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Home My WebLink About1999 Alpine Oil PoolI- Annual Surveillance Report t rr- - __j_ &-- July 2000 Annual Injection Repoll Alpine KD-02 Table of Contents Item 1 2 3 4 5 6 7 8 9 10 Introduction Injection Volumes Injection Rates Injection Pressures Annulus Pressures Depth Tags Surveillance Logging Fracture Growth Significant Well Events Wellwork Event Summary Page 3 3 3 4 4 5 5 10 10 11 Attachments May 1999 - April 2000 Injection Summary AOGCC Mechanical Integrity Form WD-02 Barton Test Chart record Diagnostic Analysis of PFO test Automatic Type Curve Match of PFO test Weekly Injection Plots PDS Memory Caliper Survey Summary Report Annual Injection Report Alpine WD-02 Introduction This report represents the first prepared in accordance with Disposal Injection Order No. 18, dated April 19, 1999 Rule 5 which requested an annual performance report be submitted to the Commission on or about July 1. In the spring of 2000, Disposal Injection Order No. 18A Rule 9 modified the submission date to on or before April 1. Additionally, this report is prepared in accordance with the requirements of 20 AAC 25.432 (Report of Underground Injection). Future annual injection summaries will be submitted in accordance with the April deadline authorized in Order 18A. This report focuses on well WD-02, which was drilled and completed in April. Injection commenced on May 15,1999 and the well has been in nearly continuous operation since that date. A second service well was drilled and completed within the Alpine Oil Pool in 2000. The CD1-19A was drilled and completed in June 2000. This well has not yet been placed into fulltime service and as such will be included in the next annual report. Injection Volumes Injection volumes are summarized on Attachment 3. Injection volumes for the 12-month period of May 1999 through April 2000 totaled 178,727 bbl. This represents a monthly average of 14,894 bbl. Cumulative injection since the start of the project is 178,727 bbl. This data is available in electronic database format (Microsoft Access) on CD. Please contact Mike Erwin or Tom Osterkamp to request a copy. Injection rates The injection pumps operate on level controls located on upstream holding tanks. Essentially 100% of the fluids injected are effluent from Alpine base camp, hence injection volumes swing in response to field manpower and staffing. The twin injection pumps are rated at a flat 15 gpm up to the 3200 psi allowable injection pressure. Injection rates increased from 15 gpm to 30 gpm as staffing increased for construction, but never actually exceeded 32 gpm, despite spikes in the data to the contrary. Daily injection rates are included in the weekly data plots (see Attachment 6). Annual Injection Report Alpine WI)-02 This data is available in electronic database format (Microsoft Access) on CD. Please contact Mike Erwin or Tom Osterkamp to request a copy. Injection Pressures Injection pressures are monitored and recorded continuously and summarized on the weekly data plots (Attachment 6). Normal wellhead pressure when the pump is offline ranges between 500 psi and 775 psi. With the pump running at 15 gpm injection pressure ranges between 1,450 psi and 1,800 psi, and averages approximately 1600 psi. Spikes in the data have been reported as high as 2800 psi, but do not represent normal operating conditions. This data is available in electronic database format (Microsoft Access) on CD. Please contact Mike Erwin or Tom Osterkamp to request a copy. Annulus Pressures Annulus pressures respond directly to cold fluid injection rates. Without injection, pressures prior to April 2000 would stabilize in the range of 550 to 650 psi. During injection over that same time period pressures would stabilize in the 50 to 100 psi range. When injection rates increased over the winter to match increasing camp output the additional cooling further suppressed