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Home My WebLink About199-103XHVZE Pages NOT Scanned in this Well History File This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. File Number of Well History File PAGES TO DELETE Complete RESCAN Color items - Pages: GraYScale, halftones, pictures, graphs, charts - Pages: / Poor Quality o~ina'l- Pages: [3 Other - Pages: DIGITAL DATA ~ Diskettes, No. [3 Other, No/Type -OVERSIZED .Logs of various kinds n Other COMMENTS: Scanned by~,dred. D'amm" Naltmn Lowell i TO RE-SCAN Notes: Re-Scanned by: Bevedy Mildred Daretha Nathan Lowell Date: /s/ I Arctic Well Design Sequence 1 & Failure Prognosis I North Slope of Alaska by ` 0 Dan Clark Trudi Hallett Kasper Kowalewski Maria Medvedeva Kacey Shupp Zhaohong Wang C ,:s-C AN.• c� \ `1 I X3= 1 - l 0T css \►\c- - � r k Presented to Dr. Godwin Chukwu Department of Petroleum Engineering In Partial Fulfillment of the Requirements for Fall /Spring PETE 487 Petroleum Project Design 1„,,AF 1 UN ;VERSIFY OF ALASKA FAIRBANKS ' University of Alaska - Fairbanks May 1, 2009 1 I ACKNOWLEDGEMENTS I The senior class of the Petroleum Engineering Department would like to express our sincere gratitude to our advisor, Dr. Godwin Chukwu. His continuous encouragement and valuable guidance throughout the completion of our project has inspired all of us to I strive for professional excellence and instilled invaluable work ethic in all of us. We are also especially appreciative to Greg Hobbs of BP Alaska, as well as the AADE Alaska I section, for the opportunity to work on a complex arctic well workover. We are extremely grateful for all the valuable time and expertise he has put forth on our behalf. I We would like to acknowledge the petroleum department staff and faculty for their unremitting leadership as well. This support will undoubtedly help pave the way to our I future success. I I I I I I I I I I I _ 'F `� ` TABLE OF CONTENTS ur+w�as�r� �F ALASKA FAIRBANKS I I Abstract 2 Introduction .3 Considerations 6 I Constraints 10 Background Theory 12 I Preventative Measures Summary 14 I Well Problems Summary 16 I Workover Plan Summary 17 Plugging and Abandonment Regulations .....22 Conclusion 23 I Figures & Diagrams 25 References 37 I 1 Ift LAKVSRSITY OF ALASKA ABSTRACT FAIRBANKS I Arctic well design has special engineering needs where factors such as permafrost and ice are t loading, special transportation requirements, and arctic material design a e due o the extreme cold and weather limitations. One of the primary considerations for arctic well design is the permafrost layer. It indicates a thermal condition where the temperature of the rock or soil remains below freezing throughout the year. Due to the frozen ground conditions, special drilling fluids are used which normally withstand the freezing temperature and protect the ground from thawing. In some instances, serious hole problems may occur and a timely, cost effective approach must be pursued in diagnosing the problem. This study focuses on a field study of an arctic well that failed after 20 years of production. The study also describes the well design sequence, identifies the impact of failure, and recommends the best approach to bring the well back on production. I I 1 I I I I 2 1 II UM LIN::VERSIFY OF ALASKA INTRODUCTION j FAIRBANKS I The importance of wellbore design is critical in the arctic regions of the world and the issues involved can be detrimental to a well. The design issues start from the drilling process and drilling mud, then with setting of the casing as well as deciding the type of casing and tubing to run, and also determining the best cements to use. These parameters are case sensitive and can vary highly from well to well. However, the fundamentals of each arctic well remain constant, such as dealing with the sensitive area of permafrost. Once the well is completed and ready to be put in service, other precautions, such as well integrity tests, must be met to satisfy a successful production well. Permafrost is both a frozen matrix of water; soil and lenses of ice. These zones can extend from a few feet to a thousand feet or more. Arctic well design strongly restricted by permafrost, which usually lies between 1000' to 2000'. This depth can vary quite a bit from region to region dependent on the environmental conditions. In Prudhoe Bay the depth is from I 1800' to 2000', near Barrow it varies from 1000' to 1300' and towards the Brook's Range it is in the 1400' range. In the permafrost interval the concerns are the drilling operations, thawing of the frozen ground, and with any fluids coming in contact with the permafrost long enough to freeze. On a typical well, without circulation, freezing could occur about 4 -5 days in the wellbore. Cementing is one of the more unique issues. The cement must hydrate before it freezes. This involves proper mixture of the cement and added water. The freezing and expansion of water in the pores and capillaries of the cement slurry leads to the development of cracks in the 3 1 I structure before the cement is set. Typically, conventional cements are not good insulators for arctic wells. I Freeze protection is another pertinent issue that requires special attention. If the well becomes stagnant for more than 4 or 5 days, a brine or diesel must be pumped down to help I freeze protect the well. I Another concern in the arctic well design sequence is the existence of thaw bulb. This may occur around a well during production from a deep hot zone and could weaken the I conductor pipe support and create subsidence. I Due to the above - mentioned issues, the design of wellbore in the arctic region can become complicated. Understanding the issue of permafrost is when considering the I characteristics of the design at hand from the drilling process, drilling mud, setting the casing I and what types to set, what type of tubing to run and which cements are most adequate. After well completion, other precautions must be met in order to satisfy the needs of a successfully I producing g well. I When serious problems occur, a timely cost effective approach is essential when diagnosing and repairing the issue. The particular well of focus for this project had collapsed this well is located in the arctic region of Alaska, the collapse is not directly Even though g p Y I caused by permafrost. The problem arose from cement settling at the surface, which led to water I entering the void space between the conductor and surface casing. The water then sat on the surface of the settled cement and reacted with the salt in the cement creating a solution. The I mixture of oxygen, sodium and water created the perfect oxidizing agent. This caused the metal I to rust when in contact with the solution for an extended amount of time. The rust weakened the surface casing and resulted the formation of holes. Water entered through the holes, froze and I the external pressure from the ice expansion caused the intermediate casing to bend and thus 1 4 I I creating an external stress point on the tubing. A pressure test (mechanical integrity test) I performed on the well caused the tubing to collapse. I The following describes the best approach, technique, and tool selection that should be implemented to remove the tubing and repair the casing. It will discuss the procedure and I purpose of these techniques. It will also explain the type of fluid that will be used to keep the well stabilized due to the lack of a plug downhole and the difficulty in placing one because of the collapsed tubing. Protection is required at the surface as well to ensure formation control. Using I the best economic approach, a final decision will be discussed to determine whether to put this I well back in service or to plug and abandon the well. The evaluation will also clarify the proper way to plug and abandon the well. I I 1 I I I I I I I I 5 I I h uHW€Rsiry OF CONSIDERATIONS ALASKA I FAIRBANKS I Casing types are dependent on setting depths, mud weights, formation pressures and pay zone thickness. The main categories are conductor, surface, intermediate, and production g P casing strings, which are described below — ■ Surface casing • Cover fresh water sands to prevent contamination • Maintain hole integrity • Minimize lost circulation into shallow, permeable zones • Cover weak zones that are incompetent to control kick - imposed pressures • Provide a means for attaching the blowout preventors • Support the weight of all casing strings (except liners) run below the surface pipe • Intermediate Casing • Isolate salt zones • Isolates weak zones that cause hole problems • Same motives as drilling liners o Cost effective method to attain pressure control without the expense of running string to the surface. o A full string of casing can be run to the surface instead of a liner if required. 1 6 I I • Production Casing (oil string) • Isolate the producing zone from the other formations • Provide a work shaft of a known diameter to the pay zone • Protect the production tubing equipment I When producing hydrocarbons at the liner, in which the deeper section is not commercial, a tie -back string is used. A tie -back is a section of liner that is run from a liner hanger back to the wellhead after the initial liner and hanger system have been installed and cemented. A tie -back liner may be required to provide the necessary pressure capacity during a flow -test period or for special treatments, and is typically not cemented in place. In some cases, a tie -back liner will be installed as a remedial treatment when the integrity of the intermediate casing string is in doubt. (Oil field glossary, Schlumberger) • Tubing • Evaluated for the producing conditions Space-out — tubing placement relative to the • p gp packer and the p production tree • Flowing — oil and gas up the tubing • Stimulation/Squeeze — high tubing pressures and fluid densities, annular back -up pressure, and cooling effects due to surface fluids being pumped down the tubing (including acid and cement) • Depletion — when the formation pressures are reduced to a non- economical productive level 7 I I • The severity of the stress loads under the operating conditions controls the design criteria I * Note that the tubing is an expendable string that can be replaced. • Hole size I • Based on bit and casing size availability as well as drilling conditions • Deep, high - pressure wells usually deviate from the common geometries I The hole size at the surface of an arctic well can be much larger that the casing and this is due to gravel that is sometimes packed around the casing to help insulate. I • Drilling fluids • Cool and lubricate the bit I • Clean the hole 1 • Carry cuttings to the surface • Remove cuttings from mud at the surface • Minimize formation damage 1 • Control formation pressures I • Maintain hole integrity • Assist in well logging operations 1 • Minimize corrosion of the drill string, casing, and tubing I • Minimize contamination problems • Minimize torque, drag, and pipe sticking I • Improve drilling rate I 8 I I I The drilling fluids in the arctic well need to be chilled to keep the permafrost from I thawing. By using available cold lake water or some type of refrigeration device or cooling mechanism this can be achieved. (See figure 11) I I • Pressure Requirements are decided when the setting depths, casing designs, cement, etc., are established. The casing design can vary when abnormal pressures are known to be I encountered. I I I I I I 1 I I I I I 9 I ti RS�ry O FD CONSTRAINTS I FAIRBANKS I The constraints with developing an arctic well can become quite cumbersome and take lengthy amounts of time when trying to get the well drilled, completed and into production. of the major issues that are encountered are: the government regulations, the availability Some � g g � tY I of resources, supplies and equipment, transportation issues, weather problems, and extreme cold I conditions. Government regulations are the leading and most extensively drawn — out procedures that I are required from the start of an arctic well, to the completion of one. There are many criteria I that must be addressed such as obtaining permits, complying with all the posted regulations (which may vary from lease to lease), dealing with the disposal of fluids and gas, acting in I accordance with the numerous of environmental policies. There are also several inspections that I must be performed once the well is completed. These involve but are not limited to drill stem testing, meter proving, mechanical integrity tests (or MIT's), blow out preventor testing (BOPE), I and safety valve testing. I Flaring oversight is a program that tries to eliminate the unnecessary flaring whenever possible in which the Alaska Oil and Gas Conservation Commission (AOGCC) has control. 1 AOGCC also helps regulate the operations of waste prevention. Drill stem testing is performed I to check the integrity of the well bore once completed. Meter proving is a procedure performed verify the accuracy of crude sales meters used for royalty and severance tax determinations. I to MIT's are performed on new injection wells, workovers and repairs to injectors. The BOPE tests I and surface safety valve tests are performed to check the integrity of the blowout preventors. They must operate correctly before the well can go into service or production. 