- _.. 270 I I I I I I III ' ' I I 111111 100 1000 10000 100000 (Tp + dt) / dt 9410'79 Environmental Protection Agency CO1516-02115 August 27, 1993 Page 7 This test raises several questions. The semi-log straight line portion of the test lasts only 45 minutes. This could indicate that more than one storage system exists in the Lyons. The falloff test would probably have showed a second semi-log straight line if the test had a longer duration. The reservoir likely contains both matrix and fracture porosity. In support of this, the zone exhibits high injectivity, yet the log porosity is low. The openhole density-neutron log run in this well July 2, 1989, appears to be accurately calibrated, but shows fairly poor repeatability in the Lyons interval. This is an indication of fracture porosity. Approximately 1200 barrels of drilling mud were lost in the Lyons formation during drilling operations. This is also a good indication of fracture porosity. Core samples of the Lyons at other Weld County locations show significant fracturing. In addition, the calculated 40 millidarcy permeability is lower than the well's injectivity would indicate. The negative skin factor also could be an indicator of fracture porosity. Negative skin is normally seen in a stimulated wellbore. Here, the high conductivity fracture porosity may be acting as a stimulated zone upstream, and in series with, the low conductivity matrix porosity. No radius of investigation was calculated, as Earlougher (SPE, 1977, pg 19) states that systems completely recharged by an aquifer do not lend themselves to conventional radius of _ investigation calculations. The areal extent and high water flow capacity of the Lyons formation in this area makes it extremely likely that steady-state flow is occurring. This makes the concepts of transient behavior and pseudosteady-state analysis mathmatically tenuous. In light of this, the pressure falloff behavior seen in the latter stages of this test is puzzling, as one would expect to see stabilization, not continued pressure decrease. The pressure falloff test is scheduled to be repeated annually following Class I approval. Continued refinement of the test parameters is in order. MAXIMUM PERMITTED INJECTION VOLUME As stated in the cover letter, the question of the maximum cumulative volume to be injected will need to be addressed in the near future. A volumetric calculation of swept area depends on an accurate value of the total system porosity. As the above analysis indicates, the Lyons porosity system in the Suckla Farms Injection Well #1 is quite complex. The presence of fracture - porosity makes an exact determination of total system porosity difficult. Reservoir simulation and more sophisticated pressure transient testing would be required to adequately define this reservoir. In addition, the one-quarter mile radius specified in the permit may be unnecessarily small. There are no wells penetrating the Lyons formation in the area. The Lyons aquifer has a large areal extent and storage capacity. Confining the injection volume to an arbitrary 1/4 mile radius should be reevaluated in light of the information gained in this round of testing. 941079 .!`®et% UNITED ST, =S ENVIRONMENTAL PROTECT d AGENCY (147k 999 18tha I REGItajON VIII STREET - SUITE 500 scow DENVER, COLORADO 80202-2466 SEP 31993 Ref: 8WM-DW CERTIFIED MAIL RETURN RECEIPT REOUESTED Martin J. Wohnlich Wright' s Disposal, Inc. 2323 South Wadsworth, Suite 107 Denver, Colorado 80227 RE: UNDERGROUND INJECTION CONTROL (UIC) Authorization to Inject Suckla Farms No. 1 Well Class I Permit CO1516-02115 Weld County, Colorado Dear Mr. Wohnlich: Thank you for the recently submitted test data pertaining to the above-referenced injection well . This information included the results of a mechanical integrity test, temperature log, radioactive tracer survey, and step-rate test. These tests were witnessed by a representative of the Environmental Protection Agency (EPA) and have been evaluated and approved. Therefore, Wright' s has complied with all pertinent permit conditions [Part II, Sections A. 5 and C. 1. ] and may begin operation as a Class I nonhazardous industrial waste injection well . To date, the only Class I fluid proposed for injection is a hide tanning waste brine from the ConAgra Red Meat Company in Greeley, Colorado. The laboratory analysis submitted for this fluid has been evaluated by EPA and determined to be non- hazardous in nature, and therefore, is approved for injection. For your guidance regarding additional fluid analyses of this fluid, as well as, any new source of Class I waste fluid, you are referred to Part II, Section C. 6. and Section D. 1. of the permit . Specifically, the permit requires that analyses shall include determinations of BTEX (benzene, toluene, ethylbenzene, xylene) , characteristics of corrosivity, ignitability, and reactivity, plus toxicity