annulus pressures below the gauge ranges as the casing went on a vacuum. In conjunction with the April mechanical integrity test conducted for the EPA an additional 314 bbl. of diesel was added to the annulus to increase annulus pressures. For that reason static annulus pressures are now expected in the range of 1250-1450 psi. Injection annulus pressures are now in the range of 750 to 1100 psi. Daily annulus pressures are included in the weekly data plots (Attachment 6). This data is available in electronic database format (Microsoft Access) on CD. Please contact Mike Erwin or Tom Osterkamp to request a copy. A mechanical integrity test (MIT) was conducted April 6,2000. Testing was performed by Little Red Hot Oil Services under the direction of Mark Chaney, Alpine Wells Specialist, and witnessed by John H. Crisp, AOGCC Inspector. Dual gauges monitored the inner annulus pressures during the testing. 0 Test records were kept for 60 minutes to confirm pressures had stabilized. Annual Injection Report Alpine WD-02 The casing pressure change was 40 psi during the 60-minute test period. This approximately 1 % pressure decline is well within the 10% allowed under the EPA permit in Part II.C.1 .b. The original circular Barton chart recorder and AOGCC Mechanical Integrity Test form were both signed by Mr. Crisp, the AOGCC inspector present for the test, and are included in this report (Attachments 1 & 2). Results of the test are summarized below. Actual 1 Relative I Tubing Casing Actual I Allowable 1 Time 1237 hrs The volume of diesel injected into the casing annulus to perform the MIT was 2.7 bbl. The volume of diesel expelled as the casing annulus depressurized was monitored and determined to be 2.7 bbl. 1252 hrs 1307 hrs 1322 hrs 1337 hrs Depth Tags Halliburton Energy Services (HES) under the supervision of Jack Kralick tagged the well on March 29,2000. PBTD was noted at a depth of 10,097' WLM. This correlates 4 fi higher than the previous tag dated April 6, 1999 at 1 0,10 1 ' WLM. Time Start Surveillance Logging In April of 2000, under the direction of the EPA, Phillips conducted a thorough 15 min 30 min 45 min 60 min examination of the mechanical condition of the wellbore through application of five (5) surveillance logs. Summaries of each are provided below. Pressure 1050 Calipev Survey A caliper survey was conducted in the intermediate casing. 950 950 950 950 - Proactive Diagnostic Services performed the caliper survey on March 29,2000. Two separate passes were completed for this initial caliper survey. The caliper tool selected utilizes 40 independent arms to survey the casing wall. Each arm is capable of recording a penetration as deep as 0.33". 0 Other than observing perforations in the injection interval, there were no recorded intervals of significant wall loss (exceeding 10%) noted. Percent of Wall Contacted by Feelers = 21% Distance Between Feelers = 0.39" Radial Measurement Accuracy = 0.0 1 " Pressure 3500 3475 3465 3460 3460 Casing SP 0 Casing SP 3500 25 35 40 40 3266 3150 3150 3 150 Annual Injection RepoH Alpine WD-02 Refemng only to the area of interest, those joints between the tubing tail and the top of the injection interval (casing joint numbers 1-36)> PDS reports the following: Nominal ID - 7" 26 lb/ft / Largest ID Measured I Jts14, 19&31 @6.298" 1 fi 19 @ 6.309" 24 12 0 Joints < 5% Penetration Joints 5%-10% Penetration Joints >lo% Penetration Joints <5% Metal Loss Joints 5%-10% Metal Loss Joints >lo% Metal Loss Overall the two caliper surveys compliment each other and concur on the overall Survey No. 1 6.276" 24 12 0 condition of the casing with respect to corrosion or metal loss. Survey No. 2 6.276" 32 4 0 Temperature Survey Base line temperature surveys were conducted April 1, with the follow-up survey 3 5 2 0 completed April 4,2000. Mark Chaney and Jack Kralick, Kupa..uk Well Specialists performed the logging. Witnesses from the AOGCC or the