1 I 10 I I The availability of resources is another issue that acts as a constraint. Once in an isolated location, the tools and equipment maybe be hard to come by if overlooked initially. This will be costly since crews may have to wait days before a part or correct tool arrives. The longer this takes, the more money is expelled. A significant amount of water is needed and if not readily available it will be expensive to import it in. Temperature plays a large role as well. The frigid temperatures can cause fluids to freeze, thus the fluids must be circulated or have additive mixed into them to prevent freezing. The temperature can affect the equipment as well by causing brittle fracturing if not taken care of properly. Any sudden hits or drops can be catastrophic to the casing, tubing, or equipment that is essential for the preparation of the oil and gas wells. The cold can be detrimental on the generators, motors, and the people as well. Extra precautions need to be made when working � P p P g in the extreme arctic temperature to prevent engines from quitting and crews from being injured. Transporting rigs and equipment in the arctic can be quite difficult. Exploration rigs must wait for ice roads to be transported. This must be done quickly, before the ice roads melt in the spring. In addition, delays might arise to deliveries from blizzard conditions. I 1 I I I I 11 'V UN£rnaF BACKGROUND THEORY I FAIRBANKS If a welibore is drilled through a permafrost zone, the warm formation fluids being produced can cause the permafrost adjacent to the well to thaw or melt. This can be detrimental to the casing, causing it to buckle when it loses the lateral support and also cause the casing to move g g pp g downward due to subsidence. The thawed region at the surface will also start to subside as the saturated soil starts to consolidate. This can be resolved by cementing the casing below the of the uncemented portion of the casing permafrost zone and suspending the weight o p g with a means at the surface which would not be affected subsidence -wise by the thawed region. Some constant relief of tension can also be considered on the casing. If the walls along the borehole of the permafrost zone are weakened by the thawing of the I permafrost and the casing travels downward due to subsidence, the casing will buckle. The thawing adjacent to the wellbore will also cause the hole to enlarge. If the casing is hung in an ordinary manner disregarding the presence of permafrost, the casing will be under compression and result in damage. A casing support can be used for the top casing, which would keep the casing at a fixed level. The North Slope encounters thaw bulbs and subsidence, however, severe buckling or collapse has yet to be associated with it. If piles are used in the permafrost, twice as much length should extend into the part that does not thaw as the part in which does thaw. Drilling fluid selection used in drilling a wellbore in permafrost, can be employed as a major component in the cementing materials selection such as a rapid setting, strong, low permeability. The cement can also be insulating, which provides adequate resistance to corrosion and the effects of freeze cement that shows good resistance to corrosion and the effects of freeze — thaw cycles. The use of a thermo casing and arctic set settles cement that can cure before it freezes, Y g 12 1 I should be used. This has been proven to be sufficient historically. However, to prevent wellbore I damage, a seal should be used at the surface. I Wellbore insulation is another consideration. A larger outer casing (such as 20" in diameter) and a smaller inner casing (such as 13 in diameter) is utilized to establish an area that is split I into two zones by inserting a casing between the two casings. This will allow two cooling zones I to exist one on either side of the middle casing. Some type of cooling liquid can be pumped through the two annuluses. (World Oil, Jan. 1970) I I 1 I 1 111 I I I I I I 1 13 '11 1 W UNIVERSITYOfALASKA I FAIRBANKS PREVENTATIVE MEASURES SUMMARY 1 The primary initial problem was the oxidation of the casing strings. An oxidation reaction needs all three main components in order to occur: • Water • Sodium ' • Oxygen Removal of at least one of the three, eliminates the oxidation of the casing Stipulations for new wells: Removal of water: • Use new sealed wellhead design • • i n using ombine fluted hanger design with new wellhead des C g g a sealed wellhead with g g threaded fittings in order to provide cement to the annulus • Use sealant with new wellhead to assure that there is no unwanted communication between the surface and annulus Removal of Sodium: • Use a salt free cement for the top 10 -15' • A 15.8 ppg Class G cement is recommended Removal of Oxygen: • Monitor settling cement to assure it is maintained to surface • Assure cement to surface when pumping in order to know that it has been filled I Stipulations for retrofitting existing wells: Removal of water: 14 1 • Retrofit the wellhead to be sealed perhaps by welding a cap on the hanger to cover the flutes ' Removal of Sodium: • If applicable, use a salt free cement for the top 10 - 15' Removal of Oxygen: • Monitor settling cement to assure it is maintained to surface • Assure cement to surface 1 1 I 1 1 1 1 1 1 1 1 1 1 15 1 1 VA F WELL PROBLEM 1 UMtYEI SITY of ALASKA FAIRBA SUMMARY 1 1 • Cement settled at the surface • Water entered the void space between casing 1 • Water reacted with salt in cement • Mixture of oxygen, sodium, water created oxidizing agent 1 • Rusted the casing metal • Rust weakened the surface casing and resulted in holes 1 • Water entered the outer annulus and froze • Ice expansion caused external pressure on intermediate casing 1 • Casing bent and created an external stress point on tubing • A mechanical integrity test collapsed the tubing 1 I Conductor Pipe — — 1 Surface Casing III Intermediate Casing ®, Water Ice 1 Production Tubing III 1 Point Corrosion Load II Ili 1 Porous Soil Freeze Protect 1 Freeze Protect Cement Lost Cement to Soil 1 Cement I 1 6 1 i HftF . WORKOVER VER PLAN 1 Uti VERSITY 4F ALASKA AIRS HKS SUMMARY 1 1 STEP # 1 The collapsed tubing must be removed while still maintaining well control. A gauge ring must be 1 used to determine the dimensional compatibility of the tools and equipment that could be used to I pass through the casing annulus. a. If the diameter is adequate, the Bowen Series 150 Overshot (Figure 2) should be selected. 1 The Bowen 150 Overshot has important well control and safety features such as high 1 pressure pack -offs, capacity to release, capacity to circulate through the fish. In the case of this well, circulation through the fish is not an option due to the collapsed portion of 1 production tubing. The main concern at this point in the process is well control. At this 1 point the only well control is 9.8 -1b /gal brine, which is in the annulus 40 feet from the surface. It should not be necessary to use the high - pressure pack -offs, which helps I eliminate the risk of a kick or blowout. As a further precaution, BOP with 2 7/8" rams 1 should also be installed. Using the Bowen 150 overshot the team will be able to do a blind back -off. The main concern of a blind back -off is the disconnect point. If the 1 production tubing is too weak at the point of collapse then there is a distinct possibility 1 that it could break at this point. If this happens, alternative measures need to be taken to get re- attached to the fish. If it does not break at this point, then a clean backing off will I occur at a threaded joint. The benefits of a blind back -off include no debris downhole 1 from any kind of milling. Also the risk of the blind back -off is much less of a risk then I some of the milling options since there is reduced chance of creating additional problems. scenario, with an overshot and blind back-off, the tubing In the worst case sce g twists off at 1 17 1 1 the collapsed point. If this happens then the situation remains the same as the initial 1 situation, which is not a detrimental issue because the fish is only 37' down; multiple 1 trips should not be an issue. If the blind back -off works, one trip to engage the fish and I remove it from the well will be all that is necessary. The advantage is quick and easy removal of the fish with no cutting drilling or milling, with no risk of further damage to 1 the intermediate casing or multiply casings. i. If the tubing backs off at a joint directly below the damaged section, this would be the best -case scenario. 1 • Risks will include gas being released from inside the tubing, as well as gas release from the annular fluid due to disturbing this I fluid as the tubing is pulled out. Leaky pipe connections let the gas 1 move from inside the tubing to the annular fluid. To ensure well control, BOP with 2 7/8" rams should be installed in addition to a I packer. 1 ii. If the tubing backs off very far below the damaged section, the scenario will be riskier since, more tubing will be removed, the amount of gas will I be greater. 1 iii. If the tubing twists off and breaks in the damaged section, an alternate I plan will be needed. • If an external cutter will fit around the squeezed tubing section, 1 this method should be used because the risks involved with it are I less than with milling. ➢ This risk is not being able to get to the bottom of the 1 damaged area I 18 1 • More than one run may need to be made to totally 1 remove the damaged section. 1 • If the cutter cannot cut the flattened pipe, a milling bit will need to be used. b. If the diameter is inadequate for an overshot or for an external cutter, the damaged section will need to be milled out of the way until the pipe is round again. The proper plan will be to use a washpipe assembly with rotary shoe (see figure 1), 1 and mill on the 4 1/2" tubing for approximately 100' since the collapsed tubing 1 should not exist for a greater distance. i. Milling will create debris that could block off the tubing and will need to 1 be removed. 1 ii. Milling will also damage the 9 5/8" casing for the length of the 100'. iii. The 100' may not be long enough to grind away the collapsed tubing. 1 • Pull wash pipe and assembly out of hole and then run in with a 1 washpipe assembly with an external pipe cutter to approximately 150' and cut 4' /z" tubing. STEP # 2 Once the damaged section is removed by one of the above methods, use 27/8 pipe and a false ' rotary table to go inside the tubing and use a balance plug to lay cement bottom of the tubing. a. Risks associated with using a balance plug. 1 i. The balance plug may move from where you want it. 1 ii. It may move out of the zone completely. b. There are also risks associated with using 27/8 pipe to go through the tubing. 1 i. There is no BOP control on the 27/8 pipe. 19 1 • Be able to bullhead fluid down the pipe to stop any fluid 1 advancement if needed. STEP # 3 Before the tubing string is removed from the hole, the top of the 95/8 casing should be removed and replaced above the cement since it is oblong as shown in figure 3. This will also stop 1 constant fluid control issues inherent with the holes in the 9 casing. a. Locate top of cement with log and cut casing 1 1/2 joints above the cement level. ' • Assume the logging tool can get through the damaged section of 95/8 ". b. Pull out pipe and back off stub using a Tri -state type D casing and tubing spear. c. Fish 9 -5/8" stub using the Tri-state type D spear. d. Prep the hole for the replacement casing. ' e. Run in new 95/8" casing with Baker Triple Connect and Halliburton ES Cementer. f. Pressure test casing with a mechanical integrity test to assure the repair was ' successful. ' g. Circulate 15.8 ppg Class "G" cement slurry through the 9 casing. Pump the cement until it reaches the surface in the 9 and 13 annulus. Once this happens, close off this annulus and continue um in cement to squeeze cement into the 13 P P g and 20" annulus until the cement reaches the surface in that annulus as well. h. Monitor the settling of the cement and top off the cement column to surface as needed. 1 1 STEP # 4 Once the producing area is abandoned, use an internal chemical cutter on E -Line in the tubing to cut it off above just above the packers. 20 1 1 STEP # 5 1 Once the tubing is cut, use the Bowen series 150 circulating overshot to attach onto the cut tubing string. Circulate brine through the tubing to remove the contaminated water and diesel in I place that is potentially contaminated with gas. Once the diesel has been replaced with 9.8 ppg 1 brine, the risk of kicks and blowouts due to gas will be eliminated. 1 STEP # 6 1 Before the tubing string is removed from the hole, the top of the 95/8 casing should be removed and replaced above the cement since it is oblong as shown in figure 3. This will also stop I constant fluid control issues inherent with the holes in the 9 casing. g 1 i. Locate top of cement with log and cut casing 1 '/2 joints above the cement level. • Assume the logging tool can get through the damaged section of 9 / ' 8 ". 1 j. Pull out pipe and back off stub using a Tri -state type D casing and tubing spear. pp g typ g g p ear. 1 k. Fish 9 -5/8" stub using the Tri-state type D spear. 1. Prep the hole for the replacement casing. I m. Run in new 9 sis„ casing with Baker Triple Connect and Halliburton ES Cementer. 1 n. Pressure test casing with a mechanical integrity test to assure the repair was 1 successful. o. Circulate 15.8 ppg Class "G" cement slurry through the 9 casing. Pump the 1 cement until it reaches the surface in the 9 and 13 annulus. Once this happens, 1 close off this annulus and continue pumping cement to squeeze cement into the 13 and 20" annulus until the cement reaches the surface in that annulus as well. 1 1 21 1 1 p. Monitor the settling of the cement and top off the cement column to surface as needed. STEP #7 Use the Bowen Series 150 circulating overshot to fish the cut tubing string out of the hole. 1 STEP #8 Set two permanent plugs in the 9 casing just above the production packers. This will ensure that the well is adequately abandoned. 1 STEP # 9 The well is now abandoned and ready to be side - tracked. If a side-tracking option is pursued at a Y g p p later date, the whipstock can be set on top of the topmost plug to facilitate the side - track. 1 1 1 1 1 1 1 1 22 1 1 IDE AL WORKOVER y PROCESS I UNNERSITY OF ALASKA FAIRBANKS WITH BOWEN SERIES 150 OVERSHOT 1 1 I. Engage fish with releasing overshot a. Using the overshot engage the fish with the grappling mechanism II. Proceed with Blind back -off a. Back off tubing slowly in hopes to break the next joint below the damaged section III. Determine the breaking point 1 a. After the tubing is disconnected, determine whether it has come apart at the damaged section or at a lower joint below the damaged section i. If the tubing has separated at the damaged section, then alternative measures need to be taken in order to get this section out IV. Reassess well control options with round production tubing a. An undamaged section of tubing should remain. If there is, then further tubing work can take place in order to make a more permanent well control barrier 1 1 1 1 1 23 UNYER SITY VW OFALASKA Plugging and Abandonment Regulations 1FAJRBAN KS Plugging or Suspended Regulations: 1. Prove the well is a. Mechanically sound b. Fluid migration is not allowed c. Will not damage the freshwater or producing formations d. Will not impair recovery of oil /gas j e. Secure /safe to public health 2. Further prove the well is a. Has future use b. Viable for re- drilling c. Located on active pad - The company must illustrate well diagrams, abnormal zones, proposed work plan and integrity of existing and proposed plugs. - Provide with cite visits, condition of wellhead, pressure readings, i.e. operator control ** If the well does not satisfy conditions in A through E, the well must be abandoned. - Bridg e plug capped lu must be ca ed with 50 feet cement ... - Or a continuous cement plug extending 200 feet within interior casing is placed 300 feet below surface. 