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Home My WebLink About2000 Alpine Oil Poola " PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 March 29, 2001 Alaska Oil and Gas Conservation Commission 333 W. 7"' Avenue Suite 100 Anchorage, AK 99501 Subject: Annual Surveillance Report Alpine Oil Pool/Colville River Field Dear Commissioners: RECEIVED APR 0 3 2001 Alaska Oil & Gas Cons. Commission Anchorage Phillips Alaska, Inc., as an owner and the operator of the Colville River Unit, in accordance with Area Injection Order No. 18A and Disposal Injection Order No. 18 submits the attached Annual Surveillance Report for injection operations in the Alpine Oil Pool. Enclosed please find two copies or the report prepared in accordance with 20 AAC 25.432. Inquiries regarding this report may be directed to Mike Erwin at this office. Sincerely, Mark M. Ireland Alpine Development Manager ;f y Annual Surveilliance Report Alpine Oil Pool March 29, 2001 Page 2 cc: Mr. Kenneth A. Boyd, Director Alaska Department of Natural Resources Division of Oil & Gas 550 W. 7h Avenue, Suite 8000 Anchorage, Alaska 99501-3560 Ms. Teresa Imm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 Mr. Isaac Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 Mrs. Catherine Lively Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Todd Liebel Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 RECEIVED APR o 3 2001 �ImSkB Oil 2= 2000 Injection Report Colville River Field Table of Contents Section Page 1 Introduction 4 2 Class I Disposal 5 Injection Volumes Injection Rates Injection Pressures Annulus Pressures Depth Tags Surveillance Logging Fracture Growth Significant Well Events Wellwork Event Summary 3 Class II Disposal 11 Injection Volumes Injection Rates Injection Pressures Annulus Pressures Depth Tags Surveillance Logging Fracture Growth Significant Well Events Wellwork Event Summary 4 Class II EOR 14 Injection Volumes Injection Rates Injection Pressures Annulus Pressures Depth Tags Surveillance Logging Fracture Growth Significant Well Events Wellwork Event Summary 2 2000 Injection Report Colville River Field Attachments 1 WD -02 Annual Injection Summary Table 2 WD -02 Annual Injection Summary Plot 3 WD -02 Monthly Injection Plots 4 WD -02 PTA Analysis 5 CD1-19A Annual Injection Summary Table 6 CD1-19A Annual Injection Summary Plot 7 CD1-19A 6-01-2000 MIT Pressure Chart 8 CD1-19A PTA Analysis 9 CD1-19A Step Rate Test Plot 10 Gas Injection Summary Table 11 Gas Injection Summary Plot 12 Pulse Test — Response Map 13 Pulse Test — Response Magnitude by Well 14 Pulse Test — Response Overlay 9 2000 Injection Report Colville River Field Introduction Rule 9 of Disposal Injection Order No. 18A, dated April 1, 2000, requires the submission of an annual report on or before April 1. Additionally, this report is prepared in accordance with the requirements of 20 AAC 25.432 (Report of Underground Injection). This represents the second such report regarding injection operations in the Alpine Oil Pool, and the first to review a calendar year. Because of the conversion to calendar year reporting, some information is repeated from the previous report. During 2000, well WD -02, which was drilled and completed in April, 1999, continued to serve as the primary source of disposal for camp and field fluids during the final stages of construction and startup. A second disposal well, CD1-19A, was drilled and completed in May, 2000, to provide a disposal source for Class H fluids generated during wellwork operations. The Alpine Oil Pool began production on November 15, 2000 with the commissioning of the oil train. The gas train was commissioned and placed into service on December 9, 2000 with 2 injection wells. The following month the EOR flood commenced operations as the 12" seawater pipeline was placed into service on January 22, 2001. Commencement of the EOR flood placed seven water injection wells in service. During 2001 additional injection wells will begin service in the EOR flood. Drilling will wrap up the primary phase of development at Pad 1 and in early April move to Pad 2. Construction activities at Pad 2 are in full swing as this report is being prepared in anticipation of a 3rd Quarter startup. By the end of 2001 the Alpine Oil Pool will have reached peak injection and production rates as drilling continues to define and develop the field. 2000 Injection Report Colville River Field Class I Disposal Injection Volumes Fluid injection volumes for the 12 -month period of January 2000 through December 2000 totaled 329,480 bbl. This represents a monthly average of 27,457 bbl. Cumulative injection into the Sadlerochit since the start of the project is 421,669 bbl. Monthly injection volumes for WD -02 are summarized in both table and plot form as Attachments 1 and 2. 