EPA were not present during this activity. On 4/1/2000 Schlumberger Well Services performed the baseline logging survey following nearly a solid month of routine water injection. The injection pumps were allowed to operate until 0850 the morning of the survey, approximately 10 minutes before logging tools proceeded into the well. Injection pressures while logging were approximately 1800 psi to "at least equal the maximum continuous injection pressure observed in the well in the previous 6 months" (EPA Permit 11003-A Part II.C.3.b.2) The associated injection rate was approximately 1.6 bpm. The highest injection rate employed was approximately 2.5 bpm at 2250 psi to exceed the fracture gradient determined in the April 11, 1999 step rate test of 1984 psi at 1.38 BPM. This rate was previously reported in the EPA Completion Report filed in April of 1999. The baseline survey consisted of the following actions: Obtaining pressure/temperature stop counts every 1000' going in the hole. A 20-minute stop count was obtained at mid-perfs to observe the wellbore stabilize. Little Red Hot Oil Services pumped 30 bbl. of diesel into the tubing for fkeeze protection while the logging tools recorded the pressures and temperatures. The fluids were pumped at 1 bpm and approximately 1650 psi. No further fluids were injected into the well after 1230 hrs on 4/1/2000 or for the duration of the temperature logging period. Fall-off pressures were recorded for 2 hours. The first baseline temperature pass was performed from 7600' - 10,135' MD. Annual Injection Report Alpine WD-02 6. A second baseline temperature pass was performed from 7600' - 10,130' MD. Telemetry problems with the logging tools required 3 splices in the second reported survey to create a continuous log. The splice intervals are; Section I Tor, I Bottom I 7. The logging tools were removed and the wellbore and injection pumps secured to prohibit further injection for the duration of the test. On April 4,2000 Schlumberger returned to perform the final temperature survey. Temperature logging began at approximately midnight, fully 83.5 hours after Little Red completed pumping the fi-eeze protection, and continued to completion in the early morning hours of April 5. The final survey consisted of the following runs: 1. A baseline temperature survey was recorded from 100' to 10,130'. Additionally, while going in the hole stop counts were recorded every 1000'. 2. One Main Temp Pass from 7600' to TD at 10,130' MD. 3. A Repeat Temp Pass over the same interval. 4. The logging tools were removed and the wellbore secured for the night. Oxygen Activation Method (Water Flow Log) To demonstrate the viability of the OA method and its application, on April 6,2000, Schlumberger ran the Water-Flow Log (WFL) in combination with a Profile Log (PFCS) in WD-02. The following is a summary of results from the WFL survey. 1. Tied in the tool to depth. 2. Stopped at Station 1 to verify tool function at 4081' MD. 3. Set the activation tool (minitron) at 9454' MD (4' above the top perforation at 9459'). No flow was detected behind the casing on any of 4 logging cycles while pumping at 1 bpm or 2.5 bpm. Logging was conducted in both slow and fast modes. 4. Set the activation tool at 9430' MD (29' above the top perforation). No flow was detected behind the casing in five logging periods while pumping at 1 bpm or 2.5 bpm. Logging speed was also varied during this test. 5. Set the activation tool at 7852' (13' above the packer). No flow behind the packer was detected in four logging periods while pumping at a stable 1 bpd1800 psi. These results are consistent with the results obtained the following day with a radioactive tracer tool. Annual Injection Report Alpine WD-02 Spinner Survey Following completion of the WFL segment, a spinner survey was conducted to analyze fluid movements as it exits the casing. The following is a summary of the results from this log. 1. Tied in on depth and verified tool performance. 