1 24 1 'V' UN >WHISK OF ALASKA CONCLUSION 1 FAIRBANKS On the North Sloe of Alaska thousands of wells are producing beyond their original p P g Y scope of existence. Some of these wells are failing due to cementing issues, paired with the freezing/thawing conditions and water encroachment. Corrosion occurs when the salts from the agent. The rusting causes weak cement mix with water and act as an oxidizing ag g oints and p eventually results in holes in the casing or tubing. Water enters and freezes in the void spaces and deforms the surrounding pipe. This will ultimately cause many of the wells to fail unless something is done. Preventative measures should be taken, such as monitoring the cement settlement, using a salt free cement, placing an airtight seal around the surface of the wellbore, or coating the metal. The entire casing design should considered and evaluated when completing new wells or performing workovers. Performing costly workovers would not only cost a 1 significant amount of money, but could possibly produce unwanted risks such as jeopardizing well control. Evaluating the status of some of the older wells prior to failure would be the most sensible plan of attack. The 2009 UAF petroleum engineering seniors worked together to establish the above - mentioned arctic well design sequence and failure prognosis along with the workover procedure. In order to come up with our plan, we spent countless hours of phone calls, intense research, and collaboration on all the parameters mentioned to come up with a plan. With the advice and leadership of the department's professors and the industry's professionals, we as a group derived an exceptional course of action. We used our individual skills, past classroom knowledge, and internship experiences as guides for the technical portion of the project. We learned from each other and took aspects from each member of the group to execute and complete the project. Although we did not agree with everyone all the time, we used our cooperative teamwork skills 1: 25 1 1 to compromise. All of the ideas were treated equally and taken into account. Sometimes they I even sparked new ideas from which we changed our original plans. Frustration was not absent throughout the duration of our project. We faced many challenges as a team such as communication and sometimes technical dilemmas arose as well. II The availability of individual time became a factor. With our various schedules, being able to meet at the same time was difficult to accomplish. Moreover, having little or no experience in the real world petroleum industry added confusion and hindered ideas when our creative brains were I at a stand still. 1 Overall, this project enabled us all to dive into a "real- life" problem and really sink our teeth into it. We gained a whole other aspect of the petroleum industry and what complications I can occur while in to keep up with the world's energy demand. We were able to work with �'Y g P P gY I industry engineers and learn from their years of experience and at the same time show them what we have to offer. This project was a great opportunity to help us transition from students to I professionals. These challenges and efforts provided us with life-long tools and understandings g P g s g I that will benefit us in our lives and future careers and have helped us grow as a group as well as individuals. I I "In today's working environment, teamwork and communication is key, along with I technical findings." - Greg Hobbs, BP Alaska - 1 1 1 1 I 26 1 IVft v RSITY OF ALASKA FIGURES AND DIAGRAMS 1 FAIRBANKS I Mills ano Shcs provide a means to remove metal. cement, or other debris that has become lodged in the well - bore. Mills came in a wide variety of types and are generally used when the ful ID of :he tubular needs to be cleaned. Applications include roiling tight spots, cement, tubing, packers, bridge plugs. a -id other debris_ Boot baskets are run above the mills to collect the larger pieces of debris. Rotary shoes are generally run with wash - pipe in applications where only the material between the tubular being washed over and the ID of the casing or formation need to be removed. Applications include but are not li mited to sanded up tubing and open hole where the formation has fallen in. Washover shoes are also used to mill over packers. This allows for minimum material I removal in order to free the packer. With both mills and shoes it is recommended to run jars and drill collars to help prevent sticking. 1 , 0 ORn F1Pt From Baker Hughes i Baker Oil Tools Catalog • 1 Acc-ELEF A TOR x III — a;IL, OMLA 1 I — o< JAFt 1 ! 1 I - PAMPER ,1AR I 1 cI Ir 9 inylef xi am, 9.17 I WA-SWIPE I TROY 10 DKW 11lj 1 I Iir I ...ETALIJUKAER ROTARY s (ROW 10 MP 74) Romiy Shoe 8oheahola Aaaomblr Figure 1: Schematic of Wash Pipe III 27 1 1 Baker Oil Tools INTERNALJEXTERNAL ENGAGEMENT TOOLS I THE SERIES 150 BOWEN® RELEASING AND CIRCULATING OVERSHOT The Series 150 Bowen Releasing and Circulating Overshot is the strongest tool available Mat to externally engage, pack -off, and pull a fish. The basic simplicity and rugged construe- AMP \ .. ton with which it is designed have made it the standard of all external catch fishing tools. The Series 150 Bowen Releasing and Circulating Overshot is composed of three outside parts: top sub, bowl, and guide. The Basic Overshot may be dressed with either of two sets of internal parts depending on whether the fish to be caught is near maximum site 1 for the particular overshot. Some special conditions apply. If the fish diameter is near the maximum catch of the 1 � I Overshot, a Spiral Grapple, Spiral Grapple Control, and Type "A" Packer are used. If the fish diameter is considerably below maximum catch site (usually 1/2" t12 7 r»;rn a Bas - t ket Grapple and a Basket Grapple Mill Control Packer are used. ! l r - - -- Patented a. Double L p t S Packer r Packer '''' ker ' Milt 1 _. IF5111Ik Basket Grapple Mill Control Salta Grapple . _ n r Bas+ot G e I The Series 150 Bowen Releasing /w� and Circulating Overshot So rai GraPPle 0111 Outer Seal o Control From Baker Hughes Overshots may be identified by one o/ the following strengths. known as "types" They are Full Strength (F.S.) - Engrneered to withstand all pulling. jarring and torsional strain; Extra Full Strength (X.F.S.) 111 Baker Oil Tools Catalog Engineered for extreme abuse; Semi - Full Strength (S.F.S.) - Engineered to withstand all pulling strain: Slim Hole (S.H.) - Engineered to withstand heavy pulling strain only, and Extra Slim Hole (ES.S.) - Engineered for pick -up job only 1 Figure 2: Overshot 1 1 I 1 1 1 1 28 1 1 l -- - �. HYDRAULIC CASING BACKOFF TOOL 1 I ' Product Family No. H14210 i ., i i' DESCRIPTION /APPLICATION c Hydrauic. Casing Backoff Tools are hydraulically o;.erated III 3 I downhole breakout teois used to back off casing at a known or desired coupling ! ocation. They are often used as ar alter- ) native to running a casing patch during a casing repair pro- l gram. 1 OPERATION The typical Hydraulic Casing Rackoff ae consists of one staid of drill collars, mechanical collar locator, lower I _ anchor section, backOlf section, upper Tool anc section , pump out sub, severer stands of drill collars and workstring. Normal- . ly the casing is cut and pulled then the Hydraulic Casing I i i l i '� Backof Tool is used to remove the stub. The tool is assembled and run in the well to the desired depth. The mechanical collar locator pinpoints the collar to be I ; I backed off, and the backoff tool straddles the collar. The an- chor sections are set hydraulically, and the tool is then cycled until breakout is accomplished. The pump is turned off and the workstring picked up. This releases the anchors and al- l k : lows the toot to be tripped out of the well. The backed off cas- 1 ing is then retrieved with an appropriate spear. I 1 FEATURES/BENEFITS 1;: • Eliminates 'bind' backoffs of casing and allows operator to back off casing at known depth and location { . • High torque breakout capacity I • Anchor sections contact special carbide insert nips which make frm bites into casing ID to withstand torque output of tool • Leaves threaded connection for reengaging with new c•s- I r ing string. Maintains full casing ntegrity when casing is screwed back together property • Eliminates restricted ID after repairing casing i • Simple design consists of the top anchor section, backoff I tool and lower anchor section • No left-hand workstrings required for backoff u N,,.• • An€h« drive Section tom* Amt"Ir • Over torquing of to joints in workstrng is eliminated, sav- Hydieulk en Cimino Bakk Tool ing connections I V* 1 7? 1,1 7. - I 4-4y N, 1114411 • Can be used with tubing as a workstring, if necessary SPECIFICATION GUIDE I .r �? (Al t nr re. '.5': a• 5, "A:1 p 41 !.'J •raUVJO In In F.• ':•.n< I r7rt1 zsa -ma ' as 65.7 i . :.c: 142.0 I 1.1:2' ..'9 t_ i 25,000 1 n 1-518 1.193..8 24 • 87.1 70.: . g -518 244.4 32 - 5 35-7- 3.5 47.7 7 a2 10-W4 i ?::? 11 32 /5 . 551 46 . 7 - $7 7 IMO %.3 6.503' API Roo • 1 ?•351 .� 42 -68 82.s -8A3 34 ' 10.36 so.no 13 -3'8 ! 333.7 44 - 72 7/.4 . 107./ 1 I From Baker Hughes Figure 3: Casing Backoff Tool Baker Oil Tools Catalog I 1 I 29 1 1 HYDRAULIC CASING SPEAR I Product Family No. H12309 II DESCRIPTION/APPLICATION The Hydraulic Casi -g Spear is designed to be run above a I • , \ ,____. mecha ' ical or hyoraulic . nskde casing cutter and used to re- trieve casing sizes from 9-518" (244.5 ,mm) to 13 -318" (339.7 mm). This application allows `or to cutting and pull- ing of the casing string to be accom;.l - Ed in one trip. The r - I -- erne M - spear can be rotated inside the casing string without engag- e I irgg. Once the cut is completed the spear can then be posi- • timed at the desired location inside the casing string. The } f rugged design of the spear makes it well suited to withstand t the most severe downhole environments for retrieval of cas- �y 4 e r ing 4 - OPERATION 8 Dress spear to the correct size casing to be engaged. it is 12 i Lii recommended to run the hydraulic spear one joint above the cutter you are using. This wil prevent having to strip out of I i the casing at surface to lay dorm cutter and accessories. i Once cut has been made, pickup to position the spear at the i _ i top of casing string. Drop restriction plug in drillpipe. Allow I one minute per 1,000 ft (305 m) for restriction plug to seat in i I I i spear. Pressure up slowly to the necessary pressure drop (minimum of 500 psi [34.47 bw) to set spear. Once the I-y- draulic Spear is set pickup and pull on casing. Pull out of he slowly. Set the joint of pipe on top of the Hydraulic Spear in rotary and drop shear release ball in pipe. Pick up :: ; r-fi kelly or top drive and screw into same. Pick up and set cas- ing in slips and secure. Pressure up on spear to the neces- 1 1 1 sary shear load. Once shear screws are sheared spear is 1 rc eased and can now be laid down. I FEATURES/BENEFITS • Allows for cutting and retrieval it cne trip I - • Simple construction permits ease c` oaera:icn anc main - i' tenance I • Bore through ID of tool permits circulation to casing cutter r,�„ s _ �y, :x.. • Slips are retracted Inside of body to prevent damage to I r- : ti=: I ' • r: tool cr casing when casing is being cut downhole • Easily dressed for alternate casing sizes • Set and released hydraulically. No mechanical interven- tion required I From Baker Hughes Baker Oil Tools Catalog SPECIFICATION GUIDE Teel Outside Inside f Overall 1 Mambo. Standard Diameter Size In. I tart► In. teen $ In ram Thread r e 00 29.3 2 '1 "ST 3 5 t $ 4 ) 0 1.55$ } ' 4 - 1 9 1 1F 1 Figure 4: Casing Spear 1 1 30 1 1 I TRI- STATE` TYPE D T'' CASING AND TUBING SPEAR Product Family No. H12009 1 DESCRIPTION/APPLICATION -- e Type D"'' Casing anc Tubing Spears are used to retrieve al _acing sizes from -1.2 - 30" (r t4 3 mm - 762 mm; The desig ' e: I the spear manes it deal for backing off casing cr rotating cut mudl hangers a-d packer bcre receptacles. The spear ca- be seticr r g" t- hand or left -hand release anc is easily field :tressed to change the release setting. The J stet, which holds the spear in the catch cr re- I — 11 ' lease position. makes this spear the most reliable for the recovery of small lig- :- weig -t fsh To e-gage t -e spear, it s lowered into the fish until the stop ring is II I ta weigh :. 0 - quarter rotation will plate the spear r the catch positon. _ -e spear s released by bumping down then applying one - quarer rotation - t -e opposite direction. Because the mandrel must i . travel down the body length of the J slot to release. the stop ring I P s not to removec from the bccy. z ■ I FEATURES/BENEFITS - ' • S mpie cc'structen T _ i 1 1 • Slips with carburized teeth and large surface area 1 f *Sets for left- cr rig:: ^.t -hand release . • Eas ly dressed for alternate casing sizes • Optonal slips with vertical teeth for backing of I SPECIFICATION GUIDE Casing 5pesr Spear Sze OD iJ _ . in. in. in. Spear min 4 -112 - 5 3 be 1 v5:. 91 51.2 Ea8 450 3 • I =1 I - 7 - a -116 5 ' G 750 4.5 6 -11a - s -sIa 5 6 ?5 a 9 -5., - 11-31 6 :::0 6 3.000 78.2 • 11-314 - 13.3/5 •0.50: 266.7 15 - 20 ' •: oo:: _' .6 3.500 88.9 21 - 30 20.75 527.1 From Baker Hughes Baker Oil Tools Catalog I r y;rr 0 cuing end Tubing Spero. �u Family No Hi2009 Figure 5: Casing and Tubing Spear 1 1 1 I 31 a Ir A1-10 '14%1 “rt I Arctic Well 0 1O 4., • 33 cISs' T",* ,.. 91 • ' .1.41 I 'wa 4 7 .0* *71 I* %.* s „I' • ll Mouum w 2.3r (#1024? 1rn 2-7 IN 6" LINER TOP, P 0 1 I ------ *ler H „ — 4 101 fl' at. r • *V** 0.4 7V 1022s. H 4 I 'VP Mr] af 2 t ictifi .1",ZYUENT14,kg c cr 1 10214 4 . c. 1 'Bo z 3 c • : )tv 147,1* 10211' H slOWINN 7C. OF S ...NAT WV Xt3Ctr IEJ *tr V'4 44 . 0* t 105 • • Is 'V' 11214 3240' 7 r; esvoiee,e 11444 I • .1 41r, NIP 4 'S ,fitat,14,_. 5D 3 sps*.* 2.841" }—* Courtesy of: aogcc.alaska.gov Figure 6: Schematic of our well I I I 32 y R v 1 1 • Vi Courtesy of. aogcc.alaska.gov Figure 7: Image of Cased Interior 1 I I I 1 33 1 I 1 — 1 1 i 3 i i 4 \ I . . . 4 . , 4 , 4 II / n. A Is / o — I i ,.,, I 1 ' . . . . 1 _ . a . „ t 4,-.. 111 4 - - ., .. , I onir . ... ...4'.. - , — _ I 4- - lc- ... , -4 ....-, Courtesy of: aogcc.alaska.gov I Figure 8: Photo of Collapsed Tubing I I I 1 34 I I I I --....- - I I CRAIN'S PETROPHYSICAL HANDBOOK FIGURE 05.14: LONG AND SHORT SPACED SONIC LOGS IN PERMAFROST I I SONIC LOG GR TRAVEL TIME I • I • 140 90 40 LTIEZESTZ.Ing 1 MagE32'-'.,____:'--".... _ ... ....sm..r7i— .... IP+. • I ONFININ.M.1101•11.01MM•■ 4•1711.■M•••••■■ ....am •■■*■••■••••=41■= I .11141.1.01.==.4===irros■■•••••••• OM 11111.00 =. •■•■••••■••,==la ................ . :.....m.m............ ..= ...rt........r....m...m.= 1:""""'"•'M ism= a ___. -F-_,...r.=.7 I ..--.. ......=.esz==................-== _•________ = .______= .... _ onmooMolp.....• ..111•1.11■111M11....•• IN•••••■•■ •■■•■• • -...0••■•• /MO MN *1•1...r., .■■••• a a I la •No NIIIMMI.•••■■■•■•■■■ ■■■•••••■+m, S INI " Iimi aro .....== NH os ..■=......■ MI.M.N.O.N. == ..7.01=97..........■ = . ........,.. ... '■' , ="•'• ` •■•••■•■ .. 