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. During April the well was offline for six days during the annual EPA inspection. During July the injection rates reflect snow melt disposal. Following startup of the oil train at startup in November, produced water was disposed of in WD -02. During the early weeks of startup the production wells cleaned up as drilling fluids and brines were produced back. The produced fluids greatly increased the daily injection volumes for a few days midmonth. By the end of December, the field water cut was essentially 0%. The twin injection pumps are operated at 15-20 gpm each up to the 3200 psi allowable injection pressure. Daily injection volumes swings require additional pumping hours as required to handle the increased loads. Daily injection rates are included in the monthly data plots (see Attachment 3). Injection Pressures Injection pressures are monitored and recorded continuously and summarized on the weekly data plots (Attachment 3). Normal wellhead pressure when the pump is offline ranges between 600 psi and 800 psi. With the pump running at 15 gpm injection pressure ranges between 1,400 psi and 1,600 psi. Spikes in the data have been reported as high as 2800 psi, but do not represent normal operating conditions. Annulus Pressures Annulus pressures are monitored and recorded continuously and summarized on the monthly data plots (Attachment 3). Beginning in January the injection of cold fluids in the tubing suppressed annulus pressures lower than planned. During the April inspection the annulus pressure was raised to 700 psi in order to maintain pressures above 200 psi even during cold fluid injection. This maintained average annulus pressures in the 600- 2000 Injection Report Colville River Field 900 psi range throughout the summer. Concern over hot produced water injection sending the annulus pressure over the EPA annulus pressure limit of 1500 psi led to bleeding fluids off the annulus following the November startup. As a result, when the produced fluids declined off injection of dominantly cold water injection suppressed casing pressures. We have again repressured the casing annulus during the annual 2001 EPA inspection to maintain the pressures in a readily observable range. Annulus pressures are included in the attached monthly injection plots (Attachment 3 ) Depth IM During the 2000 Annual EPA Inspection slickline tagged TD on March 29 at 10,097' WLM. This corresponds to 10,130' RKB. This tag is only 4' shallower than the 10,101' WLM tagged 4/6/99. This depth is 83' below the deepest perforation at 10,147'MD. Surveillance Logging In compliance with stipulations in Part II.C.3.b.1&2 of EPA Permit AK -1I003 -A, Phillips conducted a thorough examination of the mechanical condition of the wellbore through application of five (5) surveillance logs. This work was completed in April of 2000, under the direction of the EPA. Even though more complete reviews were included in the previous report, shorter summaries are provided below. 1. A caliper survey was conducted in the intermediate casing. • 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". • 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 = 0.01" 2. A temperature survey consisted of the following actions: *Fall-off pressures were recorded for 2 hours. *The first baseline temperature pass was performed from 7600' — 10,135' MD. •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 Top Bottom Splice 1 7600' 9574' Splice 2 9574' 9890' 0 2000 Injection Report Colville River Field S lice 3 9890' 9994' S lice 4 9994' 10,132' • 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 freeze 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. 3. 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. • Logged Station 1 to verify tool function at 4081' MD. • Logged Station 2 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. • Logged Station 3 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. • Logged Station 4 at 7852' (13' above the packer). No flow behind the packer was detected in four logging periods while pumping at a stable 1 bpm/1800 psi. 4. 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. • Tied in on depth and verified tool performance. • Surveyed from the packer to TD (8000' — 10,050') at 1 bpm/1600 psi. • Surveyed stop counts at lbpm/1600 psi. • Surveyed the Sadlerochit injection interval (9350'-10,070') at 2.5 bpm/2250 psi. *Surveyed stop counts at 2.5 bpm/2250 psi. 5. A Radioactive Tracer Survey was performed which consisted of the following runs: • Tied in on depth and ran background gamma ray survey until proper results were noted from 10,070 to 8800'. • Log at top perf with injection below fracture gradient to observe fluid movement behind the casing. 