using the toxicity characteristic leachate procedure (TCLP) . All analyses must be submitted to EPA for evaluation prior to obtaining approval for delivery to the injection plant facility. Analysis of commingled Class I and Class II fluids prior to injection is to be performed at random, but not less than once every three months, for total dissolved solids, pH, specific conductivity, specific gravity, major cations and anions, oil and grease, and total organic carbon. Printed on Recycled Paper 941078 A A Martin J. Wohnlich Wright' s Disposal, Inc. CO1516-02115 Page 2 You are also required, under Part III, Section E. 6 . of the permit, to submit within sixty (60) days the names of three firms capable of performing an environmental audit of the plant and injection well surface facilities. EPA will then select one firm to conduct an audit twice each year, with the audit report sent to this office for evaluation. The purpose of the audits is to evaluate the adequacy of facility operations and maintenance in preventing groundwater contamination. You are reminded that the maximum surface injection pressure for the well is currently 2, 397 pounds per square inch gauge (psig) . If necessary, an adjustment to this pressure limit may be made at a later date, based on the results of the afore- mentioned step-rate test of the Lyons injection zone. If you have any questions concerning this letter you may contact John Carson at (303) 293-1435 . Also. Please direct all correspondence to the attention of John Carson at Mail Code 8WM-DW. Thank you for your continued cooperation. Sincerely, / Wag . Do n, Director er Management Division / cc: Frank J. Suckla Suckla Farms, Inc. Eugene S . Reynolds Mayor, City of Fort Lupton Dennis Bicknell Colorado Oil & Gas Conservation Commission John S . Pickle Environmental Protection Services Division Weld County Keith A. Schuett Department of Planning Services Weld County Ken Mersfelder Wright' s Disposal, Inc. L 941079 PERMIT PLAN MAP 911079 CERTIFIED LIST OF NAMES AND ADDRESSES AND PARCEL IDENTIFICATION NUMBERS OF PROPERTY OWNERS WITHIN 500 FEET 911071 AFFIDAVIT OF INTEREST OWNERS SURFACE ESTATE Application No. Part of the SEa of the NW% and the SW% of the NE% of Section Subject Property 10, Township 1 North, Range 67 West of the 6th P.M. , Weld County, Colorado. STATE OF COLORADO ) ss. COUNTY OF WELD THE UNDERSIGNED, being first duly sworn, states that to the best of his or her knowledge the attached list is a true and accurate list of the names , addresses, and the corresponding Parcel Identification Number assigned by the Weld County Assessor of the owners' of property (the surface estate) within five hundred feet of the property under consideration This list was compiled from the records of the Weld County Assessor, or an ownership update from a title or abstract company or attorney, derived from such records, or from the records of the Weld County Clerk and Recorder. The list compiled from the records of the Weld County Assessor shall have been assembled within thirty days of the application's submission date. Kenneth F. Li # 792 The foregoing instrument was subscribed and sworn to before me this 9th day December , 19 93 , by Kenneth F. Lind WITNESS my hand and official seal. MY Commission expires: August 22, 1995. (-Li 62-tmfr Notary P lic 9I4075 NAMES OF OWNERS OF PROPERTY WITHIN 500 FEET Please print or type NAME ADDRESS, TOWN/CITY, ASSESSOR'S PARCEL STATE AND ZIP CODE IDENTIFICATION # 4468 WCR 19 Suckla Farms, Inc. Fort Lupton, CO 80621 146910000004 45 S. Lookout Mtn Circle Columbine Jersey Farms, Inc. Golden, CO 80401 146910000007 4468 WCR 19 Suckla Farms, Inc. Fort Lupton, CO 80621 146910000006 4468 WCR 19 Suckla Farms, Inc. Fort Lupton, CO 80621 146910000005 941079 CERTIFIED LIST OF NAMES AND ADDRESSES OF MINERAL OWNERS AND LESSEES 941079 AFFIDAVIT OF INTEREST OWNERS MINERALS AND/OR SUBSURFACE ESTATE Application No. Subject Property Part of the SE' of the NWn and the SW% of the NE1 of Section 10, Township 1 North, Range 67 West of the 6th P.M. , Weld County, Colorado. STATE OF COLORADO ) ss COUNTY OF WELD ) THE UNDERSIGNED, being first duly sworn, states that to the best of his or her knowledge the attached list is a true and accurate list of the names and addresses of all mineral owners and lessees of mineral owners on or under the parcel of land under as their names appear upon the records in the Weld County Clerk and Recorder's Office or from an ownership update from a title or abstract company or an attorney. 79'14-44 The foregoing instrument was subscribed and sworn to before me this 9th day of December , 1993 . WITNESS my hand and official seal. My Commission Expires: August 22, 1995 262/.4-1 Notary P l is 1 941079 OWNER OF MINERALS Frank J. Suckla and Suckla Farms, Inc . 4468 WCR 19 Fort Lupton, CO 80621 LESSEE Amoco Production Company P .O. Box 800 Denver, CO 80201 941079 Hello