2 :==*z12L.....:= =4,===...— - _■•.11= ,.. i=,.........,.......... ==SOLICIRIC= ..... NmEl. ■••■•••■••■•■•■■••••■•■■ Z ■•■••••••••• `. -•••■•■•■• I = .Z. === =.....""=".= mow • MO aw .•■•■••lo 4.' -7 ............................taiam• nme■•■■••••••■—_,_ = SHORT SONIC -----= = ZE---...--- .-....— -...... . r.....-ri. Iracmz....--. .. =_-..:.= =sasz...-- — ....1:111......... == : 311:2-==„=• p LONG SON IC .-.. --- .11.011, .010•11111.nw.m■ ===•■•■■• •••••■■•■••• , ■mowe....M. !my •■■••*.mw ....T. I === =.1.11" - '''''''' ..=•.= =• .1 = . .... . = I ... -- ■•••Meo.“01.1 1 ROZE ±b- 7.-.1.-...- = ,„ L .....=.111. s A N • =1„ ‘..,...., ....." -..... ...........==_.-...... FROZEN SAND VELOCITY I ......................._ -=.:..... ====== UNFROZEN. - =' - e TZ- ====a 9 :4-7.-: ===Z'== VELOCIT - ...__"" ;SE 18000 FT. / SEC . L7 . - .1..7.-, 8000 FT/SEC 2 t• _.=- =SI_ g .: ..E4 tt. f: :: :::....f: =-..-.— - ......-. -- - .......„ -....... --.... --- ...kr= = ---,== 411011.11■11111.11■ ••■•••••••••• ""...""'"'"'''''''''' ''''..iL.U====•■ ----...sm ==... ...—r.T...--..„....--.......—....... ..i2 T.-- ------- -- ----- ■•• .10.1.••■■ •m• •••••■•• ....m. IIII.M•■••■•■■•.....- ■ 1111 ..".. ''....==== . Ma IND ... 41.1,011• •■•■■ .=.m. a . ===== =___.z.........:-.= . --. =""======.1.1r........ ......” m ...m.... I ............,-- , tl...ta .:: .......r............. em.■....r ow ..................., i OM zliiiimparow.......11•IMAMIN.1.••••• ===■=3 wage ========='..wW•■••■= 3 -...... am qma m■ aw• am...ye •■••■•••••••• ■ ...... ....■...............■,.. ■••••• ■ ...••■• =,........,.........,, ..,.,,,,....., =.116311===== -,' ." ................... ........-' - -. .., ..., :-.45,..--:-..._Ez..-.4-fa Erralas==:. '".■....."__*".",&-"" - I , = = = =2■.• = = 3 31 ... „„,......,.. ====........=.. ...... FROZEN S H A L E ...--- ------. _ =Zara 2..... - :.................-........ SAME V E LO C I T Y •■■••• .. .. .•111•• ■IM.M=M .." % % •••■ : : ..■••••■■■•••■•••■■ " =MI 6 :' P••== AS UNFROZEN , .._, Mr1121111==............. _ ...MI...mu.. I =7 ======== •••• • """7, ...... .... ...........= _. - • --==== =nu am-- ...•■=11: 4m...rat Owe= OM MI -.ma =••••••■ •■••-........ ."""""'"..=.'".......... '... .".==•.: Z om•MIN ......st:r.• ... - —_ —_—..-■■= •■•• ■•= , IN ... aw . 1•11•••■■• =`=:•====== I I OAIONAl. DRAWING COURTESY OF SONLUMBERGER 1 35 Figure 9: Type Log with Permafrost I I I I I . ', ct Discontinuous Taig tundra perrnaErust 47 -7 :. -s- , 4 ..,..• f . A. —,.. .' .. . - + ' r -' 4 ` E`er' , z , ... .;-.7.4.' .4st----tr- ty.. .. COMM! uc _ _ r . _1- I • ti:r c rr Soil Sporadic 1 permafrost permafrost http: / /www. deft- geochallenge.ca /atlas(Images /arctic PermafrostEn.jpg I Figure 10: Permafrost Schematic II I 1 I I I I I 36 1 I Drilling Fluid Retails • Dr' Ilinil Fluid F�eturns Mu ! Ta nh;. �', Mi 1 Tanr.s . Is ' I Flu e0- 1 _liille�.l _ * msL G 31 Cl ill lin�l ":I ' - surface -' IN711 �'. 1 CU rl.Y_8 D ;� Peimafrest Mel — s :1707.----IM Casing ss ^ . M1 - :�t3bil F'e r7�efrost 27m 11 — — iJr "en Hole O en Hole r r 7 I 1 I 111 26 . .. I . I Arctic Drilling ithart Temperature Control Ar ctic Drilling with Ternporat ire Control 9 y L(" i- 40-,.'....740tt:_',. " y ,6.... i1 1 Cl 4 t .., ' ', :4 t t: T,; ; : : not 0J,� tiiiiirfi i0 JMO Sta'.' At�'�tVt:id, �Sfu : !i�•.::.��y� (� ::d.) l 4 "y r "0 !r! ! .. 5 _ . � j . afrAadr hi�� rig and cvnal�c3�r. &o-i.:71.:....,..; OL! (. ,' On , .; : ! i gyp p 1' t J } !� 7 ! h P 1f / (is � ""° nn 4. t a' "b sing OMAN to coog000 41to so:.o bt6: :: 4 '.JYriJiL ! i0, ." y6r .r !�rB.R. to, ,:t.o." www.drillcool.com /downloads /geochiller I Figure 11: Schematic of temperature control device I 1 I I I I I 1 37 I I 1 1 ' Slurry 111' Tubing III Or I Workstring r ------ Packer , r4 " a I I _V \ _ ___,,_ ,-- 2_:,_ <-_-- - . _ (rPerforatiot3s l ` _I]. i 11) 1 _ 1J IL - 11 - ' _ ---- - H _ H. r <_______ Bull heading Applying WIC Cement Pressure 1 Pump Down or Bullhead Squeeze Figure from: http: / /ocw.kfupm.edu.sa /user PETE3020102 Short %20Remedial %20Cementing.pdf I Figure 12: Schematic of bullhead flow I I I I I I 1 38 I 'V'W usvrRSITY OF ALASXA REFERENCES I FAIRBANKS AOGCC: Alaska Oil and Gas Conservation Commission. 2008. Online: Commission Functions and Processes: http: // www. state .ak.us /admin/ogc /homeogc.shtml Schlumberger Limited. 2008. Online: Oil Field Glossary http : / /www.glossary.oilfield.slb.com Alyeska Pipeline Service Company. 2008. Online: http: // www .alyeska - pipe.com /PipelineFacts /Pei mafrost.html Hobbs, Greg. Petroleum Engineer, BP Alaska, Anchorage, AK. (907) 564 -4191 or greg.hobbs @bp.com ' Dier, J. S., "New Ideas Solve Permafrost Drilling /Cementing Problems ", World Oil, May, 1969. Quay, Walter, Chevron. Drilling Engineer, ASRC. Anchorage, Alaska. (907) 263- 7812 or wquay�?a,chevron.com Mike Chivers, Chevron, Lead Operator, Steelhead Platform. Nikiski, Alaska. (907) 252 -1263 or chivemw@chevron.com ' Rick Parrish, Chevron, D &C Engineer. Midland, Texas. rdparri @chevron.com 1 http: / /ocw.kfupm.edu.sa/ user /PETE3020102/ Short%20Remedial %20Cementing.pdf Rich. "ANWR — pictures are worth a thousand words" June 28, 2008. Online: 1 http:// fromtheduke .blogtownhall.com/default.aspx 1 1 1 1 1 39 • • gyrodata Gyrodata Incorporated 1682 W. Sam Houston Pkwy. N. Houston, Texas 77043 713/461-3146 Fax: 713/461-0920 November 21, 2007 State of Alaska - AOGCC Attn: Christine Mahnken 333 W. 7th Ave, Suite 100 Anchorage, Alaska 99501 Re: G-Pad, Well #G-19A Prudhoe Bay, Alaska ~~~ ~~. Enclosed, please find two (2) copies, and one (1) disk of the completed survey for the above referenced well. We would like to take this opportunity to thank you for using Gyrodata, and we look forward to serving you in the future. Sincerely, ' ~tl~ DEC 2002 Rob Shoup v North American Regional Manager RS:tf Serving the Worldwide Energy Industry with Precision Survey Instrumentation • gyr data Gyrodata Incorporated 1682 W. Sam Houston Pkwy. N. Houston, Texas 77043 713/461-3146 Fax: 713/461-0920 SURVEY REPORT BP G-Pad #G-19A Prudhoe Bay, AK AK1007G_549 2 Oct 2007 Serving the Worldwide Energy Industry with Precision Survey Instrumentation ~ ~~ ' 1 v J A Gyrodata Directional Survey for BP EXPLORATION (ALASKA), INC Lease: G-Pad Well: G-19A, 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 549 Run Date: O1 Oct 2007 Surveyor: Steve Thompson; Michael Villarreal Calculation Method: MINIMUM CURVATURE Survey Latitude: 70.318984 deg. N Longitude: 148.725210 deg. W Azimuth Correction: Gyro: Bearings are Relative to True North Vertical Section Calculated from Well Head Location Closure Calculated from Well Head Location • • Horizontal Coordinates Calculated from Well Head Location A Gyrodata Directional Survey BP Exploration (Alaska), Inc Lease: G-Pad Well: G-19A, 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 549 MEASURED I N C L AZIMUTH B ORE HOLE DOGLEG VERTICAL CLOS URE HORIZONTAL DEPTH BEARING SEVERITY DEPTH DIST. AZIMUTH COORDINATES feet deg. deg. deg. min. deg./ feet feet deg. feet 100 ft. 0.00 0.00 0.00 N 0 0 E 0.00 0.00 0.0 0.0 0.00 N 0.00 E 0 - 9930 FT. RATE GYROSCOPIC MULTISHOT SURVEY ALL MEASURED DEPTHS AND COORDINATES REFERENCED TO NABORS #7ES R.K.B. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 100.00 0.26 198.04 S 18 2 W 0.26 100.00 0.2 198.0 0.22 S 0.07 W 200.00 0.37 197.17 S 17 10 W 0.11 200.00 0.8 197.7 0.74 S 0.24 W 300.00 0.51 195.91 S 15 55 W 0.14 300.00 1.5 197.1 1.48 S 0.45 W 400.00 0.54 194.68 S 14 41 W 0.03 399.99 2.5 196.4 2.36 S 0.70 W 500.00 0.57 185.55 S 5 33 W 0.09 499.99 3.4 194.6 3.32 S 0.86 W 600.00 0.48 186.63 S 6 38 W 0.09 599.98 4.3 192.8 4.23 S 0.96W 700.00 0.45 176.21 S 3 47 E 0.09 699.98 5.1 191.0 5.03 S 0.98 W 800.00 0.61 168.48 S 11 31 E 0.17 799.97 6.0 188.1 5.95 S 0.85 W 900.00 0.29 157.38 S 22 37 E 0.33 899.97 6.7 185.5 6.70 S 0.65 W 1000.00 0.32 160.10 S 19 54 E 0.03 999.97 7.2 183.6 7.19 S 0.46 W 1100.00 0.34 162.81 S 17 11 E 0.03 1099.97 7.7 182.0 7.74 S 0.27 W 1200.00 0.34 161.96 S 18 3 E 0.01 1199.97 8.3 180.7 8.30 S 0.10 W 1300.00 0.33 161.10 S 18 54 E 0,01 1299.96 8.8 179.4 8.85 S 0.09 E 1400.00 0.16 145.71 S 34 17 E 0.18 1399.96 9.2 178.4 9.24 S 0.26 E 1500.00 0.23 174.06 S 5 56 E 0.12 1499.96 9.6 177.8 9.55 S 0.36 E 1600.00 0.27 255.47 S 75 28 W 0.33 1599.96 9.8 179.1 9.81 S 0.15 E 1700.00 0.90 237.95 S 57 57 W 0.65 1699.96 10.3 184.1 10.29 S 0.74 W 1800.00 2.15 222.71 S 42 43 W 1.30 1799.92 12.4 192.5 12.08 S 2.68 W 1900.00 4.13 213.90 S 33 54 W 2.03 1899.77 17.5 199.9 16.45 S 5.96 W 2000.00 8.45 236.14 S 56 8 W 4.88 1999.15 27.4 210.9 23.54 S 14.08 W 2 A Gyrodata Directional Survey BP Exploration (Alaska), Inc Lease: G-Pad Well: G-19A, 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 549 MEASURED I N C L AZIMUTH BORE HOLE DOGLEG VERTICAL CLOSURE HORIZONTAL DEPTH BEARING SEVERITY DEPTH DIST. AZIMUTH COORDINATES feet deg. deg. deg. min. deg./ feet feet deg. feet 100 ft. 2100.00 12.47 241.09 S 61 5 W 4.12 2097.47 44.2 222.1 32.85 S 29.63 W 2200.00 16.15 240.86 S 60 52 W 3.68 2194.35 68.1 228.8 44.85 S 51.24 W • 2300.00 20.06 240.23 S 60 14 W 3.91 2289.38 98.7 232.5 60.14 S 78.28 W 2400.00 24.40 241.05 S 61 3 W 4.35 2381.93 136.3 234.7 78.66 S 111.26 W 2500.00 29.56 242.56 S 62 34 W 5.20 2471.02 181.3 236.5 100.04 S 151.26 W 2600.00 33.71 243.65 S 63 39 W 4.19 2556.14 233.5 238.0 123.74 S 198.03 W 2700.00 35.96 244.19 S 64 11 W 2.27 2638.21 290.4 239.2 148.84 S 249.34 W 2800.00 37.10 244.88 S 64 53 W 1.21 2718.57 349.7 240.1 174.43 S 303.08 W 2900.00 39.01 242.66 S 62 40 W 2.35 2797.31 411.2 240.6 201.69 S 358.35 W 3000.00 41.27 242.13 S 62 8 W 2.29 2873.75 475.6 240.9 231.57 S 415.47 W 3100.00 42.89 243.69 S 63 41 W 1.93 2947.97 542.6 241.1 262.07 S 475.14 W 3200.00 44.42 243.09 S 63 5 W 1.59 3020.32 611.6 241.4 292.99 S 536.85 W 3300.00 44.74 242.88 S 62 53 W 0.35 3091.55 681.8 241.5 324.88 S 599.38 W 3400.00 44.46 242.84 S 62 50 W 0.28 3162.75 752.0 241.7 356.91 S 661.87 W 3500.00 44.22 243.41 S 63 25 W 0.47 3234.27 821.8 241.8 388.50 S 724.21 W 3600.00 44.29 243.10 S 63 6 W 0.23 3305.90 891.6 241.9 419.91 S 786.53 W • 3700.00 44.27 243.28 S 63 17 W 0.13 3377.49 961.4 242.0 451.40 S 848.84 W 3800.00 44.58 243.b9 S 63 41 W 0.42 3448.91 1031.4 242.1 482.64 S 911.48 W 3900.00 44.61 243.60 S 63 36 W 0.07 3520.12 1101.6 242.2 513.81 S 974.39 W 4000.00 44.60 244.04 S 64 2 W 0.31 3591.31 1171.8 242.3 544.79 S 1037.41 W 4100.00 44.54 243.18 S 63 11 W 0.61 3662.55 1241.9 242.4 575.98 S 1100.27 W 4200.00 44.47 243.51 S 63 31 W 0.24 3733.87 1312.0 242.4 607.43 S 1162.92 W 4300.00 44.20 243.41 S 63 25 W 0.28 3805.40 1381.9 242.5 638.66 S 1225.44 W 4400.00 44.24 243.75 S 63 45 W 0.24 3877.06 1451.6 242.5 669.69 S 1287.89 W 3 A Gyrodata Directional Survey BP Exploration (Alaska), Inc Lease: G-Pad Well: G-19A, 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 549 MEASURED 1 N C L AZIMUTH BORE HOLE DOGLEG VERTICAL CLOSURE HORIZONTAL DEPTH BEARING SEVERITY DEPTH DIST. AZIMUTH COORDINATES feet deg. deg. deg. min. deg./ feet feet deg. feet 100 ft. 4500.00 43.92 243.52 S 63 31 W 0.36 3948.90 1521.2 242.6 700.58 S 1350.22 W 4600.00 43.46 243.73 S 63 44 W 0.48 4021.21 1590.2 242.6 731.27 S 1412.11 W 4700.00 43.46 243.74 S 63 44 W 0.01 4093.80 1659.0 242.7 761.71 S 1473.79 W 4800.00 43.05 244.19 S 64 11 W 0.51 4166.63 1727.5 242.7 791.78 S 1535.36 W 4900.00 42.91 244.21 S 64 13 W 0.14 4239.79 1795.7 242.8 821.46 S 1596.74 W 5000.00 42.61 244.35 S 64 21 W 0.31 4313.21 1863.5 242.8 850.92 S 1657.91 W 5100.00 42.65 244.76 S 64 46 W 0.28 4386.78 1931.2 242.9 880.02 S 1719.06 W 5200.00 42.64 244.72 S 64 43 W 0.03 4460.34 1998.9 243.0 908.93 S 1780.33 W 5300.00 42.52 245.30 S 65 18 W 0.41 4533.97 2066.6 243.0 937.51 S 1841.66 W 5400.00 42.76 245.48 S 65 29 W 0.27 4607.53 2134.2 243.1 965.72 S 1903.24 W 5500.00 43.02 245.31 S 65 19 W 0.28 4680.80 2202.2 243.2 994.06 S 1965.12 W 5600.00 43.69 246.59 S 66 35 W 1.11 4753.51 2270.8 243.3 1022.03 S 2027.81 W 5700.00 43.79 246.67 S 66 40 W 0.11 4825.76 2339.8 243.4 1049.45 S 2091.28 W 5800.00 43.50 246.76 S 66 46 W 0.30 4898.12 2408.7 243.4 1076.74 S 2154.68 W 5900.00 43.87 246.90 S 66 54 W 0.38 4970.44 2477.7 243.5 1103.91 S 2218.18 W 6000.00 44.20 246.78 S 66 47 W 0.34 5042.33 2547.1 243.6 1131.25 5 2282.08 W 6100.00 44.91 247.85 S 67 51 W 1.03 5113.59 2617.1 243.7 1158.31 S 2346.82 W 6200.00 44.98 247.82 S 67 49 W 0.07 5184.37 2687.6 243.8 1184.96 S 2412.24 W 6300.00 45.18 248.53 S 68 32 W 0.54 5254.98 2758.2 243.9 1211.28 S 2477.97 W 6400.00 45.65 249.34 S 69 20 W 0.74 5325.18 2829.1 244.1 1236.88 S 2544.43 W 6500.00 45.64 250.14 S 70 8 W 0.57 5395.09 2900.3 244.2 1261.64 S 2611.51 W 6600.00 45.82 250.75 S 70 45 W 0.47 5464.89 2971.5 244.4 1285.60 S 2678.98 W 6700.00 45.76 251.92 S 71 55 W 0.84 5534.62 3042.6 244.5 1308.54 S 2746.89 W 6800.00 45.85 250.38 S 70 23 W 1.11 5604.33 3113.9 244.7 1331.71 S 2814.74 W 4 • A Gyrodata Directional Survey BP Exploration (Alaska), Inc Lease: G-Pad Well: G-19A, 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 549 MEASURED I N C L AZIMUTH BORE HOLE DOGLEG VERTICAL CLOSURE HORIZONTAL DEPTH BEARING SEVERITY DEPTH DIST. AZIMUTH COORDINATES feet deg. deg. deg. min. deg./ feet feet deg. feet 100 ft. 6900.00 45.65 250.42 S 70 25 W 0.20 5674.11 3185.2 244.8 1355.74 S 2882.22 W 7000.00 45.43 250.19 S 70 11 W 0.27 5744.15 3256.2 244.9 1379.79 S 2949.42 W 7100.00 45.27 250.48 S 70 29 W 0.26 5814.43 3327.0 245.0 1403.73 S 3016.41 W 7200.00 45.30 250.46 S 70 28 W 0.03 5884.79 3397.8 245.2 1427.49 S 3083.38 W 7300.00 44.99 250.62 S 70 37 W 0.33 5955.32 3468.4 245.3 1451.10 S 3150.22 W 7400.00 44.81 250.51 S 70 31 W 0.20 6026.15 3538.7 245.4 1474.59 S 3216.79 W 7500.00 44.39 250.49 S 70 29 W 0.42 6097.36 3608.6 245.5 1498.03 S 3282.97 W 7600.00 44.04 250.68 S 70 41 W 0.37 6169.03 3678.1 245.6 1521.21 S 3348.74 W 7700.00 43.62 250.71 S 70 43 W 0.42 6241.17 3747.0 245.7 1544.10 S 3414.10 W 7800.00 43.31 251.19 S 71 11 W 0.45 6313.75 3815.5 245.8 1566.56 S 3479.13 W 7900.00 42.75 251.17 S 71 10 W 0.56 6386.85 3883.5 245.9 1588.57 S 3543.71 W 8000.00 42.39 251.67 S 71 40 W 0.49 6460.49 3950.8 245.9 1610.13 S 3607.84 W 8100.00 42.09 251.74 S 71 44 W 0.30 6534.53 4017.7 246.0 1631.23 S 3671.66 W 8200.00 43.13 251.72 S 71 43 W 1.04 6608.12 4085.1 246.1 1652.45 S 3735.95 W 8300.00 44.11 251.52 S 71 31 W 0.99 6680.52 4153.8 246.2 1674.21 S 3801.42 W 8400.00 44.92 251.65 S 71 39 W 0.82 6751.82 4223.6 246.3 1696.35 S 3867.94 W 8500.00 45.41 251.41 S 71 25 W 0.52 6822.33 4294.2 246.4 1718.82 S 3935.20 W 8600.00 45.70 251.58 S 71 35 W 0.31 6892.35 4365.3 246.5 1741.48 S 4002.90 W 8700.00 45.10 251.72 S 71 43 W 0.61 6962.57 4436.2 246.6 1763.89 S 4070.48 W 8800.00 44.25 251.68 S 71 41 W 0.85 7033.68 4506.3 246.7 1785.97 S 4137.23 W 8900.00 43.65 251.52 S 71 31 W 0.61 7105.67 4575.4 246.7 1807.88 S 4203.09 W 9000.00 42.98 251.52 S 71 31 W 0.67 7178.43 4643.8 246.8 1829.62 S 4268.15 W 9100.00 42.40 251.40 S 71 24 W 0.59 7251.93 4711.4 246.9 1851.18 S 4332.43 W 9200.00 41.53 251.75 S 71 45 W 0.90 7326.29 4778.0 246.9 1872.32 S 4395.87 W 5 • • A Gyrodata Directional Survey BP Exploration (Alaska), Inc Lease: G-Pad Well: G-19A, 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska Job Number: AK1007G 549 MEASURED I N C L AZIMUTH BORE HOLE DEPTH BEARING feet deg. deg. deg. min. 9300.00 41.32 251.60 S 71 36 W 9400.00 40.93 251.74 S 71 44 W 9500.00 40.53 251.41 S 71 25 W 9600.00 40.26 251.19 S 71 11 W 9700.00 40.00 251.30 S 71 18 W 9800.00 39.24 251.30 S 71 18 W 9900.00 38.59 251.80 S 71 48 W 9930.00 38.41 252.09 S 72 5 W Final Station Closure: Distance: 5248.33 ft Az: 247.34 deg. DOGLEG VERTICAL CLOSURE SEVERITY DEPTH DIST. AZIMUTH deg./ feet feet deg. 100 ft. 0.23 7401.27 4843.9 247.0 0.40 7476.60 4909.5 247.1 0.45 7552.38 4974.5 247.1 0.31 7628.54 5039.2 247.2 0.27 7704.99 5103.5 247.2 0.76 7782.02 5167.1 247.3 0.72 7859.83 5229.7 247.3 0.85 7883.31 5248.3 247.3 HORIZONTAL COORDINATES feet 1893.12 S 4458.68 W 1913.80 S 4521.11 W 1934.42 S 4583.02 W 1955.20 S 4644.40 W 1975.92 S 4705.43 W 1996.37 S 4765.83 W 2016.25 S 4825.42 W 2022.04 S 4843.18 W • • 6 BP Exploration (Alaska), Inc Well: G-Pad G-19A 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska 0 -200 -400 -600 -800 w C7 -1000 z Z -1200 -1400 -1600 -1800 -2000 Interp Final_Ca Gyrodata AK1007G_549 DEFINITIVE BOTTOM LOCATED OLE i ~ i i -50 00 -4500 -40 00 -3500 -30 00 -2500 -20 00 -1500 -10 00 -5 00 0 • • FASTING (ft) BP Exploration (Alaska), Inc Well: G-Pad G-19A 9-5/8" Location: Nabors #7ES, Prudhoe Bay, Alaska 10 9 8 .. 