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. • Repeat logging at 9455'. 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. 7 2000 Injection Report Colville River Field •Increase rate to 2.5 bpm at 2250 psi to exceed fracture gradient and repeat logging procedure. Repeat slug ejection and log for 10 minutes in place. No sign of fluid movement or channels upward behind perforations. *Pull up to the packer and eject slug below packer at 7875', chase downhole while pumping in at 1.0 bpm. Looking for leaks in the tubing between the packer and the top perfs. Slug appears to have diluted to the point it is not detectable. •Evaluate the perforations for splits and casing leaks while pumping below the fracture gradient. With tool at 9400' (59' above top perf at 9459') release slug and log up/down passes while chasing slug downhole pumping at lbpm at 1550 psi. *Repeat the previous step at injection rates above the fracture gradient. Increase pump rates to 2.5 bpm. Release slug and log up/down passes while chasing slug downhole. 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 sandstones, limestones and shales. The baseline temperature logs taken April ls` 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; • all fluids are being conducted from the packer to the perforated interval, • all fluids are exiting the casing within the permitted interval, and • no fluids are migrating outside the permitted interval. 0 2000 Injection Report Colville River Field Fluid splits from the spinner survey show the fluids leaving the wellbore as shown below. Perforated Interval Fluid % 9459'-9472' 0% 9514'-9552' 0% 9612'-9627' 1% 9702'-9712' 1% 9803'-9818' 0% 9837'-9867' 50% 9876'-9896' 10% 9900'-9020' 0% 10,017'-10,047' 38% The splits shown concur with the results of the temperature survey as well as the radioactive tracer survey. However, spinner analysis provides quantitative results when compared to the qualitative results of the temperature survey. Fracture Growth The surface fracture pressure of the Ivishak, as measured during the step rate test conducted April 11, 1999, is 1984 psi. This pressure coincides with an injection rate of 1.38 BPM, or 1987 BPD. The associated bottomhole fracture pressure extrapolated from the step test data is 6,259 psi. This equates to a gradient of 0.66 psi/ft, or fluid equivalent of 12.7 PPg• With the exception of short term injection periods, tubing tests, and miscellaneous data spikes the injection pressures have not exceeded the surface fracture pressure for any extended period of time during 2000. For that reason significant fracture growth is not expected in the Sadlerochit formation. Pressure transient analysis of surface pressure readings recorded during 10 hour February 2000 shutdown are included as Attachement 4. Though only a brief shutdown, this 10 hour period is one of the longest during the year. Analysis of the differential pressure response does not suggest fracture growth is occurring. Key formation properties determined in the analysis include; • formation permeability is 9.6 md., • formation perm -height is 1440 and -ft, and • skin is —2.07. Significant Well Events The failure of the heat trace protection and startup of the produced water system are the two most noteable events of the past year. Last fall it was noted that the heat trace controls did not appear to be functioning. On January 16, 2001 an evaluation by Raychem, the manufacturer and installation contractor, 2000 Injection Report Colville River Field confirmed the system is shorted out. The tubing is wrapped with heat trace cable to safeguard against freezing the tubing in the event of an extended pump shutdown. Without this system in operation, we will be required to respond to frozen tubing with a hot oil and coil tubing unit. The produced water system was commissioned with startup in November of the oil train. All produced water from the wells is currently disposed of in WD -02. Wellwork Event Summary Outlined below is a summary of wellwork events. Date Work Activity 3/29/2000 Pull SSSV, tag 10097" WLM, run PDS Caliper log. 4/01/2000 Run base line temp log. 4/04/2000 Repressure IA. Run final Temp survey. 4/05/2000 Perform MIT — Passed. 4/06/2000 Run VVTL log and spinner log. 4/07/2000 Run RAT log. 4/08/2000 Set SSSV. 10/28/2000 Pull SSSV. Drift tubing, tagged soft and sticky at 9990'WLM. 10/30/2000 Reset SSSV.Pump 30 bbl diesel down tubing. It should be noted that the high tag on 10/28 was apparently due to buildup in the tubing. During the 2001 annual inspection bottom was tagged following a chemical wash at 10,055' WLM on 2/24/2001. 