2. Surveyed fiom the packer to TD (8000' - 10,050') at 1 bpm/1600 psi. 3. Surveyed stop counts at 1 bpd1600 psi. 4. Surveyed the Sadlerochit injection interval (9350'-10,070') at 2.5 bpm/2250 psi. 5. Surveyed stop counts at 2.5 bpd2250 psi. The splits shown concur with the results of the temperature survey as well as the First pass splits show the fluids leaving the wellbore as shown below. radioactive tracer survey. However, spinner analysis provides quantitative results when compared to the qualitative results of the temperature survey. Perforated Interval 9459'-9472' Radioactive Tracer Survey On April 7,2000, Lee Tool of Calgary (a Division of Schlumberger Canada Limited) Fluid % 0% performed a radioactive tracer survey. ProTechnics of New Orleans provided the liquid Iodine 13 1 isotope. Schlumberger Well Services coordinated the arrivals of both parties on the slope and provided the support services necessary to run the logs. There were no representatives fiom the EPA present during the logging. The survey consisted of the following runs: Stabilized temperature survey at 8002.5'. Baseline gamma ray pass from 8550'-10,070'. Tie-in passes to get on depth. Logged a 10-minute TemperatureIPressure survey at mid-perfs (9732' MD). The Lee Tool operator observed higher than expected GR counts, so to determine if the tools were leaking iodine the tool was picked up to 8800'. Further evaluation did not confirm the tool was leaking. The tool was moved into the rathole (10,075') while the wellbore was flushed with 70 bbl. of seawater. Annual Injection Report Alpine VD-02 6. Repeated gamma ray survey from 10,070 to 8800'. Based on good results of the repeat log continued with procedure. 7. Park at low (896 1 ') and high (9 106') and record gamma ray background counts. 8. Place tools at 9455' (4' above top perf at 9459' MD). After several attempts to eject iodine, POOH and reload tool. Appears iodine leaked out prematurely. 9. GIH to 8050'. Log in time drive, no leaks detected. 10. Tie back into depth control. 11. Return tool to 9455' (4' above top perf at 9459' MD). Eject slug while Little Red is injecting 1.6 bpm at stable 1800 psi. Normal tool response, monitor slug passage below tools. No channels or up flow detected behind perfs. 12. Increase rate to 2.5 bpm at 2250 psi, repeat slug ejection and log for 10 minutes in place. No sign of fluid movement or channels upward behind perforations. 13. Pull up to packer, and repeat tie-in. 14. Eject slug below packer at 7875'' chase downhole while pumping in at 1.0 bpm. Slug appears to have diluted to the point it is not detectable. 15. With tool at 9400' (59' above top perf at 9459') release slug and log upldown passes while chasing slug downhole pumping at 1 bpm at 1550 psi. 16. Return to 9400' and increase pump rates to 2.5 bpm. Release slug and log upldown passes while chasing slug downhole. 17. Return to 9400'' and eject remainder of the iodine solution to clear the tool. Flush with seawater into the perfs. 18. Freeze-protect the wellbore with diesel and methanol. 19. Pull the tools out of the wellbore and rig down. Interpreted Results The temperature decay, radioactive tracer and oxygen activation logs demonstrate that 100% of the injected fluids are exiting the casing through the perforations below the Sag River formation, well within the permitted injection interval. Review of the April 4 temperature survey shows very clearly that the majority of injected fluids are entering the formation in the interval between 9820-10,050'. This interval contains the most significant cooling anomaly in the wellbore below the packer. The primary injection interval is clearly the perforations at 9837'-9867' MD. The deepest point of injection is 10,022'MD. Secondary injection occurs at the perforations 10,017'- 10,047' MD. Minor amounts of fluid are escaping through the remaining perforations