0 0 6 a~ v ~ 5 w w J 4 C~ O Interp Final_Ca Gyrodata AK1007G_549 DEFINITIVE I I - B L M TTOM HO CATED :9930.0 E n 1000 20 00 30 00 40 00 50 00 60 00 70 00 80 00 90 00 100 00 110 00 • • MEASURED DEPTH (ft) BP Exploration (Alaska), Inc Well: G-Pad G-19A 9-5j8" Location: Nabors #7ES, Prudhoe Bay, Alaska 45 40 35 30 z O Q 25 z U Z 20 15 10 Interp Final_Ca Gyrodata - AK1007G_549 DEFINITIVE OTTOM H OCATED lE I ' ~ ~~ i ~ i 0 10 0D 20 00 30 00 40 00 50 00 60 00 70 00 80 00 90 00 100 00 ii0 00 • • MEASURED DEPTH (ft) ~~~ ~' ~lti 1 a. Well Status: ^ Oil ^ Gas ^ Plugged ®Abandoned ^ Suspended zoAACZS.TOS zoAACZS.~~o ^ GINJ ^ WINJ ^ WDSPL ^ WAG ^ Other No. of Completions Zero 1 b. Well Class: =L/li+ " ®Development ^ Exploratory ^ Service ^ Stratigraphic 2. Operator Name: BP Exploration (Alaska) Inc. 5. Date Comp., Susp., or Aban •,~ 10/10/2007 12. Permit to Drill Number 199-103 - 307-251 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Date Spudded 10/29/1999 13. API Number 50-029-21599-01-00- 4a. Location of Well (Governmental Section): Surface: ' ' 7. Date T.D. Reached 11/02/1999 14. Well Name and Number: PBU G-19A- 1535 FSL, 2276 FWL, SEC. 12, T11N, R13E, UM Top of Productive Horizon: 477' FNL, 3623' FEL, SEC. 14, T11 N, R13E, UM g KB (ft above MSL): 67.06'' Ground (ft MSL): 37.86 15. Field /Pool(s): ,, Prudhoe Bay Field / Prudhoe Bay Total Depth: 360' FNL, 2761' FEL, SEC. 14, T11 N, R13E, UM 9. Plug Back Depth (MD+ND) 12691 9007 Pool 4b. Location of We11(State Base Plane Coordinates, NAD 27): Surface: x- 657248 y- 5967883 Zone- ASP4 10. Total Depth (MD+ND) 12758 - 9008 - 16. Property Designation: ADL 028285 - TPI: x- 651394 y- 5965750 Zone- ASP4 Total Depth: x- 652252 y- 5965885 Zone- ASP4 11. SSSV DeN A(MD+ND) 17. Land Use Permit: 18. Directional Survey ^ Yes ~ No Submit electroni and rinted inf rmation er 20 AAC 25.0 0 19. Water depth, if offshore N/A ft MSL 20. Thickness of Permafrost (ND): 1900' (Approx.) 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): MWD, GR, ROP 22. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH MD: SETTING DEPTH ND' HOLE AMOUNT WT. PER FT. GRADE TOP BOTTOM TOP 'BOTT`OM SIZE CEMENTING RECORD PULLED 0" Insulated Con uct r urfacd 11 Surface 110' 6" 8 cu ds Concrete 13-3/8" 72# L-80 Surface 2703' Surface 2641' 17-1/2" 3808 cu ft Permafrost 9-5/8" 47# L-80 urface 105 5' Surface 8387' 12-1 /4" 575 cu ft Class 'G', 780 cu ft Class 'G' 7" 26# L-80 10341' 112 3' 8188' 88 9' -1/2" 448 cu ft CI ss' ' 2-718" 6.16# L-80 10247' 127 8' 8114' 9008' 3-3/4" 129 cu ft Class 'G' 23. Open to production or inject ion? ^ Yes ®No 2q. TUBING RECORD If Yes, list each i (MD+ND of Top & Bottom; Pe nterval open rforation Size and Number): SIZE DEPTH .SET MD PACKER SET MD 4-1/2", 12.6#, L-80 10142' - 10291' 10183' MD ND MD ND T G : 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. ~~~~ £(~~ ~Y ~~~ 3 S ~1~~ i ti+~ v~ ~ DEPTH INTERVAL MD AMOUNT & KIND OF MATERIAL USED 10210' Set EZSV 10007' P&A w/ 14.4 Bbls S z Crete & 2nd Plu w/ 7.3 Bbls 'G' 9943' Set EZSV / CIBP 9509' Set EZSV with Whipstock on Top 26. '" ' , " " PRODUCTION TEST Date First Production: Not on Production Method of Operation (Flowing, Gas Lift, etc.): N/A Date Of Test: HOUfS Tested: PRODUCTION FOR TEST PERIOD OIL-BBL: GAS-MCF: WATER-BBL: CHOKE SIZE: GAS-OIL RATIO: FIOW TUbing PreSS. CaSing PreSS: CALCULATED 24-HOUR RATE• OIL-BBL: GAS-MCF: WATER-BBL: OIL GRAVITY-API (CORK): 27. CORE DATA Conventional Core(s) Acquired? ^ Yes ®No Sidewal l Cores Ac uired? ^ Yes ®No If Yes to either question, list formations and intervals cored (MD+ND of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical resultr 20 AACp250.071. None ~~ I~)~I ~ 2D~i /D~/~O STATE OF ALA KA ~/'~ '~ ~~~~~~~~ s ALASKA 01L AND GAS CONSERVATION COMMISSION NQ~/ 0 6 2007 WELL COMPLETION OR RECOMPLETION REPORT AND LOG aiaska {Iil & Gas Cans. Comr~~~~ Form 10-407 Revised 02/2007 CONTINUED ON REVERSE SIDE r. 2S. GEOLOGIC MARKERS (LIST ALL FORMATIONS AND RKERS ENCOUNTERED): 29. ~ FORMATION TESTS NAME MD TVD Well Tested? ^ Yes ®No Permafrost Top If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, and submit Permafrost Base detailed test information per 20 AAC 25.071. 21N 11372' 8932' None 21 P 11378' 8935' 14N / 14P 11424' 8956' 13N 11975' 8991' 13P 12167' 9006' Formation at Total Depth (Name): 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram 31. I hereby certify that the foregoi g is true and correct to the best of my knowledge. Si d t (l ~~°l gne ~ Terrie Hubble Title Drilling Technologist Date PBU G-19A 199-103 307-251 Prepared By NameMumber. Terrie Hubble, 564-4628 Well Number Permit No. / A royal No. Drilling Engineer: Ron Phillips, 564-5913 ~N$TRUCTION$ GeNeRA~: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. IreM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. IreM 4b: TPI (Top of Producing Interval). IreM 8: The Kelly Bushing and Ground Level elevation in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. IreM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). IreM 20: Report true vertical thickness of permafrost in Box 20. Provide MD and ND for the top and base of permafrost in Box 28. IreM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. IreM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). IreM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). IreM 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. IreM 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 02/2007 Submit Original ONy • $P EXPLORATION Page 1 of 31 Operations Summalry Report Legal Well Name: G-19 Common Well Name: G-19 ~~ `\1g Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date ,From - To (Hours I Task I Code, NPT , Phase , Description of Operations 9/13/2007 { 17:00 - 00:00 { 7.00 {MOB I P 9(14(2007 , 04:00 - 08:00 I 4.00 ~ MOB I P 08:00 - 09:00 ` 1.00 ~ MOB I P 09:00 - 09:30 I 0.50 MOB P 09:30 - 12:00 I 2.501 MOB I P 12:00 - 12:30 0.50 MOB P 12:30 - 13:30 1.00 RIGU P 13:30 - 14:30 1.00 DHEOP P 14:30 - 16:00 1.50 DHB P 16:00 - 17:00 { 1.00 I DHB I P 17:00 - 18:30 I 1.50 { WHSUR { P 18:30 - 22:00 3.50 BOPSU P 22:00 - 23:00 1.00 BOPSU P 23:00 - 00:00 1.00 BOPSU P { 9(15/2007 {00:00 - 05:00 I 5.001 BOPSUF~ P PRE Stage sub on N-Pad Move satelitte camp, truck shop, and pit module from N-Pad to G-Pad Move Rig from N-Pad to G-Pad PRE Move rig sub from N-Pad to G-Pad PRE Prepare location for rig -Remove tree scalfold, set mats for sub base, and spread herculite Spot sub and pits Berm sub and cuttings box PRE Make up service lines from pits to rig PRE PJSM with hands Inspect Derrick Raise Derrick PRE PJSM with hands Bridle down Hang Bridle lines Raise Cattle Chute Rig up Rig floor PRE Rig accepted @ 12:00 Continue Rig up and fill pits with 9.8 ppg brine PRE Pre Spud meeting with Well Site Leader, Toolpusher, Mud Man, and Crew. DECOMP Cameron pump down control lines to verify SSSV is pulled DECOMP PJSM with hands and OSM Ri up Lubricator Test Lubricator to 3,500 psi for 5 min Pu B Tubing static, IA - 0 psi, OA -vac DECOMP Make up TWC valve Rig up Lubricator and test to 3,500 psi for 5 min et Test TWC to 1,000 psi from above for 5 min DECOMP PJSM with hands Nipple down tree Inspect hanger threads, threads damaged Mobilize 4 1/2" testjoint with donut ring OECOMP Nipple up BOPs Install riser DECOMP Rig up to test BOP DECOMP BOP test 250 psi low, 3,500 psi high_ AOGCC witness of test waived by Lou Grimaldi, test witnessed by Joey LeBlanc WSL and Biff Perry NTP Test #1 -Choke valves 1, 2, 3, Blind rams, Manual Kill, Dart valve DECOMP Test #2 -Choke 4,5,6, TIW, HCR Kill i Test #3 -Choke 7,8,9 Test #4 -Super Choke, Manual Choke Test #5 -Choke 10, 11, 15, Upper IBOP Test #6 -Choke 12, 13, Manual IBOP Test #7 -Upper Pipe Rams (Var - 3 112"-6"~, Choke 14 Test #8 -HCR Choke Test #9 -Manual Choke, Annular Accumulator test Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION '-Page 2 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6!1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date ~ From - To ~ Hours ~ Task ~ Code ~ NPT ~ Phase 9/15/2007 100:00 - 05:00 I 5.001 BOPSUR P 05:00 - 05:30 0.50 05:30 - 07:00 1.50 07:00 - 08:30 I 1.50 08:30 - 09:30 I 1.001 PULL I P 09:30 - 11:30 I 2.001 PULL I P 12:00 - 13:030 10.501 PULL ~ P 13:30 - 16:00 1 2.50) PULL I P 16:00 - 22:00 I 6.00! PULL I P 22:00 - 00:00 I 2.001 PULL I P Description of Operations DECOMP Initial 2,980 psi Function valves - 1,750 psi Recover to 200 psi - 14 sec Full Recovery 1 min 16 sec Avg Nitrogen in 5 bottles 1,825 psi DECOMP Rig down BOP test equipment DECOMP PJSM with DSM and crew Rig up Lubricator with doughnut extension IA = 0 psi DECOMP Pressure test Lubricator to 3500 osi for 5 r P P P Pull TWC, tubing on vac. start filling the hole and RD lubricator and extension. Hole took 26 bbls to fill tubing. Check IA for pressure 0 psi on gauge, open IA to bleed tank, fluid level dropping in tubing, took 8 bbls to fluid pack IA. total 34 bbls to fill the well. DECOMP Monitor well -initial static loss rate loss rate 3 bbls/hr for first half hour, diminishing to static after 1 hour. Fill hole with 9.8 ppg brine Rig up 2 718" handling equipment while monitoring well DECOMP Continue monitor well, Static. Pick up multi string cutter BHA DECOMP RIH with multi string cutter and tag up at 69' DECOMP Extend knives and attempt to locate collar, no collar Tag up on collapse and pick up 2' to 67' Start cut, 270 GPM @ 2,470 psi, 50 RPM @ 1,000 ft/Ibs Confirm cut with 700 psi decrease in pressure, POH to inspect blades Monitor well DECOMP Well flowing, shut in well 4 bbl gain in pits SICP = 50 psi Consult with town Bleed through choke in 10 psi increments monitoring for pressure build, SICP = 10 psi, no pit gains, no pressure increase. DECOMP Circulate across top of well, maintain 20 psi casing pressure Monitor IA and OA, OA dead most of the time, occasional release of pressure about every 4 hours IA building pressure, bleed gas only when IA reaches 55 psi, stop bleeding when fluid is present Approximately 63 bbls displaced in well bore, of which '30 bbls was diese{ rest was gas DECOMP Circulate across top of well, maintain 20 psi casing pressure Monitor IA and OA, OA dead most of the time, occasional release of pressure about every 4 hours IA building pressure, bleed gas every 5 minutes, stop bleeding when fluid is present Approximately 85 bbls displaced 'in well bore, of which -45 bbls was diesel rest was gas OOA 13 3/8" x 20" appears to have dropped 3 inches since tubing was cut, 5 inches below top of flutes Printed: 10/25/2007 1:26:19 PM BP EXPLORATION Page 3 of 31 ~ Operations Summary Report '~, Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date 1 From - To I Hours I Task I Code I NPT I Phase 9/16/2007 100:00 - 03:00 I 3.00 I PULL I P 03:00 - 07:30 I 4.501 PULL I P 07:30 - 08:00 ( 0.501 PULL I P 08:00 - 08:40 I 0.671 PULL I P 08:40 - 12:45 I 4.081 PULL I P 12:45 - 13:00 I 0.251 PULL I P 13:00 - 00:00 I 11.001 PULL I P 19/17/2007 100:00 - 07:30 I 7.501 PULL I P Description of Operations DECOMP Circulate across top of well, maintain 20-30 psi casing pressure Monitor IA and OA, OA dead most of the time, occasional release of pressure about every 4 hours IA building pressure, bleed gas every 5 minutes, stop bleeding when fluid is present Approximately 120 bbls displaced in well bore, of which -53 bbls was diesel rest was gas OOA 13 318" x 20" static, 5 inches below top of flutes 01:30 large gas bubble migrated up, had to vent IA for 29 minutes to get rid of gas in IA and loss returns while circulating across well head momentarily DECOMP Circulate across top of well, maintain 20-30 psi casing pressure Monitor IA and OA, OA dead IA building pressure, bleed gas every 10 minutes, stop bleeding when fluid is present Approximately 164 bbls displaced in well bore, of which -94 bbls was diesel rest was gas OOA 13 3/8" x 20" static, 5 inches below top of flutes 05:00 large gas bubble migrated up, had to vent IA for 20 minutes to get rid of gas in IA and loss returns again, increased pump rate to re-gain returns. DECOMP Rig up secondary kill line to IA and test secondary kill line to 3,500 psi DECOMP Pump 9.8 ppg brine down IA and take returns from the tubing, route returns through choke and gas buster Returns were straight diesel for first 23 barrels DECOMP Pump 508 bbls 9.8 ppg brine down IA and take returns from the tubing and route through choke and gas buster Maintain 20-60 psi back pressure with choke Loss a total of 30 bbls, 14 bbls to hole, 16 bbls diesel back Total cumulative losses 194 bbls, of which 110 bbls of diesel brine slurry DECOMP Shut down pumps, monitor well -well static Open Blind rams to monitor well 26 bbl gain -shut well in and line back up on choke DECOMP Started new procedure Pump 2 BPM @ 65 psi until losses stabilize and no diesel in returns Shut pumps down and allow fluid to flow back -diesel and 9.8 ppg brine U-tube, as diesel gets closer to surface gas breaks out of diesel, this forces returns to increase beyond capability of possum belly to drain Start pumps and pump until losses stabilize and no diesel in returns repeat over and over again Total losses 109 bbls, 35 bbls to the hole, 74 bbls to diesel Cumulative losses 303 bbls of which 184 bbls was diesel DECOMP Pump 2 BPM @ 65 psi until losses stabilize and no diesel in returns Shut pumps down and allow fluid to flow back -diesel and 9.8 ppg brine U-tube, as diesel gets closer to surface gas breaks out of diesel, this forces returns to increase beyond capability of possum belly to drain Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION Page 4 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING f Rig Release: Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 9/17/2007 00:00 - 07:30 7.50 PULL P DECOMP Start pumps and pump until losses stabilize and no diesel in retums shut down cycle seems to increasing in length, possibly means situation is improving? 