10 2000 Injection Report Colville River Field Class II Disposal WD1-19A) Injection Volumes Fluid injection volumes for the 5 -month period of August 2000 through December 2000 totaled 8,322 bbl. This represents a monthly average of 1,664 bbl. Cumulative injection into the Sadlerochit since the start of the project is 8,322 bbl. Injection volumes for CD1-19A are summarized on Attachment 5. Injection Rates Disposal operations for this well are manually recorded. Various trucks are utilized to transport and dispose of fluids into this well. Injection rates vary between 1-2 bpm, with occasional spikes as high as 2.5 bpm. There are no permanent disposal pumps or piping installed at this time. Pressure and injection rate records are collected manually during disposal operations. Disposed fluids primarily include spent wellwork fluids and brine from the well flowbacks. All fluid disposal reports and manifests are recorded and stored at Alpine. The data is displayed graphically on Attachment 6. Injection Pressures Injection pressures are monitored and recorded manually and reported to the Alpine Environmental staff. Their reports are summarized in the data plots (Attachment 6). Normal wellhead pressures during disposal operations vary between 2,000 psi and 3200 psi. Annulus Pressures Annulus pressures are manually recorded and reported, and displayed in graphical form on the well performance plots (Attachment 6). Typically the inner annulus pressure is less than 100 psi, and remains stable during injection periods. On June 1, 2000 a pressure test was conducted to verify the mechanical integrity of the lower packer. As approved by the AOGCC in our drilling permit, during the re-entry and repair of this well in May a second packer was set to isolate squeeze perforations in the Alpine formation. The rig was unable to test this packer when set because plugs were present in the tubing tails during the hydraulic setting operation. Before leaving the well a pressure test of the upper packer to 3500 psi was successfully completed on May 29, 2000. The June 1 pressure test followed packer plug removal, and preceded perforating for injection operations. The test was recorded and witnessed as shown on Attachment 7. This test confirmed tubing integrity, casing integrity from the packer to the casing shoe, and the integrity of the lower packer prior to perforating. 11 2000 Injection Report Colville River Field Depth Tags The initial tag on CD1-19A occurred on 6/01/2000 and reportedly set down at 11,816'WLM. Adjusted for RKB the tag depth was 11,849' MD, or 36' below the deepest perforations. There have been no additional tag runs later in the year. Surveillance Logs6ng On 6/04/2000 SWS performed a temperature/pressure survey of the CD1-19A. Following the final perforating runs the tools were set at 11,813' MD (bottom perfs) to observe the initial breakdown. Injection was stabilized at 2.0 BPM at 3300 psi WHP. After pumping 120 bbl of diesel the well was shut-in and the tools recorded the pressure fall-off. The results are shown as Attachment 8. Key formation parameters determined include; • permeability is 4.5 md, • kh is estimated to be 379 and -ft., and • skin is 0.65. A step rate test was performed on September 17, 2000. Formation fracture was observed at 1700 psi and 0.55 bpm with the wellbore displaced to diesel. Assuming the formation top perf is at 9118' TVD, the fracture gradient is Frac Pressure = (6.8 ppg * 0.052 psi/ft * 9118 ft) + 1700 psi = 4924 psi Frac Gradient = 4924 psi / 9118ft / 0.052 = 0.54 psi/ft This fracture gradient is lower than the 0.66 observed in the inital testing of WD -02. The step rate data is displayed on Attachment 9. Logging plans for 2001 include a spinner log and repeat pressure fall-off test. Fracture Growth Correcting the fracture pressure observed with diesel yields a surface fracture pressure of approximately 950 psi assuming water injection. All fluid injection to date has occurred above that pressure. However, due to the limited fluid injection volumes during 2000, there is little concern regarding fracture formation or growth involving this wellbore. Significant Well Events Doyon 19 returned to this well for a workover to block squeeze the Alpine formation prior to running the completion. During the initial drilling program, poor returns left the cement top well above the primary injection interval but failed to protect the Alpine formation from fluids migrating through the open wellbore to other intervals. During the workover block squeeze perfs were shot and squeezed above and below the Alpine. A bond log confirmed appropriate isolation was achieved across the Alpine. A dual packer design was discussed with an agreed to by the AOGCC. 