at 9876'-9896'. Both the temperature and spinner logs confirm these conclusions. These intervals are well below the top of the permitted injection interval (Sag River formation at 8938' MD). Minor temperature anomalies are noted around the top of the Sadlerochit and Sag River formations associated with changing lithology and varying heat transfer coefficients for Annual Injection Report Alpine KD-02 sandstones, limestones and shales. The baseline temperature logs taken April 1" did not identify any anomalies adjacent to the packer or tailpipe. Review of the radioactive tracer survey shows clearly 100% of the tracer fluids are entering the perforations in the Sadlerochit. No channels were detected behind the casing or above the top perforations. Additionally, no casing leaks were noted in the unperforated casing between the perforations. The oxygen activation tools (Water Flow Log) results concur with the temperature, spinner and radioactive tools to indicate; that all fluids are being conducted from the packer to the perforated interval, all fluids are exiting the casing within the permitted interval, and 0 there are no fluids migrating outside the permitted interval. Attachmentdsupporting Documents The PDS Memory Caliper Survey Summary Report is attached. Final copies of the logs will be distributed by Schlwnberger-Geoquest. Fracture Growth To date there is no apparent sustained fracture growth in WD-02. This is supported by pressure transient data collected in December, 1999 by surface pressure gauges during a routine shut-in period. Attachments 4 & 5 are analyzed plots of the pressure fall-off. Classic fracture derivative response is not evident. Instead, the best curve fit match was obtained modeling differential inner and outer rings of permeability around the wellbore. The pressure data and analyzed results are displayed on the plot. Significant Well Events The following events occurred during the reporting period and are reflected in the weekly data plots. 0513011999 The metering system 'locked up' during a test of the surface recording data system download process. Problems persisted until resolution was achieved and the equipment returned to normal operation on June 10. 071021199 Power failure problems killed the recorders. 07/29/1999 Computer data recording system malfunctioned. Restarted the next day. 0811011999 Generator problems shut down the injection system. Annual Injection Report Alpine WD-02 08/25/1999 Generator problems shut down the injection system. 10/29/1 999 Extreme cold weather created recording problems through 1 1/01 12/09/1999 Ice plugs in the wellhead spiked the tubing pressures and SD the system. 01/01/2000 During a data download the recording system locked up and remained down until Jan 5. 03/29/2000 Annual surveillance logging program begins. Intermittent power spikes, extreme cold weather and computer restarts have created misleading spikes in the data from time to time. Wellwork Summary The following summarizes all wellwork activity performed on WD-02 during the reporting period by the date the work was performed. Performed step rate test, ran RA tracer survey, MIT test of IA. Repeat MIT test of IA. Set SSSV. Perform baseline temperature survey. Reset SSSV. Commence water injection. Pull SSSV, run caliper survey. Base temp log. Warmback temperature passes completed. Final temperature passes. MIT the inner annulus. Perform WFL/Spinner log. Perform RAT log and reset SSSV. Attachment 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test OPERATOR: ~~QLo AL~IK* /YC . FIELDIUNITIPAD: (1~~146 WO - 01 DLJBOJ~C W~L( 1 PTD: 1 I 1 well #: I I t I 0 COMMENTS: PTD: well 91: 1 I I I I COMMENTS: PTD: we1 #: 1 COMMENTS: TBG. INJ. FLUID CODES TEST TYPE: F = FRESH WATER INJ. M = ANNULUS MONITORING G = GAS INJ. P = STD ANNULUS PRESSURE TEST S = SALT WATER INJ. R = INTERNAL RAD. TRACER SURVEY N = NOT INJECTING A = TEMPERATURE ANOMALY TEST D = DIFFERENTIAL TEMPERATURE TEST 0 Dklrlbutbn: orlg -Well File c -Operator c - Dalabese c - Tr(p Rpt Flle c - Inspector I I 1 0 PTD: well #: 1 I ANNULAR FLUID: P.P.G. Grad. DIESEL GLYCOL SALT WATER DRILLING MUD OTHER I 1 COMMENTS: 0 I OPERATOR REP SIGNATURE: /'6) 1? C 4 Y C 7 , AOGCC REP I I I MIT Form 9-23-99 Venlon.xls Attachment 3 May 1999 - April 2000 Injection Summary Disposal Order: API No.: Pool Code: Well: WD-02 Field: Colville River Unit Pool: Alpine Oil Pool Tubing Pressure Casing Pressure Max Average Pressure Pressure -- 853 210 633 232 692 281 607 257 558 191 555 183 556 172 629 152 564 107 388 26 254 7 1,492 783 Days in Max Operation Pressure Average Pressure 1,316 1,310 1,414 1,361 1,287 1,188 1,403 1,342 1,252 1,345 1,360 968 Daily Avg Injection Gas 273 385 386 412 406 373 458 444 52 1 674 920 744 Total Monthly Injection LicJuiJ Gas Cumulative Monthly Liquid Month May-99 Jun-99 Jul-99 August89 Sep-99 Oct-99 November-99 Dec-99 Jan-00 February-00 Mar-00 Apr-00 Numbers shown in bold italics are correcfed from the original reports filed with the AOGCC Q Fresmre 6 Derivative Wellbore ------ Radial Flow r Skin Radial Flow Regim Wellbore Storage [b.bkdpsiJ = 0%0,01852 PermeabUlQ [md] = 1.431 Apparent SMn [B] = -3.WtR M. Erwin, D, Fmyder OVlUOO 13:31:06 1 .M5 Time @ITS) ,,- Automatic Type Curve Match 100.OO . - Calculated Pressure ------- Calculated Derivative ia Measured Pressure A Measured Derivative WD-02 May 11-20,1999 WD-02 May 2l-Sl,l999 WD-02 June 1-1 0,1!399 -- AnnPress, psi -WHIP Limit mAnnPress Lima E P ul WD-02 June 1 1-20,1999 2,m i0o.a l ,800. 1,600 80.0 1,400 1,200 - AnnP~s, psi 60.0 8 -WHIP Limit E -AnnPress iimit gi i 1,m m 2 " 800 m.0 -. 7/1/99 0:00 i'mQ @OO tl%39 a00 7MsS @DO Tf5/99 0:OO 7/6/99 ROO 7nf923 0:00 7/@9 R00 7Ng9 D:O0 7/10/99 7/11/99 ROO 0:oo 1 $300 1,400, ---.AnnPress, psi I% 12L?o -WHIP LimR 1,000 800 WD-02 September 1-1 0,1999 2,om 160.00 1.800 1,600 80.00 1,400 - 1,2m W 60.00 n ai -WHIP Limit 5 1,000 Ql -&nPrdss Limit 2 IL 800 40.00 600 400 26.00 200 0 0.00 9M399 0:M) 9/2/98 QM) 9/3/99 0:OO 9/4/99 0:OO 9/5/@9 QQO 9W99 0:DO WIN 0:OO 9/8199 D;OO 9/9/99 0:OO 9/10/99 9/11/99 ROO 8:OO WD-02 September 21 -30,1999 60.00 - AnnPress, psi E P cn -WHIP Limit 6' AnnPress Limit 49.00 3 20.00 0.00 I99 9/22/99 9/23I99 9/24/99 9/25/99 9/26/99 9/27/99 9/28/99 9/29/99 9/30/99 1W1/99 ?0 0:OO 0:oo 0:oo 0:OO 0:oo 0:oo 0:oo 000 0:oo O:oo WD-02 October 1-1 0,1999 1,400 1,200 EO.00 1,000 ---- AnnPress, psi 800 40.00 400 20nO rm 0 0:o.o om' 1 OEOO L oom WD-02 November 1-10,1999 WD-02 November 21-30,1999 WD-02 December 1-10,1999 WD-02 December 11-20,1999 [--WHIP, psi WD-02 January 1-10,2000 WD02 January ll-%0,2€l00 WPQ2 January 21-31,200Q WD-02 February 1-10,2000 WD-02 February 11-20,2000 WD-02 February 2149,21100 WD-02 March 1 1-20,2000 WD-02 March 21 -31,2000 -WHIP Limit -AnnPress Limit WD-02 April 11-20,2000 April 2-l-30,2000 4nlKW 4/2;?/00 4/23/00 @24/DO 4f2Ed00 4J2WOO 4/27fOO 4/28/00 4h9/00 4/308)0 WtJOOQOO 090 0: DO QOO Q:Oo QOO 0:ou a00 0;Oa Roo Q00 Attachment 7, Page 1 Memory Multi-Finger Caliper Log Results Summary Company: ARC0 ALASKA Inc. Well: &WbO2' Log Date: March 29,2000 Field: Alpine Log No. : 4038 State: Alaska Run No.: I API No.: 50-1 03-20285-00 Pipe Desc.: 7" 26 Ib. Buttress Top Log Intvl: 7,975 Ft. (MD) Pipe Use: Prod. Casing Bot. Log Intvl: 10,126 Ft. (MD) Inspection Type : Corrosive Damage inspection - Baseline COMMENTS : This survey was run to assess and document the condition of the production casing with respect to mechanical and corrosive damages. Two separate passes over the casing interval below the tubing tail were made, with the results of both passes presented separately in this report. The caliper recordings indicate that the casing is in good condition with respect to corrosive damage. With the exception of perforations recorded in perforated intervals, no penetrations in excess of 6% wall thickness are recorded throughout