6 hr losses 49.5 bbls, 11.5 bbls to the hole, 37 bbls to diesel Cumulative losses 352.5 bbls of which 221 bbls was diesel 07:30 - 11:30 4.00 PULL P DECOMP Shut well in to monitor pressure build up Minutes Tubing IA Minutes Tubing IA initial 20 40 80 68 107 9 20 50 90 69 109 20 37 65 100 70 111 30 45 77 110 73 115 40 52 87 120 75 115 50 58 96 137 76 115 60 61 100 160 84 115 70 65 104 170 84 114 ii Open choke and bleed back for 25 minutes Total fluid back was 20.2 bbls, of which 14.7 was diesel 11:30 - 13:30 2.00 PULL P DECOMP Shut well in and monitor pressure build up Minutes Tubing IA Minutes Tubing IA Initial 14 5 60 20 10 10 19 10 90 20 10 30 20 10 105 20 10 Determine well is not flowing, pressure are caused by small amounts of gas breaking out of migrating diesel freeze protect 13:30 - 20:45 7.25 PULL P DECOMP Pump 2 BPM @ 65 psi to circulate out diesel 4 bbls diesel per hour till 19:00 slowed -1.5 bbls diesel per hour 20:45 - 21:15 0.50 PULL P DECOMP Shut down pumps to rig up contingency line to G-18 15 minutes after pumps down returns diminished to nothing IA pressure increased from 20 psi when pumps where shut down to 27 psi in 30 minutes 21:15 - 00:00 2.75 PULL P DECOMP Pump 2 BPM @ 65 psi to circulate out diesel - 0.5 bbls diesel per hour Slowed pump rate to 1 BPM @ 30 psi to see if diesel recovery would increase Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION Page S of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date I From - To I Hours I Task I Code' NPT, Phase I Description of Operations 9/17/2007 121:15 - 00:00 I 2.751 PULL I P 9/18/2007 100:00 - 03:00 I 3.001 PULL I P 03:00 - 04:00 1 1.001 PULL 1 P 04:00 - 04:30 0.50 PULL P 04:30 - 08:00 3.50 PULL P 08:00 - 11:30 3.50 PULL P 11:30 - 13:30 2.00 PULL P 13:30 - 14:00 I 0.501 PULL I P 14:00 - 15:30 I 1.501 PULL 1 P 15:30 - 18:00 I 2.50J BOPSUF~ P 18:00 - 20:00 2.00 EVAL P 20:00 - 21:30 1.50 EVAL P 21:30 - 23:00 1.50 FISH P DECOMP No noticeable increase, only a trace of diesel in retums 24 hr losses 175 bbls, 79 bbls to hole and 96 bbls was diesel Cumulative losses 478 bbls, 198 bbls to hole and 280 bbls was diesel DECOMP Pump 1 BPM @ 30 psi to circulate out diesel Avg '3 bbls diesel per hour Trace of diesel in returns for 1 hour 3 hr losses 14 bbls, 5 bbls to hole and 9 bbls of diesel recovered Cumulative losses 492 bbls, 203 bbls to hole and 289 bbls of diesel recovered DECOMP Monitor returns from Gas Buster for 1 hour, no fluid back IA dropped from 20 psi to 10 psi after 1 hour Bleed IA to bleed trailer, short release of pressure and then dead Fill hole, took 4 strokes to get retums - 0.3 bbls Open blinds rams and monitor well DECOMP Fill riser to flow line Monitor well for 30 minutes, lost 1/2 bbl DECOMP Line up hole fill and monitor static losses Static loss rate @ 1.8 bbls/hr DECOMP Reverse circulate, monitor returns for diesel 2 BPM @ 65 psi DECOMP Monitor well and mobilize Camco for control line and Cameron for Tubing hanger Static loss rate 2.25 bbls/hr RU control line spooler RU tubing handling equipment DECOMP PJSM with Baker Make up Fishing Spear BHA Engage grapple in hanger Pull Hanger, 5K Ibs to unseat hanger DECOMP Lay down Spear BHA Monitor well, static loss rate @ 2.25 bbls/hr Lay down hanger Cut off joint (40.18'), 1 -Control line clamp with pin, and 40' of control line DECOMP Rig up to test BOP, upper rams and annular with 4" test joint, Blinds, and Lower rams with both 4" and 4.5" test joints. Low test pressure 250 psi, high 3,500 psi. DECOMP Monitor well, allow fluid level to drop below problematic area to run camera DECOMP PJSM with Haliburton Rig up wireline unit Run in the hole with downhofe camera Identify control line and control line clamp sitting at 68' DECOMP Mobilize Baker Rope Spear PJSM with hands Pickup BHA Run in hole to 75', rotate, pull out of hole Recovered 22' of control line and 1 control line clamp with pin Run in hole to 79', rotate, pull out of hole Nothing recovered Printed: 10/25!2007 1:26:19 PM BP EXPLORATION Page 6 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 , Event Name: REENTER+COMPLETE Start: Contractor Name: NABORS ALASKA DRILLING t Rig Release: Rig Name: NABORS 7ES Rig Number: Date ~ From - To ~ Hours ~ Task ~ Code ~ NPT I Phase 19/18/2007 i 23:00 - 00:00 I 1.001 EVAL I P 19/19/2007 100:00 - 02:00 I 2.00 I EVAL I P 02:00 - 09:30 l 7.501 EVAL ! P 09:30 - 10:00 I 0.501 FISH I P 10:00 - 12:00 I 2.001 FISH I P 12:00 - 13:00 I 1.001 F{SH 1 P 13:00 - 21:00 I 8.001 DHB I P 21:00 - 22:30 I 1.501 DHB I P 22:30 - 00:00 I 1.501 DHB I P 19/20/2007 100:00 - 00:30 I 0.501 DHB I P 00:30 - 05:30 I 5.001 DHB I P 05:30 - 07:00 ~ 1.501 DHB ( P 07:00 - 10:00 3.00 FISH P Spud Date: 6/6/1986 9/13/2007 End: Description of Operations DECOMP Run in the hole with downhole camera Identified collapsed 9 518" casing from 69' to top of tubing stump at 75' Run inside 4 1/2" tubing, collapsed 3' from top of tubing stump DECOMP Discuss camera video results showing collapsed 9 5/8" casing with town team and plan forward Rig down Haliburton camera wireline unit DECOMP Line up on hole fill and monitor losses Static losses average 2 bbls/hr DECOMP Make up 6.25" sub on bottom of drill pipe, run in hole 6.25" tagged up at 71', 9 5/8" collapsed casing ID smaller Pull out of hole and fay down 6.25" sub Run in hole with drill pipe, tool joint OD = Taq top of tubing stump at 76' DECOMP I Make up Spear assembly Run in hole to top of tubing stump at 76' Engage spear in fish Pull 50 Klbs, slack off to 30 Klbs, rotate 12 turns to the left, joint backed out and weight dropped off to 15 Klbs, calculated tubing length -1 000' based on 15 Klbs string weiahL DECOMP Pull out of hole to collapsed joint of tubing Lay down 2' of cut joint and collapsed joint of tubing (14.5' of joint was collapsed) ~< C,~ ~ C rc `~ v~ ~' ~~ e DECOMP Mobilize Schlumberger E-line PJSM -Rig up Big Mac (7.062" ID valve to test lubricator) while waiting on Schlumberger Average loss rate of 1.7 bbls/hr DECOMP PJSM with crew and Schlumberger Rig up E-line lubricator, BOP, and pack off Test to 1000 psi DECOMP Run in hole with gauge ring, junk basket, and collar locator Last collar located at 1,056' Tagged tubing stump at 1,165' Multiple attempts to enter tubing failed DECOMP Crew change for Rig and Schlumberger PJSM with new rig crew and Schlumberger Inspect rig up for E-sine well control Mobilize swage and lead impression block DECOMP Pull out of hole with gauge ring junk basket Inspect bottom, no identifiable marks on bottom of junk basket Rig up lead impression block (3.5" OD), and centralizer (3.70" OD), run in hole Tag up on tubing stump at 1,165', pick up and drop 4' Pull out of hole and inspect impression block Half moon from pin of tubing in the center of lead block Pick up tapered centralizer 3.70" OD and run in hole Tag up on tubing stump at 1,165', multiple attempts to enter tubing failed Pull out of hole and rig down Schlumberger E-line DECOMP Rig up 4.5" tubing handling equipment DECOMP Run in the hole with 116' of 4.5" tubing to tag the top of 4.5" Printed: 10/25/2007 1:26:19 PM • ~ BP EXPLORATION Page 7 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 19!20/2007 07:00 - 10:00 3.00 FISH P DECOMP tubing stump at 1,165' while pumping down tubing at 2 BPM - 30 psi Tag top of tubing and rotate slowly 1 tum to the left, no noticeable change in weight or pressure Pick up 2', set back down on 4.5" tubing stump and rotate 1/4 turn to the right, positive indication box fell over pin on weight _ indicator and pressure increased to 90 psi 10:00 - 12:30 I 2.501 DHB I P 12:30 - 17:30 I 5.001 DHB I P 17:30 - 18:30 I 1.001 DHB I P 18:30 - 00:00 I 5.501 DHB 1 P 19!21/2007 100:00 - 06:30 I 6.501 DHB I P 06:30 - 07:30 I 1.00 I DHB ~ P 07:30 - 09:30 2.00 DHB P Shut down pumps and remove pup joint to space out for wireline rig up DECOMP PJSM with Schlumberger E-line hands Rig up Big Mac (7.062" ID valve to test lubricator), E-line lubricator, SOP, and pack off, test to 1000 psi DECOMP Run in hole with 3.70" gauge ring, junk basket, and collar locator No problems passin 1,165' tubing reconnect joint or 2,070' S SV nipple, run down to 10,228' Pull out of hole with out any problems, 1 - 12 oz cup of plastic pipe coating in junk basket DEGOMP Run in hole with EZSV 3.66" OD Tag up at 192' Work multiple times but could not get past 204' Looked like EZSV was pushing something ahead of it Pull out of hole, bottom of EZSV was full of paraffin and plastic pipe coating DECOMP Run in hole with second 3.70" OD gauge ring, junk basket, and collar locator Tagged up at 204', work up and down twice and was able to get past 204' Run in hole to 10,228' without any problems Pull out of hole, stuck at 500', work junk basket down to get free, pull out of hole and inspect junk basket Junk basket full of paraffin and some plastic pipe coating Run in hole to 3,000' with 3.70" OD gauge ring, junk basket, and collar locator DECOMP Pull out of hole with 3.70" OD gauge ring, junk basket, and collar locator Junk basket full of paraffin Run in hole with 4 1/2" EZSV (3.66" OD) Start taking weight from 340' - 400', slump on wireline and wait for EZSV to fall Run in hole fine from 500' to 10,230', identify completion equipment from Sliding sleeve to the "X" Nipple Re-log pulling up from "X" Nipple to Sliding sleeve, run in hole to 10,230' Pull up to position top of EZSV at 10,210', Set top of EZSV at 10,210', Positive indication EZSV fired by decrease in tension, wait 3 minutes and stack tools on EZSV to confirm set Pull out of hole Break Schlumberger Lubricator and stand off to side Fill 4 1/2" tubing, shut down hole fill and monitor fluid levels in 4 1/2" tubing and 9 5/8" IA DECOMP Monitor well for losses, losses at 0.5 bbls/hr DECOMP Rig down Schlumberger Lubricator Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION Page 8 of 31 'Operations Summary Repolrt (Legal Well Name: G-19 Common Well Name: G-19 Event Name: REENTER+COMPLETE Start: Contractor Name: NABORS ALASKA DRILLING 1 Rig Release: Rig Name: NABORS 7ES Rig Number: Date ~ From - To ~ Hours ~ Task ~ Code ~ NPT ~ Phase 9121/2007 1104:00 - 16:00 I 2.001 DHB I P 16:00 - 18:00 I 2.00 18:00 - 00:00 I 6.00 9122/2007 100:00 - 12:00 I 12.00 12:00 - 13:00 I 1.00 13:00 - 14:00 I 1.00 14:00 - 18:00 I 4.00 18:00 - 19:30 I 1.50 19:30 - 20:30 1 1.00 20:30 - 22:00 I 1.50 Mud Push 2.2 bbls 1 BPM 2,050 psi 14.0 PPG Squeeze Crete 14.4 bbls 1 BPM 1,360 psi Mud Push 2.0 bbls 1 BPM 1,309 psi 9.8 ppg Brine 40.5 bbts 1 BPM 1,670 psi Spud Date: 6/6/1986 9/13/2007 End: Description of Operations DECOMP Monitor well for losses, losses at 0.5 bbls/hr DECOMP Pick up Baker internal multi string cutter Cut 4 112" cubing just above lower pipe rams, 19.5' Lay down cutter, 5.80' pup, and cut joint 13.58' DECOMP PJSM with Haliburton, Baker, and crew Rig up 2 7/8" PAC running equipment Pick up Haliburton stinger for EZSV DECOMP Run in the hole with 2 7/8" PAC drill pipe from surface to 3,000' picking up singles out of the pipeshed Stop and circulate 104 degree 9.8 brine at first HTPAC joint of drill pipe and 3,000' 1,600' 4 bbls 1 bbllmin 130 psi 3,000' 22 bbls 2 bbl/min 595 psi Paraffin in returns, dump to cuttings box DECOMP RIH with 2 7/8" HTPAC drill pipe from 3,000' to 10,142' picking up singles out of the pipeshed Stop and circulate bottoms up with 104 degree 9.8 ppg brine at 6,000' and 9,000' 6,024' 92 bbls 3 bbl/min - 2,200 psi, fluid was out of balance, U-tubing after first bottoms up, circulate bottoms up x2 9,021' 78 bbls 2 bbl/min - 1,355 psi, 3 bbl/min - 2,933 psi DECOMP Rig up to pump Wash down from 10,142' to EZSV Tag EZSV at 10,210' 2 BPM - 1,537 psi OECOMP Lay down joint of HTPAC drill pipe and space out string for cementing DECOMP Circulate 9.8 ppg brine while waiting on cement results from Lab 2 BPM - 1,537 psi 3 BPM - 3,100 psi DECOMP Rig up Schlumberger Cementers PJSM with Schlumberger, Halliburton, and crew Pressure test lines to 5,000 psi DECOMP Run in hole to 10,210', sting into EZSV past "O"ring seal but left the valve closed to test seal Seal tested good, slack off and apply 10 Klbs on stinger Switch over to Schlumberger for injection test 0.5 BPM - 1,450 psi 1.0 BPM - 2,100 psi, staging up to 1 BPM break over was at 2,600 psi Inject 43.7 bbls of 9.8 ppg brine while waiting on 14.0 ppg Squeeze Crete Cement to be batch mixed Batching started at 19:50 DECOMP Switch on the fly to start cement job Phase Vol Rate Pressure Printed: 10/25/21107 1:26:19 PM BP EXPLORATION Operations Summary Report Page 9 of 31 Legal Well Name: G-19 Common We11 Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 9/22/2007 20:30 - 22:00 1.50 REMCM P DECOMP Displacement left 1.0 bbls of cement in the 2 7/8" drill pipe and 2.0 bbls of Mud Push 22:00 - 22:30 0.50 REMCM P 22:30 - 23:30 1.00 REMCM P 23:30 - 00:00 0.50 REMCM P 9/23!2007 00:00 - 12:00 12.00 REMCM P 12:00 - 12:30 0.50 REMCM P 12:30 - 13:30 1.00 REMCM P 13:30 - 18:00 4.50 STCTPL P 18:00 - 21:00 3.00 STCTPL P 21:00 - 22:00 1.00 STCTPL P 22:00 - 00:00 I 2.00 I STCTPL I P 19/24/2007 100:00 - 02:00 1 2.001 CLEAN i P 02:00 - 04:00 ` 2.00 I CLEAN I P 04:00 - 10:30 I 6.50 CLEAN l P Pressure started to climb as the cement crossed the first set of perfs, 1,200 psi to 1,670 psi Cement in place at 21:42 DECOMP Shut down pumps, 400 psi on drill pipe Pull out of EZSV, drill pipe pressure dropped to zero Allow cement in drill pipe to U-tube Pull out of hole, lay down 2 joints, both joints were dry DECOMP Hook up head pin and circulate bottoms up x2 159 bbls 9.8 ppg brine 3 BPM 3,130 psi 10 bbls of cement contaiminated brine back to surface, ph spike, weight increased to 11.0 ppg, and smelled like cement, dump to cuttings box DECOMP Rig down circulating equipment Rig up to lay down 2 718" HTPAC drill pipe DECOMP Pull out of hole from 10,150' to BHA laying down 2 7!8" PAC drill pipe Well static, no losses during trip out DECOMP Lay down cement stinger BHA DECOMP Rig down 2 718" handling equipment Clean and clear rig floor DEGOMP Rig up Schlumberger lubricator extension, Big Mac (7.062" ID valve to test lubricator), wireline BOP, lubricator, and pack off Test lubricator to 500 / 1000 psi DECOMP Run in hole with Schlumberger Jet cutter and collar locator on E-line to 10,100' DECOMP Log down to 10,154', lost tension on wireline, pick up and get tool movement at 10,154' To of Cement at 10 