12 2000 Injection Report Colville River Field Wellwork Event Summary Outlined below is a summary of wellwork events. Date Work Activity 5/21/2000 Doyon 19 returns for remedial cement job. 5/29/2000 Doyon 19 released following well completion. MIT tubing and casing to 3500 psi. 5/31/2000 Drift and pull RHC plugs. 6/01/2000 Tag PBTD at 11,816' WLM. MIT the lower packer to 3500 psi prior to perforating. Run tie-in log prior to perforating. 6/02/2000 Perforate 3 lowest intervals. 6/03/2000 Perforate 2 additional intervals. 6/04/2000 Perforated final interval. Break down perfs and record PFO. 6/08/2000 Set SSSV and test. 9/17/2000 Step rate test pumped. 13 2000 Injection Report Colville River Field Class II EOR Flood By the end of 2000 there were 14 injectors drilled and completed. Those initial wells were CD1-01, CD 1-03, CD1-05, CD1-06, CD1-13, CD1-16, CD 1-23, CD1-26, CD1-31, CD 1-36, CD 1-37, CD 1-39, CD 1-42, and CD1-45. All but three of these wells were prepared to commence injection, and those three were CD1-13, CD1-16 and CD 1-23. The rest completed their initial flowbacks to clean up drilling fluids and formation solids during 2000. Of the 14 injection wells, three were placed on gas injection. Two wells were designated long term gas injectors and were the first wells in injection service when the gas train was commissioned December 9th. The two dedicated gas injectors are CD1-06 and CD1-31. The third well, CD1-05, is a long term WAG injector that was placed in gas injection service December 23 to provide additional short term gas injection capacity and operational flexibility in the event either of the two dedicated wells were unavailable. Injection Volumes Gas injection volumes for the three wells for the 1 -month period of December 2000 totaled 830,991 MSCF, and are included as Attachment 10. Injection Rates Daily injection rates for the three gas injection wells are included in the single December injection plots (see Attachment 11). Injection Pressures Injection pressures and rates are plotted for the three injection wells on Attachment 11. During startup rates fluctuated in response to various operational changes and upsets. By the end of the year we were beginning to recognize normal trends in the rates and pressures. While initially there was some concern about the injection capacities of the Alpine injection wells, particularly in regards to gas injection, the concerns were quickly dispelled by the early rate and pressure response of wells CDl-06 and CDl-05. Annulus Pressures Annulus pressures were not recorded in the weeks following startup. Daily readings are now being taken and manually recorded. Depth Tags Depth tags are not as significant or straightforward on horizontal gas injection wells as in more conventional water injection or disposal wells. However, during each completion 14 2000 Injection Report Colville River Field setup a tag is performed to the deepest depth the tools will fall. Summarized below are the depths reached on each of the 3 wells. Well Tubing Depth, NID Tag Depth, NID Tag Date CD 1-05 10,060 10,432 3/11/2000 CD 1-06 12,667 13,314 7/23/2000 CD 1-31 10,057 10,285 10/08/2000 Surveillance Logging The only surveillance logging performed during this time period were the required cement bond log. Plans are in place to run coil tubing conveyed memory spinner surveys of each injection well during 2001. Fracture Growth Expected fracture pressures on gas injection were expected exceed 3500 psi at the wellhead. Injection pressures on the three injection wells included in this report do not indicate fractures to be forming at this time. Significant Well Events The most significant wellwork event to date regarding the injection wells was the pulse test conducted between April and July, 2000. The test was conducted during the winter construction season at a time when production pulses or flowbacks could not be performed on the pad. There we several expected benefits from the test including; • refinement of the full -field reservoir model permeability. • confirming connectivity across waterflood patterns. • confirming communication across numerous north -south trending faults. • evaluating long term water injectivity. Summarized below are the key events regarding this test; 1. Pressure gauges were installed in wells CD1-5/13/16/22/23/36/37/39/42. 2. Wells 1 and 37 were cleaned out with coil tubing to remove drilling fluids and mud. 3. An injection pulse of 23,738 bbl of seawater was pumped into Well CD1-01 between 3/31-4/03/2000 at 5 bpm. Injection pressures were monitored with downhole gauges. 4. An injection pulse of 21,280 bbl of seawater was pumped into Well CD1-37 between 4/21-4/24/2000 at 4.2 bpm. Injection pressures were monitored with downhole gauges. 