the interval logged. Perforations are recorded in Joint numbers 37-41,43,44, 46-49, 51 and 52. Due to the shape of the tip on the caliper fingers, penetrations in excess of 0.30 to 0.33 inches could not be measured, depending on the orientation of the caliper tool relative to the pipe axis. The outward projecting "tip" on the caliper fingers projects only 0.33 inches from the "arm" portion of the finger, preventing the "tip" from protruding further than 0.33 inches into the "drilled hole" type damage that could be expected with new perforations. MAXIMUM RECORDED WALL PENETRATIONS : PERFORATION PERFORATION PERFORATION PERFORATION PERFORATION ( 92%) Jt. 37 @ 9,462' MD ( 87%) Jt. 43 @ $71 1' MD ( 87%) Jt. 46 @ 9,812' MD ( 86%) Jt. 51 @ 10,022' MD ( 84%) Jt. 39 @ 9,543' MD MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS : No areas of significant cross-sectional wall-loss (in excess of 10%) were recorded throughout the interval logged. MAXIMUM RECORDED ID RESTRICTIONS : No areas of significant ID restriction were recorded throughout the interval logged. I Field Engineer : R. Richey Analyst: J. Burton Witness: Jack Kralick I n ,,,. ,,.. :..- -;:zC.nr..+;,~ r ,..... : ,,,. -.-- , - ,. ' . c , - . C' ',"..c:<, . .i... :-~., .. .: <. 2 ,.-* -8.- - -?-'% ' - -- .,.' &. -, . .. .c. a - - , .-,3-- 2' ,. J ,; ,-,- .- - , /_j , . ., ,-..;.>OC' -=i:_"c--- r 17- -, - : . ,;,G --,---,.,.., c.-+ - .. . .. .. . ,r;i., , .+.. .. .,d?Y;, c:.. :.i -, , ~ . ~ . 'G. : .. .:. L.. ,..', 5 ; :. ~ ..., - , > ... ,- . -* .. ". l.?, ., .- ..,- -. --* -.,. . , ., --- , ,.,=., -.>!*, +>:: -c ,..I -,-..,=: - . .- .. ,%.. -" 8 . . , . , , . - ~ . .. r/'." ~. , ^- - - . , .- Attachment 7, Page2 Well: WD02 Survey Date: March 29, 2000 Field: ALPWE Tool Type: MFC4O No. 99493 Company: ARC0 ALASKA INC. Tool Size: 2.75" Countw USA No. of Fingers: 40 Analvsed: 1. Burron Tubing: Size Weight Grade &Thread Norn.OD Nom.lD Nom.Upset 7 ins 26 ppf La0 BTRS 7 ins 6.276 ins 7 ins Pecretration and Metal Loss (%wan) penetration body metal loss body O 0 to 1 to TO to 20 to 40 to above 1% 10% 20% 40% 85% 89% Number of joints analvsed koral= 54) 'me 1 40 0 0 12 1 Damage Configuration (body ) Numhr of joints damaged (total - 131 10 0 0 0 3 Damage profile: (% wll) penetration body metal loss body 0 SO Analysis Overview page 2 PDS CA~IPER JOINT TABULATION SH~T Attachment 7, Page 3 Plpe: 7 ins 26 ppf L8D BTR5 Wall thickness. Bsdy: 0.362ins Upset = 0.362ins bminal ID: 6.276 im Well: WD02 Field: ALPINE Comparv ARCQ ALASKA INC. ~penetranon bddy Counuy: U5A w metal lass body Drate: March 29,2000 fotnt Damage prafie Pipe TaklaZians page I Pipe: 7ins 26 ppf L-30 BmS Well: WD02 Wall hickness. Bcd~ 0362ins Upset= U.362ins n& ALPINE I;iomirml In; 6.276 ins Company: ARC0 ALASKA INC. penatration bady Country USA r metd lass bpdy Date: March 29,2000 Damage Classifications Peaemtion / projection class, in order of damas severity H~le - penetration exceeds 85% of nominal wall thickness Ring - damage area exceeds 75% of circumference, bu? depth range does net exceed 2 ' pipe ID Line -damage depth range exceeds 5 * pipe ID, but extends lm than 20% of circumference Gene& - damage debth range exceeds 2 * pipe ID and/or extends more than 20% of drcumference Isolated - damage depth range does not exceed 5 * pipe ID or extend more than 20% of drcumference Damage reporting threshold = 30 thpu inches deviation in body, 50 thou in wwt. Modal line length- 0.345 feet Pipe Tabulations page 2 Well: WD-tf2 Survey Date: March 29,2000 Field: ALPINE Tool Type: MFC40 No. 99493 Company: ARC0 ALASKA INC. Tool Size: 2.75" Countly: USA No. of Fingers: 40 Tubins: 7 ins 26 ppf L-80 BTRS Analysed: I. Bunoh Cross section for Joint 43 at depth 9706.92 ft Tool aped = 72 Mminal ID = 6.276 Nominal OD - 7.000 Remaining Walt area - 92 % Tool deviation - 47 " Cil6 ins PEBFORATIW HIGH SIDE = UP PDS Caliper Sectisns I Welk WDm Field: ALPINE Cornow: ARC0 ALASKA INC