1 ' Log sliding sleeve going down, log sliding sleeve going up and correlate to EZSV run Position 'et cutter at 10 142' Fire jet cutter, positive indication on tension that jet cutter moved down hole DECOMP Pull out of hole Lay down wireline tools Jet cutter fired DECOMP Rig up 2 7/8" PAC handling equipment Pick up 4 1/2" RTTS BHA to circulate below back off at 1,165' DECOMP Run in hole with 49 joints of 2 718" PAC to 1,512' DECOMP Set RTTS Packer at 1,512' Circulate Hi Vis Sweep with red dye surface to surface 138 bbls 9.8 ppg brine pumped 2 BPM @ 3444 psi 323 bbls 9.8 ppg brine pumped 4 BPM @ 2,900 psi, gas back to surface, breaking out in bell nipple, shut down pumps and monitor well, well static, returns were 9.3 ppg brine 548 bbls 9.8 ppg brine pumped 3 BPM @ 3,055 psi, returns back to 9.8 ppg brine, no gas 625 bbls 9.8 ppg brine pumped 4 BPM @ 3,480 psi, Red dye back to surface, dump 65 bbls red brine, dye strung out in Prin[Ctl: lUl15/1UU/ 7:L0:1 `J YM • BP EXPLORATION Page 10 of 31 Operations Summary'Report 'Legal Well Name: G-19 Common Well Name: G-19 , Event Name: REENTER+COMPLETE Start: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date ~ From - To ~ Hours ~ Task ~ Code ~ NPT ~ Phase 19/24/2007 104:00 - 10:30 I 6.501 CLEAN I P 10:30 - 11:00 I 0.501 CLEAN I P 11:00 - 13:15 2.25 CLEAN P 13:15 - 14:00 I 0.751 CLEAN I P 14:00 - 14:30 0.50 CLEAN P 14:30 - 15:00 ~ 0.501 CLEAN ~ P 15:00 - 17:00 2.00 CLEAN P 17:00 - 17:30 I 0.501 CLEAN I P 17:30 - 18:15 1 0.751 STCTPL I P 18:15 - 18:45 I 0.501 STCTPL I P 18:45 - 19:30 I 0.751 STCTPL I P 19:30 - 20:00 1 0.501 STCTPL i P 20:00 - 22:00 I 2.001 STCTPLI P 22:30 - 00:00 I 10.501 BOPSULFi P 19/25/2007 100:00 - 00:45 I 0.751 BOPSUR P 00:45 - 08:30 I 7.751 BOPSURP 08:30 - 09:30 1.00 BOPSU P 09:30 - 10:00 0.50 FISH P 10:00 - 10:30 0.50 FISH P 10:30 - 12:00 1.50 FISH P Spud Date: 6/6/1986 9/13/2007 End: Description of Operations DECOMP returns Calculated 680 bbls surface to surface for cut at 10,142' and dye back at 690 bbls 9.8 ppg brine in, 9.8 ppg brine out DECOMP Monitor well, well static DECOMP Circulate bottoms up 549 bbls 9.8 ppg brine 4 BPM @ 2,878 psi 9.8 ppg brine in, 9.8 ppg brine out OA = 135 psi Fluid level in 20" x 13 3/8" = 58" DECOMP Monitor well, well static DECOMP Bleed OA down to zero and monitor during test Test 9 5/8" casing to 1000 osi for 5 min_ aaoci-test, OA = 100 psi DECOMP Monitor well, well static Rig down E-line equipment left on rig floor and clear off rig floor DECOMP Pull out of hole with RTTS from 1,512' laying down 2 7/8" PAC drill pipe in pipe shed DECOMP Lay down RTTS Pick up Multi string cutter DECOMP Run in hole to 217' with multi string cutter on 2 7/8" PAC drill pipe DECOMP Cut 4 1/2" tubing at 217' 17 GPM @ 1,550 psi DEGOMP Pull out of hole with multi string cutter Lay down cutter DECOMP Pick up Baker Spear Assembly on 4" Drill Pipe ftun in hole to 19' Spear 4 1/2" tubing Pull out of hole with fish DECOMP Lay down cut joint (28.25') with spear engaged, 3 pups, 3 joints tubing, 2nd cut joint (12.25'), 95' control line, and one control line clamp DECOMP Rig down handling equipment, clean and clear rig floor DECOMP Install test plug Change lower rams to 9 5/8" DECOMP Install 9 5/8" test joint Fill stack, choke, and test joint with water DECOMP Test BOP, Low 250 psi, High 3,500 psi #1 -Upper Rams, 4 112" test joint #2 -Upper Rams, 4" test joint, Choke valves 1, 2, 3, 16, Lower IBOP, Oart Valve #3 -Choke vavtes 4, 5, 6, HGR Kill, Manual top drive #4 -Choke valves 7, 8, 9, Floor Valve, Manual Kill #5 -Super Choke, Manual Choke #6 -Choke valves 10, 11, 15 Witnessed by: Duncan Ferguson, Joey LeBlanc BP, Lenward Toussant and Chris Weaver NAD and Jeff Jones AOGCC. DECOMP RD test equipment. Clear rig floor. DECOMP PU Baker 5-1/2" multistring cutter. DECOMP RIH to 178' MD. OECOMP Circulate 50 bbl 8.5 ppg seawater, RU lines f/OA to cuttings Panted: 10lZ52V0/ 126:1y YM • BP EXPLORATION Page 11 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 , Event Name: REENTER+COMPLETE Start: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date ~ From - To ~ Hours ~ Task l Code I NPT ~ .Phase 1 i 9/25/2007 10:30 - 12:00 1.50 FISH ~ P 12:00 - 12:30 0.50 FISH P 12:30 - 13:00 0.50 FISH P 13:00 - 15:30 I 2.50) FISH I P 15:45 - 17:00 10.251 FISH I P 17:00 - 19:00 ~ 2.00 I FISH P 19:00 - 21:00 2.00 FISH P 21:030 - 22:45 10.251 FISH I P 22:45 - 00:00 1 1.251 FISH I P 19/26/2007 100:00 - 01:30 I 1.501 FISH I P 01:30 - 02:30 I 1.00 I FISH I P 02:30 - 03:00 0.50 FISH P 03:00 - 06:00 3.00 FISH P 06:00 - 08:00 2.00 FISH P 08:00 - 09:00 1.00 FISH P 09:00 - 10:00 1.00 FISH P 10:00 - 11:00 1.00 FISH P 11:00 - 12:00 1.00 FISH P 12:00 - 13:00 1.00 FISH P 13:00 - 15:00 2.00 FISH P 15:00 - 16:00 I 1.001 FISH I P Spud Date: 6!6/1986 9!13/2007 End: Description of Operations DECOMP box. Fluid 52" below 13-3/8" x 20" fluted hanger. DECOMP Cut 9-5/8" casin at 178'. 229 gpm, 609 psi, 53 rpm, 1 K tq. DECOMP Close annular preventer. Circulate 170 gpm, 360 psi. 50 bbls 120 deg. 8.5 ppg seawater down 9-5/8" through cut at 178' in 9-518" up 13-3/8" annulus. Dead crude freeze protect fluid recovered at surface and sent to cuttings box. DECOMP PJSM. Rig up Little Red Hot Oil Svcs. Pump 20 bbls 100 deg F. diesel down 9-5/8" casing. Returns apparent up 9-5/8" x 13-3/8" annulus. Allow diesel to sit 30 mins. Circulate 120 deg. F 8.5 ppg seawater. 211 gpm, 410 psi. Pump 128 bbis total volume. DECOMP POH 8178' w/9-5/8" casing cutter and LD cutter. DECOMP MU 9-5/8" casing spear. RIH. Latch into 9-5/8" casing. Fluid returns noticed at 13-3/8" x 20" annulus. 10 gals. crude oil released into secondary containment herculite berm in cellar. Cleaned up w/adsorb. Notified BP non emergency spill department # 5700. Drain fluid f/BOP stack and flow ceased f/20". DECOMP Unlatch spear. POH. Monitor 13-3l8" x 20" annulus. Static. DECOMP RIH w/ 9-5/8" spear and latch casing. Back off lock down screws. Pull oackoff up 7' w/25K overoull. No further upward ,movement possible after 7'. PuII to 75K wino movement. Consult w/town team. DECOMP POH. LD casing spear. DECOMP MU &RIH w/casing cutter. Cut 9-5/8" casing at 52'. 191 gpm, 820 psi, 60 rpm, 1K tq. POH and lay down casing cutter. DECOMP MU 9-5/8" casing spear, RIH 21' and latch casing. Pull to 75K. Not free. POH and lay down spear. Prepare to rerun casing cutter. DECOMP MU & RIH w/casing cutter. Re-cut 9-5/8" casino at 52'. 190 gpm, 820 psi, 60 rpm, 1 K tq. POH and lay down casing cutter. DECOMP POH w/9-5/8" casing f/52' to surface. LD 32' of 9-518" casing. DECOMP MU and RIH w/9-5/8" spear, bumper sub, and two 6.5" drill collars. DECOMP Engage spear in 9-518" casing at 52'. Jar down w/bumper sub and free casing. Tag up 7.5' below stuck point on top of cut at 178' as expected. PU and pull back up through tight spot w/9-5/8". Work pipe up through tight spot. Pull over to 100K on indicator briefly and work pipe to surface w/spear. Casing collapsed immediately below 1st collar pulled above floor. DECOMP RU and LD 9.92' top cut off stub, 1 collapsed jt, 2 jts, and a 32' bottom cut off stub. Top of 9 5/8" stub at 178' DECOMP Clear floor, service top drive and rig. DECOMP Monitor well. Consult w/town team on plan forward. DECOMP RU and RIH w/BHA #13 to spear 4.5" tubing. DECOMP Engage fish w/spear and POH w/4.5" tubing. PU = 40K. DECOMP RU to LD 4.5" tubing. DECOMP LD 28.45' top cut off stub, 22 jts of 4.5" tubing, total of 917.61' laid down. 917.61' + 217' f/previous cut =top of 4.5" tubing at 1164.61'. Note: Pin up on tubing remaining in hole. Laid down additional control line and 12 clamps. DECOMP RD tubing handling equipment. Clear rig floor. Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION Page 12of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date I From - To I Hours I Task ~ Code I NPT ~ Phase I Description of Operations 9/26/2007 122:00 - 00:00 I 2.00 I FISH ~ P 19/27/2007 100:00 - 03:00 I 3.001 FISH I P 03:00 - 04:30 I 1.501 FISH I P 04:30 - 06:00 1.50 FISH 1 P 06:00 - 12:00 6.00 FISH P 12:00 - 16:00 4.00 FISH P 16:00 - 17:00 1.00 FISH P 17:00 - 19:30 2.50 FISH P 19:30 - 20:30 1.00 FISH P 20:30 - 21:00 0.50 FISH P 21:00 - 00:00 3.00 FISH P 9(28(2007 100:00 - 00:30 I 0.501 FISH I P 00:30 - 02:30 2.00 FISH P 02:30 - 03:00 0.50 FISH P 03:00 - 03:30 0.50 FISH P 03:30 - 05:30 2.00 FISH P 05:30 - 06:30 1.00 FISH P 06:30 - 07:00 0.50 FISH P 07:00 - 09:30 2.50 FISH P 09:30 - 11:00 1.50 FISH P 11:00 - 12:30 1.50 FISH P 12:30 - 13:30 1.00 FISH P 13:30 - 15:00 1.50 FISH N 15:00 - 16:30 I 1.50 ~ FISH I P 16:30 - 18:15 1.75 FISH P 18:15 - 20:00 ~ 1.751 FISH I P DECOMP MU 10.75" swaging BHA # 15. DECOMP Work swage through tight spot in 13-3/8" f/69' to 80' several times. Use bumper subs to drive through obstruction each time. Pull up to 100K to pull back through. Trip jars as required when pulling back through tight spot. Broke hydraulic fitting on top drive. Repair line. DECOMP Work 10.75" OD swage through tight spot in 13 3/8" casing f/69' to 80'. No change in up down weight requirements to work swedge down and back through. DECOMP LD 10.75" OD swage and PU 11.50" OD swedge. DECOMP Swage tight spot between 69' and 80' w/11.25" OD swedge. DECOMP Spot tube pill across tight spot. Swedge between 69' and 82'. No change 50K overpull to bring swedge through tight spot. DEGOMP PJSM. Replace IBOP damaged by jarring activities. Test Power IBOP 250/3000 psi. DECOMP Inspect derrick and top drive. DECOMP Work 11.5" swedge through tight spot between 69' and 82'. DECOMP LD 11.5" swedge and PU 12.125" swedge. 11.5" swedge still gage. DECOMP RIH to 68' wl12.125" swedge and spot {ube pill around swedge. DECOMP Run 12.125" swedge and work tight spot between 69' and 82' several times. This swedge worked through more easily than past smaller swedges. RIH to 100' w/no resistance. Still 50K PU to pull swedge through tight spot. DECOMP Run 12.125" swedge through tight spot in 13-318" casing between 69' and 82'. DECOMP LD 12.125" swedge and BHA #17. DECOMP Clear rig floor and bring 1.125" OD dress-off shoe and washpipe assy for 9 5/8" casing to floor. DECOMP Service topdrive and rig. DECOMP Pick up 12.125" OD Dress-off shoe for 9-518" stub. BHA #18. DECOMP RIH BHA # 18 w/12.125" OD shoe w/11.75" washpipe and inner mill to dress top of 9-5/8" stub. DECOMP Dress top of 9-518" casing stub at 178' to accept temporary casing patch overshot. DECOMP POH and LD BHA # 18. DECOMP RU to run 9-518" temporary overshot casing patch and 9-5/8" 47# L-80 BTC casing f/178' to surface and land using lower pipe rams as temporary packoff. DECOMP Run BHA #19. 11.125" OD overshot assy. to 178'. Engage 9-5/8" and ull check w/25K over trin DECOMP RD casing handling equipment. RREP DECOMP (NPT not chargeable to rig.) Topdrive. Bolts sheared on top of IBOP actuator due to jarring while swaging. Replace ring and bolts. Test upper and manual IBOPs 250/3000 psi low/high pressure. DECOMP MU BHA #20. 4.5" tubing overshot assy. DECOMP RIH picking up 4" HT40 drill pipe 1 x 1 to 1165'. Engage 4.5" tubing w/overshot and grapple. Pull over string wt. 25K to 175K and pull free. DECOMP Circulate 20 bbls Safe-Solt' and 30 bbls Safe-Surf O around Printed: iorz~zoui i:ze:ia Pra • BP EXPLORATION Page 13 of 31 Operations Summail•y Report 'Legal Well Name: G-19 iCommon Weli Name: G-19 Spud Date: 6/6!1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: !,Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date I From - To I Hours I Task I Code I NPT I Phase Description of Operations 912812007 18:15 - 20:00 1.75 FISH P DECOMP w/9.8 ppg brine. 490 gpm, 1175 psi. Pump 781 bbls. 20:00 - 22:00 2.00 FISH P DECOMP POH. LD 4.5" tubing overshot/grapple BHA # 20. 22:00 - 00:00 2.00 FISH P DECOMP POH laying down 4.5" 12.6# L-80 Buttress tubing 1 x 1. 912912007 00:00 - 05:00 5.00 FISH P DECOMP Continue POH laying down 4.5" 12.6 # L-80 Buttress tubing. Lay down 219 jts, 1 SSSV w/pups, 1 sliding sleeve w/pups, 1 cut off stub 17.08' w/clean jet cut. Retrieved 11 rubber clamps, 2 stainless steel bands and 1000' control line. 05:00 - 06:30 1.50 FISH P DECOMP RD 4.5" tubing handling equipment and clear rig floor. 06:30 - 07:30 1.00 CLEAN P DECOMP PU 8.5" bit and 9-5/8" casing scraper BHA #21. 07:30 - 14:00 6.50 CLEAN P DECOMP PU 4" drill i e in sin les from the i e shed and R1H to 10138' and to tubin stub. 180K PU 130K SO. 14:00 - 15:15 1.25 CLEAN P DECOMP CBU at 10137'. 460 gpm, 2530 psi. Pumped 623 bbls. 15:15 - 19:30 4.25 CLEAN P DECOMP Monitor well. BD topdrive. MW = 9.8 ppg. POH to BHA. 19:30 - 21:00 1.50 CLEAN P DECOMP LD BHA #21. Recover 1.5 gals scale from boot baskets. 21:00 - 23:45 2.75 DHB P DECOMP PU blank bottom perforated drill pipe pup and RIH picking up 4" drill pipe singles to 3351'. 23:45 - 00:00 0.25 DHB P DECOMP RIH hole w/drill pipe stands f/3351' to 4595'. 9!3012007 00:00 - 02:00 2.00 DHB P DECOMP RIH w/cementing stinger and drill pipe stands fi/4595' to 10142'. 02:00 - 04:30 04:30 - 05:30 5:30 - 07:00 2.50 1.00 .50 DHB DHB HB P P P DECOMP DECOMP ECOMP CBU and RU cement lines to spot balanced plug. RU Schlumberger cementing unit. PJSM w/Schlumberger, hands, TP and WSL. Test lines to 4000 psi. Pump 10 bbl water ahead of cement. Mix and pump 7.3 bbl class "G" cement at 15.8 ppg, 92 gpm 150 psi. Pump 1.25 bbl water, 84 gpm, 118 psi. Switch to rig pumps and displace with 95 bbl 9.8 ppg brine. 294 gpm, 800 psi. Under displace by 2 bbl. Cement in place at 05:15. POH 100' slowly out of cement plug to 9980'. CBU 500 gpm, 2330 psi. Noted ph spik fat bottoms up. 07:00 - 14:00 7.00 DHB P DECOMP WOC for 1000 psi compressive strength. Service rig and top drive. Repair EZ torque pressure regulator. Cut and slip drilling line. Displace well to 8.5 ppg seawater while WOC. Rig housecleaning. 14:00 - 14:30 0.50 DHB P DECOMP RIH and find hard cement at 10005'. SO 10K on cement. POH to 9947' and circulate 20 bbls 8.5 ppg seawater to clear cement from stinger, 200 gpm 360 psi. PU 165K, SO 125K. BD topdrive. Monitor well. 14:30 - 19:00 4.50 DHB P DECOMP POH w/drill pipe f/9947' to surface. LD cementing stinger, 19:00 - 21:30 2.50 DHB N WAIT DECOMP Wait on Schlumberger Wireline unit to run 9-5/8" EZSV and USIT log. 21:30 - 23:30 2.00 DHB P DECOMP RU Schlumberger wireline unit. 23:30 - 00:00 0.50 DHB N SFAL DECOMP Mobilize Sclumberger mechanic f/Deadhorse to repair wireline unit hydraulic winch actuator pump system. 10/1/2007 00:00 - 00:30 0.50 DHB N SFAL DECOMP Continue repair actuator pump f/winch on wireline unit. 00:30 - 03:00 2.50 DHB P DECOMP RIH w/9-5/8" Halliburton EZSV w/bridging plug and log into place wltop at 9943'. Collar below at o ar a ove a 9907'. Tag cement top at 10007'. 03:00 - 04:30 1.50 DHB P DECOMP POH w/E-line running tool. LD Schlumberger E-line setting tool. 04:30 - 06:30 2.00 EVAL P DECOMP RU USIT logging equipment and RIH to 9943'. 06:30 -10:00 3.50 EVAL P DECOMP USIT. Log f/9943' to 150'. 