5. Pressure gauges were gradually pulled from the various wells over the next 2-3 months to determine the timing and magnitude of the two pulses. Each observation well received a distinguishable pulse from either or both 1-01 and 1-37, and Attachment 13 is a field map with arrows specifically detailing the source of each 15 2000 Injection Report Colville River Field pulse. Attachment 13 is a graph on a simple time scale showing the arrival timing and magnitude of each observed pulse. It was fascinating to discover that several notable pulses originated from adjacent drilling activity. For instance, drilling at 1-09 initiated a pulse observed in 1-05, and 1-40 created a pulse captured in 1-39. Attachment 14 is a combination graph and map showing the observed pulse in reference to our modeled pulse response. The full field model was able to accurately reproduce the arrival times of each pulse, but the overall model permeability assumptions had to be doubled to match individual pulse magnitudes. Wellwork Event Summary Outlined below is a summary of wellwork events for well CD1-05. Date Work Activity 3/11/204200 Post rig drift, pull RHC, drift tubing, run SBHP. 3/13/2000 Run temp log and cement bond log. 3/17/2000 Set dual pressure gauges in the tubing tail for pulse test. 4/12/2000 Set SSSV. 8/04/2000 Pull, download and rerun dual pressure gauges. Reset SSSV. 9/26/2000 Retrieve dual pressure gauges. 9/28/2000 Flowback well to clean up drilling fluids and muds. 9/29/2000 Set SSSV. Outlined below is a summary of wellwork events for well CD1-06. Date Work Activity 7/22/2000 Post rig drift, pull RHC. 7/23/2000 Drift tubing, run SBHP, set SSSV. 9/29/2000 Flowback well to clean up drilling fluids and muds. Outlined below is a summary of wellwork events for well CD1-31. Date Work Activity 10/07/2000 Post rig drift, pull RHC. 10/08/2000 Drift tubing, run SBHP. 10/13/2000 Run cement bond log. 11/03/2000 Flowback well to clean up drilling fluids and muds. 11/22/2000 Set SSSV. 16 Attachment 1 January - December 2000 Injection Summary Well: WD -02 Disposal Order: 18A Field: Colville River Unit API No.: 103-20285-00 Pool: Alpine Oil Pool Pool Code: 120036 Tubing Pressure Casing Pressure Days in Max Average Max Average Daily Avg Injection Total Monthly Injection, bbl Cumulative Monthly Injection, bbl Month Operation Pressure Pressure Pressure Pressure L ggid Gas Liquid Gas iLqGas January 31 1,794 1,252 564 107 521 16,163 16,163 February 29 1,610 1,345 388 26 385 19,551 35,714 March 31 2,124 1,360 254 7 386 28,506 64,220 April 30 2,844 968 1,492 783 412 22,318 86,538 May 31 2,707 1,356 1,299 830 406 32,116 118,654 June 30 1,582 1,375 1,041 772 373 34,241 152,895 July 31 1,960 1,485 1,108 813 458 37,571 190,466 August 31 2,345 1,217 1,073 773 444 31,857 222,323 September 30 2,988 1,343 1,339 757 521 31,207 253,530 October 31 1,734 1,282 907 626 674 27,399 280,929 November 30 2,506 1,255 1,354 349 920 27,666 308,595 December 31 2,864 1,231 1,087 652 744 20,885 329,480 Average 2,255 1,289 992 541 520 27,457 1600 1400 1200 E 0 1000 ai cc w c 800 .y A. v 600 a 400 200 t7 Attachment 2 2000 Alpine Class I Inj Performance —$—Avg Inj Press, psi —♦—Avg Inj Rate, gpm —e—Avg Ann Press, psi --*--Monthly Inj, bbl -Ann Cum Inj, bbl Jan -00 Feb -00 Mar -00 Apr -00 May -00 Jun -00 Jul -00 Aug -00 Sep -00 Oct -00 Nov -00 Dec -00 Page 1 350,000 300,000 250,000 200,000 150,000 100,000 50,000 U F.: L t0 m 1,000.0 900.0 800.0 700.0 600.0 a m 500.0 ai �a 400.0 300.0 200.0 100.0 0.0 Attachment 3.1 January 2000 Injection Summary - A Daily Inj, Bbl. -$ Avg WHIP, psi -0 Avg AnnPress, psi 2,000 1,800 1,600 1,400 1,200 a 2 1,000 = E:I�I�>• .ME M 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 1,000.0 900.0 800.0 700.0 600.0 CL m 500.0 �o m 400.0 300.0 200.0 100.0 0.0 Attachment 3.2 February 2000 Injection Summary 2,000 :it 1,600 1,400 1,200 U5 CL 1,000 = Fit I$� M 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 Page 1 1,200.0 1,000.0 Eil CU11 0 CL m 600.0 l0 400.0 200.0 Me Attachment 3.3 March 2000 Injection Summary 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 1,800 1,600 1,400 1,200 W Q 2 1,000 = :11 200 C 1,400.0 1,200.0 1,000.0 ® 800.0 C. M 600.0 400.0 200.0 0.0 Attachment 3.4 April 2000 Injection Summary 2,000 M 1,600 1,400 1,200 C. 2 1,000 3 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Page 1 01011111111111111 M CSO 200 A 1,400.0 1,200.0 1,000.0 0 800.0 a in 600.0 Pit 1l wI Attachment 3.5 May 2000 Injection Summary —;— Daily Inj, Bbl. —�—Avg AnnPress, psi —s Avg WHIP, psi 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 :/1 1,600 1,400 1,200 a 2 1,000 M �11 M 400 200 M 1,400.0 1,200.0 1,000.0 800.0 a m �o m 600.0 200.0 MO Attachment 3.6 June 2000 Injection Summary —*— Daily Inj, Bbl. —* Avg AnnPress, psi —*.