Suwey Date: Tool Ty@e: Tool Size: March 29,2080 MFC40 WQ, 99493 Crass section far Joint 46 at depth 981 2.45 ft Tool speed - 89 Namlnal ID - 6.2% Nominal OD = 7.000 Remaining wall area - 93 % Tool deviation - 55 " Finger 6 Pen&atMn - O,W6 ins PERFORmOW HIGH SIDE * UP PDS CALIPER JOINT TALLY SHEET Pipe: 7 ins 26 ppf LBO BTRS Wall thickness. Body: 0.362ins Upset = 0.362ins Nominal ID: 6.276 ins Well: WD-02 Joint No. Field: ALPINE Company: ARC0 ALASKA INC. Depth Country: USA Date: March 29, 2000 Length Attachment 7, Page 7 Measured ID Type 54 1 10121 .OO 1 unknown 1 6.284 1 I I I I Joint No. 5 1 52 53 Joint Tally page 1 Measured ID Type Depth feet 9998.51 10039.55 10082.28 Length feet 41 .04 42.73 38.72 inches 6.284 6.289 6.290 Attachment 7, Page 8 i Well: WD-02 Survey Date: March 29,2000 Field: ALPINE Tool Type: MFC40 No. 99493 Company: ARC0 ALASKA, INC. Tool Siie: 2.75" Country: USA No. of Fingee: 40 Analfled: I. Burton Tubing: Size Weight Grade & lbread Nom.OD NomlD I\lom.Upset 7 ins 26 ppf L-80 BTRS 7 ins 6.276 ins 7 ins Penetration and Mefal Loss (% wall) I penetration body metal loss body 60 50 40 30 20 10 O Oto lto loto 20to 40to above 1% 10 20% 40% 85% 85% Number of ioinb analvsed (total = 54) 'me 1 40 0 0 9 4 Damage Configuration ( body ) I Number of ioinb damaged (total = 13) 9 0 0 0 4 Damage Profile (%wall) penetration body metal 10s body 0 50 Bottom of Survey = 54 w PDS CALlPER JOINT TABULATION SH& Pipe: 7 ins 26 ppf L-80 BTRS Wall thlcknes. Body: 0.362ins Upset * 0.362ins Nominal ID; 6376 ins Well: WDa2 Field: ALPINE Company: ARC0 AWKA, INC. Countrv; USA Attachment 7, Page 9 pehetration body I metal loss WY Date: Maids 29,3000 PlpeTabolations page 1 Attachnoent 7, Page 10 Pipe: 7 ins 26 ppf L-80 BTRS WaR thickness. Body: 0.362ins Upset- 0.36Bis Nominal ID: 6276 ins well: WD.02 Field: ALPINE Company: ARC0 ALASKA, INC. penetration body Country: USA ,-metal loss body Date: March 29,2000 Damage Classifications Penelration f projection class, in order of damage severity Hole -penetration exceeds 85% of nominal wall thickness Ring - damage area exceeds 75% of circumference, but depth range doas not oxceed 2 * pipe ID Line - damage depth range meeds 5 * pipe ID, but wends less than 20% of circumference General - damage depth mnge exceeds 2 ' pipe ID and/or extends more than 20% of circumference isolated - damage depth range does not exceed 5 *pipe ID or wtend more than 20% of circumference Damage reporting threhold - 30 thou inches deviation in body, 50 ihou in upset Modal line length = 0.345 feet Pipe Tabulations page 2 PDS Caliper Sections !A. Well: WD-02 Fid& Al PlNF ~uhey Date: Tool Type: March 29, 20OQ MFCm No. 99493 , . - Company: ARC0 ALASKA, INC. Tool Size: 2.75" Country: USA No, of Fingers: 40 Tubinn: 7 ins 26 ppf L-80 BTRS ~naly~ed: J. Burton Cross section for Joint 37 at depth 9466.98 ft Tool speed - 41 Nominal ID = 6,276 Nominal OD = 7.000 Remaining wall area = 92 % Tool deviation - 48 " Finger 39 Penetration = 0.332 ins PERFORATION HIGH SIDE = UP CrosaSREtions page 1 PDS Caliper Sections Well: WD-02 Survey Date: March 29,2000 Field: ALPINE Tool Type: MFC4O Nu. 99493 Company: ARC0 ALASKA, INC. Tool Sire: 2.75" CounPry: USA No. of Fingers: 40 Tubing: 7ins 26 ppf L-80 BTRS Analysed: I. Burton Cross section for Jaint 43 at depth 971 0.6 ft Tool speed - 70 Nominal ID = 6.276 Nominal OD = 7.000 Remaining wall area = 92 % Too1 deviation = 47 " FirtgPr 40 PeneWatim = a31 6 ins CrmSecfions page 2 Attachment 7, Page 13 PDS CALIPER JOINT TALLY SHEET Pipe: 7 ins 26 ppf LSO BTRS Wall thickness. Body: 0.362ins Upset = 0.362ins Nominal ID: 6.276 ins Well: WD-02 Field: ALP1 NE Company: ARC0 ALASKA, INC. Country: USA Date: March 29, 2000 Joint No. Depth Joint No. 54 1 101 16.67 1 unknown 1 6.283 1 I I I I 37 52 , 53 Joint Tally page 1 Depth Type Length feet 9995.92 10037.82 10079.87 Measured ID Length feet 41.90 42.05 36.80 Measured ID inches 6.283 6.296 6.293 Type