-Avg WHIP, psi 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Page 1 2,000 1,600 1,400 1,200 a 1,000 M M 200 2,500.0 2,000.0 1,000.0 500.0 MW Attachment 3.7 July 2000 Injection Summary --*—Avg AnnPress, psi * Avg WHIP, psi 1 2 3 4 5 6 7 8 9 1011 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 1,800 1,600 1,400 1,200 CL m 1,000 3 :!/ WE 400 200 IN 1,400.0 1,200.0 1,000.0 ® 800.0 a IM ai cc 600.0 400.0 200.0 0.0 Attachment 3.8 August 2000 Injection Summary 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 M 1,600 1,400 1,200 C. 1,000 3 Rllll� wk 400 200 ICC 1,400.0 1,200.0 1,000.0 800.0 a IM d co cc 600.0 400.0 200.0 0.0 Attachment 3.9 September 2000 Injection Summary —� Daily Inj, Bbl. --Avg AnnPress, psi —* Avg WHIP, psi 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Page 1 2,000 SII 1,600 1,400 1,200 fl.. m 1,000 3 L.,Mf CII 200 N 1,400.0 1,200.0 1,000.0 °' cc 600.0 200.0 Attachment 3. 10 October 2000 Injection Summary —A Daily Inj, Bbl. --*--Avg Ann Press, psi - 0 Avg WHIP, psi 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 :11 1,600 r 1,400 1,200 S 1,000 IS 111 .11 400 200 0 16,000.0 14,000.0 12,000.0 a 10,000.0 m d oC 8,000.0 4,000.0 2,000.0 me Attachment 3.11 November 2000 Injection Summary —A Daily Inj, Bbl. —*—Avg AnnPress, psi —* Avg WHIP, psi 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 1,500 1,000 CL 500 G -500 a� L N d L a 1,200 1,000 :ld O 0 - CO 600 �o 400 200 M Attachment 3.12 December 2000 Injection Summary 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Page 1 2,000 1,800 1,600 1,400' 1,200 CL m 1,000 OR M 400 200 C Aii-Acm-li'l t Wd20200 : Main Results Company Field Well Test Date Gauge Depth Formation interval Perforated interval TEST TYPE Standard FLUID TYPE Oil Porosity Phi (%) 13 Volume Factor B 1.06531 Well Radius rw 0.3542 ft Total Compr. ct 1 E-5 psi -1 Pay Zone h 150 ft Viscosity 3.4026 cp Flow Period # 2 RESERVOIR Radial composite Rate 0 STB/day BOUNDARY Infinite Rate Change 685 STB/day WELL Storage & Skin P at dt=0 5397 psia Storage C 0.00242 STB/psi Pi 4592.29 psia Skin factor -2.07 Delta P Skin -503.207 psia Time Match 51.5 (hr) -1 Pressure Match 0.00411 (psia)-1 kh 1440 md.ft k 9.6 and Mobility k/mu 2.82 Investig. R 149 ft Tested Volume 240885 Barrels Ri 35.4 ft Mobility ratio 0.23 Diffusivity ratio 0.23 WD -02 February 5, 2000 PFO from Surface Data Saphlr Level 3 V2.30T - 03-2001 5300 5200 5100 5000 4900 Wd20200 : Semi -Log �. Company Field Well Test -4 -3 -2 -1 0 N Lpsiaj versus superposition t Flow Period # 2 Rate 0 STB/day Rate Change 685 STB/day P at dt=0 5397 psia Pi 4592.29 psia STRAIGHT LINE From 5.65111 hr To 11.0186 hr Slope 64.6 psia Intercept 4635.19 psia value at dt=1 hr 4781.89 psia -> p` 4635.19 psia ->PMatch 0.0178 (psia)-1 -> k.h 6250 md.ft -> k 41.7 and -> Skin 5.62 Delta P Skin 315 RESERVOIR Radial composite BOUNDARY Infinite WELL Storage & Skin Storage C 0.00242 STB/psi Skin factor -2.07 Delta P Skin -503.207 psia kh 1440 md.ft k 9.6 and Mobility k/mu 2.82 Investig. R 149 ft Tested Volume 240885 Barrels Ri 35.4 ft Mobility ratio 0.23 Diffusivity ratio 0.23 r Pressure Match 0,M004 Bary 5, 2000 PFO from Surface Data Saphir Level 3 V2.30T - 03-2001 Wd20200 : Log -Log Company Field 49 Well Test 100 10 1 0 ------------------------------ ❑ 10-3 0.01 0.1 1 10 WD -02 February 5, 2000 PFO from Surface Data Saphir Level 3 V2.30T - 03-2001 cIF & aP' fpsiaj versus at (nrj Flow Period # 2 RESERVOIR Radial composite Rate 0 STB/day BOUNDARY Infinite Rate Change 685 STB/day WELL Storage & Skin P at dt=0 5397 psia Storage C 0.00242 STB/psi Smoothing 0.1 Skin factor -2.07 Pi 4592.29 psia Delta P Skin -503.207 psia Time Match 51.5 (hr) -1 kh 1440 md.ft Pressure Match 0.00411 (psia)-1 k 9.6 and Mobility k/mu 2.82 Investig. R 149 ft Tested Volume 240885 Barrels Ri 35.4 ft Mobility ratio 0.23 Diffusivity ratio 0.23 WD -02 February 5, 2000 PFO from Surface Data Saphir Level 3 V2.30T - 03-2001 Attachment 5 January - December 2000 Injection Summary Well: CD1-19A Disposal Order: 18A Field: Colville River Unit API No.: 103-20294-01 Pool: Alpine Oil Pool Pool Code: 120036 Tubing Pressure Casing Pressure Days in Max Average Max Average Daily Avg Injection Total Monthly Injection, bbl Cumulative Monthly Injection, bbl Month Operation Pressure Pressure Pressure Pressure Lipuid Gas Liquid Gas Liquid Gas January 0 February 0 March 0 April 0 May 0 June 0 July 0 August 3 3,700 2,534 500 500 258 775 775 September 1 2,950 2,203 500 500 406 406 1,181 October 16 3,200 2,582 600 451 228 3,641 4,822 November 4 3,200 2,388 550 545 380 1,519 6,341 December 6 3,000 2,817 500 500 330 1,981 8,322 Average 3,210 2,505 530 499 320 1,664 3,500 3,000 2,500 Q 2,000 m m CL` 1,500 1,000 500 0 Attachment 6 CD1-19A Injection Summary Plot ■ ■ ■ Avg Tubing Press, psi —*—Avg Inner Ann Press, psi ♦ Rate, bpm Y A • • AAA 0• YW Page 1 3.0 2.5 2.0 CL .0 1.5 m im 0.5 Attachment 8 - Alpine Class II Disposal Well CD1-19A Automatic Type Curve Match 10.00 1 I I I I -- - -- Calculated Pressure I I 1 I -- Calculated Derivative' ------ ' (i Measured Pressure -----~ A Measured Derivative 1 I I I 1 1 I I I I ® I I I I , ❑ I I i I 0 ❑ ;, I I 1.00 ---------------------' / �------ -- ---------A--- --------------------- X, I 1 I Q I I I 1 1 I I 0.10 ' I I 1 1 Homogeneous (Storage and Skin) Permeability [md] = 4.517 0.3561 Permeability * Thickness [md ft] = 379.4 Skin [0] = 0.6464 0.3302 Wellbore Storage [bbls/psi] = 0.000388 0.000104 Delta P Skin [psi] = 200.1 Radius of Investigation [ft] = 114.5 A Erwin, D. Freyder 06/05/00 16:53:00 I I � 0.01 0.1 1.0 10.0 tD/CD 100.0 10000.0 OODU 3000 2500 Z CL 2000 �i 1500 1000 500 0 Attachment 9 9/17/00 CD1-19 Surface Injection Step Test Plot 6 5 4 CL M aC 3 2 1 0 13:08:43 13:09:43 13:10:44 13:11:44 13:12:46 13:13:48 13:14:49 13:15:54 13:16:58 13:17:58 13:18:58 13:19:59 Time Page 1 Month January February March April May June July August September October November December Average Attachment 10 January - December 2000 Injection Summary Well: CD1-05 Disposal Order: 18A Field: Colville River Unit API No.: 103-20320-00 Pool: Alpine Oil Pool Pool Code: 120036 Tubing Pressure Casing Pressure Days in Max Average Max Average Daily Avg Injection Total Monthly Injection, bbl Cumulative Monthly Injection, bbl Operation Pressure Pressure Pressure Pressure Liquid Gas Liquid Gas Liquid Gas 0 0 0 0 0 0 0 0 0 0 0 10 5,117 1,002 365 750 3,893 38,932 51117 1,002 365 750 3,893 38,932 38,932 Attachment 10 January - December 2000 Injection Summary Well: CD1-06 Disposal Order: 18A Field: Colville River Unit API No.: 103-20341-00 Pool: Alpine Oil Pool Pool Code: 120036 Tubing Pressure Casing Pressure Days in Max Average Max Average Daily Avg Injection Total Monthly Injection, bbl Cumulative Monthly Injection, bbl Month Operation Pressure Pressure Pressure Pressure Liquid Gas Liquid Gas Liquid Gas January 0 February 0 March 0 April 0 May 0 June 0 July 0 August 0 September 0 October 0 November 0 December 24 5,027 2,790 679 1,100 22,578 541,867 541,867 Average 5,027 2,790 679 1,100 22,578 541,867 Attachment 10 January - December 2000 Injection Summary Well: CD1-31 Disposal Order: 18A Field: Colville River Unit API No.: 103-20347-00 Pool: Alpine Oil Pool Pool Code: 120036 Tubing Pressure Casing Pressure Days in Max Average Max Average Daily Avg Injection Total Monthly Injection, bbl Cumulative Monthly Injection, bbl Month Operation Pressure Pressure Pressure Pressure Liquid Gas Liquid Gas Liquid Gas January 0 February 0 March 0 April 0 May 0 June 0 July 0 August 0 September 0 October 0 November 0 December 16 4,951 2,806 315 1,100 15,637 250,192 250,192 Average 4,951 2,806 315 1,100 15,637 250,192 40,000 35,000 0 L) 25,000 2 m 20,000 C 0 c� 15,000 10,000 5,000 C Attachment 11 Gas Injection Monthly Plots 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 GG eU eG 0G eG GG' �Ci �G �G' eC eG �G �G eG �G GGi GG eG GG GG GG GG �Ci GG �Ci GG GG GG GG 0U GG Page 1 5000 4500 4000 3500 3000 2500 L a as c 2000 H 1500 1000 500 0 Attachment 12 — Pulse Test Response Map 18 G T" 79 x. 5 9 3 '. 4 DI- - `- 3 6o� s 2 42 41 '� CD�41I3� y _ -2Q3 !1 26 C Z42 1 GLQ_ 6 6P BIS eft 5 P B, CD1-25 a 97 N�CF; s�Pg -I �'� `� "� 24 X65 16 . 3 4 45 ♦ �� `{` 5 ±�1 Sri \ U N D r C '1-3. 7 86 d tM1J39P37 92 N Y.. 3 9 40 � � Definite Response 0 • • • • • • , Probable Response Attachment 13 — Response Magnitude by Well 3240 3235 ---- -- ----------------- CD1-05-CD1-13 7s._-`- ° CD1-16 CD1-22 CD1-26 CD1-36 3230 ---= - --- ----- ------------- CD1-39 1CD1-42 - - - Start Inj @ 01 T Start Inj @ 37 drill CD1-09 - drill CD1-06 3225 ---'-- ----°---------- - - - -drill CD1-40 drill CD1-35 drill CD1-32 3220 --- -------- ---- ------------------------------------ -------------------:- 3215 ----------- --- ---------------------------------------------------------- 3210 --- - - - -- -------- -- - - - -- 3205 ---� - --- ----------------------------------- --�-__ Lwow -------- 3200 ' 0 20 40 60 - Days - 80 100 120 Attachment 14 — Pulse Test Magnitude Overlay PULSE TEST RESULTS on BASE ALPINE DIP MAGNITUDE MAP 15 CD1-36 10 p5 4 0 0 20 40 60 80 100 120 14 Time. Days A \31 4 6 CD1-42 2 5 4 y 3 Pp 2 1 0 g 0 20 40 T%. Des 100 120 140 so CD1-22 50 40 30 20 10 0 0 420 40 60 80 100 120 14 _ Time. Days CD1-39 8 6 4 2 0 0 20 40 60 80 100 120 14 Time, Days ♦ 1 \ 1 \ 1 CD1-26 11 30 25 20 � 15 10 5 0 0 20 40 60 80 100 120 14 Time, Days Legeno -Gauge - Base Model J� - Base Model times 2 6,26,22,3,39- Loss Circulation Wells � -Pressure Gauge Well � • Water Injection Well Sel-- el —I 3000 FT So CD1-06 40 30 P 20 10 0 0 20 40 60 80 100 120 140 Time. Days 6 CD1-13 �6 a o? 0 20 40 60 80 100 120 14 Tme. Days CD1-16 n e M 6 3 II 0 0 20 40 60 80 100 120 1d Time, Days