10:00 - 11:30 1.50 EVAL P DECOMP RIH to 2300' and relog to 150' to verify top of cement. 11:30 - 12:00 0.50 EVAL P DECOMP LD USIT tool. Printed: 10/25/2007 1:26:19 PM BP EXPLORATION Page 14 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date f From - To ~ Hours ~ Task I Code I NPT I Phase' Description of Operations 10/1/2007 12:00 - 13:30 1.50 EVAL P DECOMP RU to run stringshot. 13:30 - 14:30 1.00 EVAL P DECOMP RIH and log 12' x 3 strand stringshot into place and fire across collar at 2000'. 14:30 - 15:00 0.50 EVAL P DECOMP POH and LD string shot tool. 15:00 - 17:45 2.75 EVAL P DECOMP RU Gyrodata gyro survey equipment. 17:45 - 18:30 0.75 EVAL P DECOMP Run gyro f/surface to 1000' continuous data acquisition. Gyrodata CCL failure. 18:30 - 19:30 1.00 EVAL N DFAL DECOMP POH and changeout CCL unit. 19:30 - 00:00 4.50 EVAL P DECOMP Attempt to gyro survey continuous mode f11000' to 9943'. Gyro not able to acquire data continuously. Consult w/town team and decision made to single shot survey surface to 9943'. Per Gyrodata, run single shot survey every 50' by surveying every even 100' running in hole to 9900' (5000, 5100, 5200 etc.}. PU 50' and survey ea. alternating odd 100' (5250', 5150', 5050' etc.} while POH to surface. Data acquisition OK in single shot mode. 10/2/2007 00:00 - 04:30 4.50 EVAL P DECOMP Continue to survey w/gyro in single shot mode f/9943' to surface. Perform rig preventive maintenance and housecleaning. 04:30 - 05:30 1.00 EVAL P DECOMP RD Schlumberger wireline unit/GyroData equipment and clear rig floor. 05:30 - 06:30 1.00 FISH P DECOMP PU Baker 9-5/8" multistring casing cutter BHA # 22 and RIH to 1980'. 06:30 - 08:00 1.50 F1SH P DECOMP RU to circulate to OA. Spot vac truck for cellar. PJSM wl8aker, crew, TP and WSL before cutting casing. 08:00 - 08:30 0.50 FISH P DECOMP Cut casin at 1980'. 127 gpm, 310 psi, 50 rpm, 2.5K tq. Circulate 115 bbls seawater down drill pipe, through cut, and up 13-3/8" x 9-5l8" annulus. 208 gpm, 1020 psi. 08:30 - 09:30 1.00 FISH P DECOMP Monitor well. POH to BHA. MW = 8.5 ppg seawater. 09:30 - 10:30 1.00 FISH P DECOMP LD 9-5/8" multistring cutter. MU 9-5l8" casing spear w/packoff and stab into 9-5/8" casing at surface. 10:30 - 11:30 1.00 FISH P DECOMP PU 9-5/8" and pull free w/string wt. 105K. Spot Hot Oil Svc. Hook up lines. PJSM. 11:30 - 14:30 3.00 FISH P DECOMP Test lines to 3000 psi. Circulate 120 bbls heated diesel down 9-5/8" casing to 1980 and into 9-5/8" x 13-3/8" annulus via cut in 9-5/8". 5 bpm, 800 psi. Displace w/145 bbl 100 deg. 8.5 ppg seawater w/Safe Surf O, 235 gpm, 20 psi. SD and allow diesel to soak f/30 min. in annulus. Circulate annulus clean w/219 bbls 8.5 ppg 100 deg seawater at 235 gpm, 137 psi. 14:30 - 15:00 0.50 FISH P DECOMP Pull casing to floor w/105K PU wt. and LD spear. 15:00 - 19:30 4.50 FISH P DECOMP Id 4 jts 9-5/8" BTC casing and casing patch overshot w/5.75' cut off stub, 50 jts. of 9-5l8" NSCC casing wl18.38' cut off stub on bottom. 10 turbolators on jts. 19:30 - 20:15 0.75 FISH P DECOMP RD casing equipment and clear floor. 20:15 - 21:00 0.75 BOPSU P DECOMP RU to test BOP. 21:00 - 00:00 3.00 BOPSU P DECOMP Test BOP to 250 si/3500 si low/hi h ressure. Test witnessed by Lenward Toussant NAD TP and Lowell Anderson BP WSL. AOGCC rep Lew Grimaldi waived AOGCC presence attest. 10/3/2007 00:00 - 01:30 1.50 BOPSU P DECOMP Continue BOP test. 01:30 - 02:00 0.50 BOPSU P DECOMP RD test equipment and clear floor. 02:00 - 03:00 1.00 FISH P DECOMP PU 11-3f4" washpipe/washover shoe BHA# 24. 03:00 - 05:00 2.00 FISH P DECOMP RIH and wash down over stub and collar at 2000'. 300 gpm, t'rintea: iuizaluui i:~ti:~a rnn • BP EXPLORATION Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Event Name: REENTER+COMPLETE Contractor Name: NABORS ALASKA DRILLING I Rig Name: NABORS 7ES Date ~ From - To 1 Hours ~ Task 1 Code ~ NPT 10/3/2007 ~ 05:00 - 06:030 I 1.50 ~ FISH I P 06:30 - 07:00 0.50 F1SH P 07:00 - 08:00 1.00 FISH P 08:00 - 08:30 0.50 FISH P 08:30 - 09:30 1.00 FISH P 09:30 - 10:30 1.00 FISH P 10:30 - 11:30 1.00 FISH P 11:30 - 12:00 0.50 FISH P 12:00 - 13:45 1.75 FISH P 13:45 - 16:00 2.251 FISH P 16:00 - 16:30 0.50 FISH P 16:30 - 16:45 I 0.251 FISH I P 16:45 - 17:45 1.00 FISH P 17:45 - 19:00 1.25 FISH P 19:00 - 20:15 1.25 FISH P 20:15 - 21:00 0.75 FISH P 21:00 - 21:45 0.75 FISH P 21:45 - 22:00 0.25 FISH P 22:00 - 23:00 1.00 FISH P 23:00 - 23:30 0.50 FISH P 23:30 - 00:00 0.50 FISH P 10/4/2007 00:00 - 02:00 2.00 FISH P 02:00 - 03:00 1.00 FISH P 03:00 - 03:30 0.50 FISH P 03:30 - 04:00 0.50 FISH P 04:00 - 04:30 0.50 FISH P 04:30 - 05:00 0.50 FISH P 05:00 - 05:30 0.50 FISH P 05:30 - 06:30 1.00 FISH P Start: 9/13/2007 Rig Release: Rig Number: Phase .Page 15 of 31 Spud Date: 6/6/1986 End: Description of Operations DECOMP 225 psi. DECOMP CBU. 300 gpm, 225 psi., 50 rpm, 2K tq. PU 70K, SO 68K, ROT 70K. DECOMP POH to BHA#24. MW = 8.5 ppg. DECOMP Stand back collars and LD washover BHA # 24. Found 3 centralizer inside of washpipe. DECOMP Clean and clear floor. DECOMP PU cleanout BHA# 25 w/8.5" bit. DECOMP RIH to stub at 1980'. Took 2K wt to enter 9-5/8" stub. RIH past stub to 2500'. PU 78K SO 78K. DECOMP POH to BHA. Stand back drill collars. DECOMP LD BHA # 25. DECOMP PU 8" Backoff Tool BHA #26 w/muleshoe on drill collars below backoff tool. DECOMP RIH w/drill pipe filling ea. stand. DECOMP RIH. Drill collars entered 9-5/8" stub. Lower anchor on back off tool would not enter 9-5/8" at 1980'. SO 10K on tools and attempt to rotate w/20 rpm, 1.5K tq. DECOMP Drop ball/rod and circulate to seat in pump out sub. Blow seat out at and circulate drill pipe volume 8.5 ppg seawater. BD topdrive. DECOMP Monitor well. POH to BHA. MW = 8.5 ppg. DECOMP LD Backoff Tool BHA #26. Stand back 3 stands of drill coNars. DECOMP MU tapered mill/string mill BHA #27. DECOMP RIH w/4" drill pipe to 1970'. DECOMP Enter 9-5/8" w/no problem. Run mills up and back f/1980' to 1985'. 80 rpm, 1 K tq, 262 gpm, 167 psi, 75K PU, 73K SO, 75K ROT. DECOMP RIH f/1980' to 2510'. No obstructions seen. DECOMP POH to BHA. DECOMP Stand back drill collars. LD tapered/string mill BHA #27. DECOMP MU 8" Rackoff Tool BHA #28. DECOMP RIH w/Backoff Tool BHA #28 to 1980'. DECOMP Position backoff tool across collar at 2000'. Actuate backoff tool. 1st break at 2000 psi. 3/4 of a tum. Cycle tool 8 more times w/average pressure of 800 psi for a total of 5 complete rotations at the casing collar. On last actuation pressure increased to 1200 psi. Drop ball/rod to circ sub. Circulate ball to seat. Blow out seat at 1400 psi. Circulate string volume w/8.5 ppg seawater. DECOMP POH w/BHA #28. DECOMP LD Rackoff Tool BHA #28. DECOMP PU Spear BHA #29. DECOMP RIH wlSpear. DECOMP Engage fish w/spear. DECOMP Attempt to complete backoff. Tq. = 9K. Work pipe. PU 60K, SO 60K. No rotation possible. Release spear. 06:30 - 07:30 1.00 FISH P DECOMP CBU x 2. 440 gpm, 430 psi. Monitor well. BD topdrive. 07:30 - 08:00 0.50 FISH P DECOMP POH w/Spear BHA #29. MW = 8.5 ppg. 08:00 - 08:30 0.50 FISH P DECOMP LD BHA #29. 08:30 - 10:00 1.50 FISH P DECOMP PU 11.75" Washpipe BHA #30. 10:00 - 11:30 1.50 FISH P DECOMP RIH to 1840'. Printed: 10/25/2007 1:26:19 PM • • BP EXPLORATION Operations Summary Report Legal Well Name: G-19 (Common Well Name: G-19 , Event Name: REENTER+COMPLETE Start: 9/13/2007 Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date I From - To I Hours { Task I Code I NPT {Phase 1014!2007 11:30 - 12:00 0.50 F1SH P 12:00 - 12:45 0.75 FISH P 12:45 - 13:00 0.25 FISH P 13:00 - 14:30 1.50 FISH P 14:30 - 16:00 I 1.501 FISH 1 P 16:00 - 17:00 1.00 FISH P 17:00 - 19:30 2.50 FISH P 19:30 - 21:00 1.50 FISH P 21:00 - 22:30 1.50 FISH P 110/5/2007 ~ 00:00 - 00:30 ~ 0.501 FISH I P 00:30 - 01:00 I 0.501 FISH I P 01:00 - 01:30 0.50 FISH P 01:30 - 02:45 l 1.251 FISH I P 02:45 - 03:45 If 1.00 FISH 1 P 03:45 - 04:30 0.75 FISH P 04:30 - 05:00 I 0.501 FISH ~ P 05:00 - 05:30 0.501 FISH P 05:30 - 07:00 1.50 FISH P 07:00 - 08:30 I 1.501 FISH I P 08:30 - 10:00 1.50 FISH P 10:00 - 11:00 1.00 FISH P 11:00 - 12:00 1.00 FISH P 12:00 - 13:00 1.00 FISH P 13:00 - 14:30 1.50 FISH P 14:30 - 16:30 2.00 FISH P Page,16 of 31 Spud Date: 6/6/1986 End: Description of Operations DECOMP Cut and slip drilling line. DECOMP Service topdrive. DECOMP RIH f/1840' to 1970'. DECOMP Wash over stub at 1980', past collar at 2000', tag up slightly and wash free at 2018'. Wash past collar at 2039' to 2073'. 211 gpm, 50 rpm. PU 75K, SO 70K. DECOMP Circulate 180 vis sweep. Work pipe between 2025' and 2068', 460 gpm, 379 psi, PU 65K, SO 50K. POH to 1960'. RIH wlwashpipe f/1960' over stump at 1980' to 2068' w/out pumps. No problems. DECOMP POH to BHA. MW = 8.5 ppg. DECOMP Stand back drill collars. LD 11.75" Washpipe BHA #30. DECOMP PU 8" Backoff Tool BHA #31. DECOMP RIH wldrill pipe to 1990' w/backoff tool {ower anchor. Dri11 collars below backoff tool with 112 mu{eshoe at 2287'. No problem entering top of stub with 1/2 muleshoe and collars on bottom of back off BHA. DECOMP Attempt to RIH f/1990' w/lower anchor of backoff tool. Lower anchor would not pass 2001'. DECOMP Work pipe and attempt to pass 2001' w/back off tool lower slip. PU 75K, SO 75K. Rotate slowly and attempt to pass obstruction. Torqued up when lower anchor at 2001'. PU 2' and attempt to rotate. Torqued up again. Attempt to RIH. Tag up each time at 2001' w/lower back off tool anchor. PU w/anchor to 1990' and attempt to rotate. Still torquing up. Pull back off tool above top of 9-5/8" into 13-3/8". Drop ball/rod to circ. sub and pump open at 1500 psi. DECOMP POH to BHA. MW = 8.5 ppg. seawater. DECOMP Stand back drill collars. LD Backoff BHA #31. Junk scars on back off tool at lower anchor. DECOMP PU 8.5" ODTapered Mill/String Mill BHA #32. DECOMP RIH w/BHA #32 to top of 9-5/8" stub at 1980'. DECOMP Enter 9-5/8" w/no problems. Run mills dry f/1980' to 2500". No obstructions. POH to collar at 2000' and work mills f/1980' to 2010'. 260 gpm, 134 psi, 50 rpm, PU 70K, SO 70K, ROT 75K. See torque to 1.9K on first pass through. Work mills through area several times. Tq .5K. Pull above collar to 1980' and run through dry to 2010'. No obstructions. DECOMP POH. MW = 8.5 ppg. seawater. DECOMP Stand back drill collars. LD tapered/string mill BHA #32. DECOMP PU 8" Back Off Tool BHA #33. Replace damaged slip on backoff tool. DECOMP RIH to 2331'. DECOMP Space out Sack Off Tool across collar at 2039'. Pressure up and at 2800 psi get 1 turn to left at surface. Pressure up 5 times to average 800 psi for a total of 4 turn to Left at surface. Crop ba111rod to circ sub and shear out at 1600 psi. Circulate drill pipe volume. DECOMP Monitor well. BD topdrive. MW = 8.5 ppg seawater. POH. DECOMP Stand back drill collars. LD Back Off Tool BHA #33. DECOMP PU Bowen Itco Spear BHA #34. DECOMP RIH to 1980' and engage spear to stop collar in fish. DECOMP POH w/fish. Printed: 10/25/2007 126:19 PM • BP EXPLORATION Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Event Name: REENTER+COMPLETE Start: Contractor Name: NABORS ALASKA DRILLING I Rig Release: 'Rig Name: NABORS 7ES Rig Number: Date ~ From - To ~ Hours ~ Task ~ Code ~ NPT ~ Phase 10/5/2007 16:30 - 17:00 0.50 FISH P 17:00 - 18:00 1.00 FISH P 18:00 - 18:30 0.50 FISH P 18:30 - 20:00 1.50 FISH P 20:00 - 21:30 1.50 FISH P 21:30 - 22:00 0.50 FISH P 22:00 - 23:00 1.00 FISH P 23:00 - 23:30 0.50 FISH P 23:30 - 00:00 0.50 FISH P 10/6/2007 00:00 - 00:30 0.50 FISH P 00:30 - 01:00 0.50 FISH P 01:00 - 01:30 0.50 FISH P 01:30 - 02:30 1.00 FISH P 02:30 - 03:00 0.50 FISH P 03:00 - 03:30 0.50 FISH P 03:30 - 04:30 1.00 FISH P 04:30 - 05:00 0.50 FISH P 05:00 - 05:30 0.50 FISH P 05:30 - 06:00 0.50 FISH P 06:00 - 07:00 1.00 FISH P 07:00 - 08:30 1.50 FISH P 08:30 - 09:00 0.50 FISH P 09:00 - 10:00 1.00 CASE P 10:00 - 17:30 7.50 CASE P 17:30 - 19:00 1.50 CASE P 19:00 - 21:00 2.00 CASE P 21:00 - 23:30 2.50 CASE P 9/13/2007 Page 17 of 31 I Spud Date: 6/6/1986 End: Description of Operations DECOMP PJSM w/hands and Baker. LD 21.05" cut off casing stub w/9-5l8" NSCC pin on bottom. DECOMP LD Itco Spear BHA #34. DECOMP PU Itco Spear BHA #35 w/new grapple fl8.681" ID. DECOMP RIH to new top of fish at 2000'. PU 63K, SO 67K, ROT 67K. Engage fish w/spear. Tq. up left to 10.2K to backoff fish and freewheel pipe. PU wt 59K. Suspect backoff, no bumper sub action. Screw back in and get pull over. Release spear. DECOMP POH f/2000' checkltorque ea. connection on trip out. DECOMP No loose jt. found. LD BHA Bowen Itco Spear #35. OECOMP PJSM wlhands on handling new type equipment. PU Baker Type "B" (slip type w/"j" slot wlright hand release) Spear BHA #36. DECOMP RIH to 2001'. PU 69K, SO 73K, ROT 73K. Engage spear and back off 9-5/8" casing 3 turns to left. DECOMP POH f/2001' to 1843'. MW = 8.5 ppg. DECOMP POH f/1843' to BHA. DECOMP Stand back drill collars. POH w/BHA #36. No fish. DECOMP Re-cock "j" on Type "B" spear. PU drill collars. RIH to 2001'. PU 69K, SO 73K, ROT 73K. Engage spear and back off 9-5/8" casing 3 more turns to left. Torque 5.5K max. See torque bleed off as expected. DECOMP POH to BHA #36. DECOMP LD Type "B" Spear BHA #36. Spear out of hole in released position. No fish. DECOMP Service rig and topdrive. DECOMP Bowen "Itco" Spear grapple damaged. Mobilize from Baker Deadhorse shop a new grapple flBowen Itco Spear BHA #37. DECOMP PU Bowen Itco Spear BHA #37. DECOMP RIH to 2001'. DECOMP PU 62K, SO 67K, ROT 67K. Engage fish w/spear assy. Work pipe and torque left to $.2K and back fish out. DECOMP POH w/fish. DECOMP Stand back drill collars. LD backed off joint 39.30' long w/NSCC box on bottom. Pin up downhole. LD spear BHA# 37. DECOMP Clean and clear rig floor of fishing equipment. DECOMP RU 9-5/8" casing handling/torque tum equipment. DECOMP PJSM w/crew, TP, casing hand, WSL. RIH w/9-5/8" L-80 47# Hydril 563 casing to 70'. Torqueturn to 18000 ftllbs. See tight hole and work casing through collapsed area of 13-3/8" f/70' to 74'. RIH to 2026' and unable to RIH further. MU IF x Hyd 563 headpin and and rotate casing slowly through tight spot and then RIH free. DECOMP Tag up at 2038'. PU 108K SO 110K. Work 10K torque down to Baker triple thread w/NSCC collar looking down. 14 turns at surface. RD torque tum equipment. Pull test to 250K. DECOMP RU cement head and circulating lines. Pressure test casing from plug on top of baffle collar installed below ES cementer to surface. 2000 psi f/30 minutes and chart. Bring pressure up and shear out ES cementer at 2900 psi. Establish circulation w/210 gpm, 142 psi. DECOMP PJSM w/Schlumberger, TP crew, truckdrivers, WSL. Pressure Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION Operations Summary Report Page 9 8 of 31 Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: 'Rig Name: NABORS 7ES Rig Number: Date 1 From - To I Hours I Task I Code I NPT I Phase 10/6/2007 121:00 - 23:30 I 2.501 CASE I P 10/7/2007 100:405 - 010:45 ~ 10.00 I CASE l P 01:45 - 02:45 ~ 1.00 I CASE ~ P 02:45 - 17:30 14.75 CASE P 17:30 - 18:00 ( 0.501 CASE I P 18:00 - 19:00 1.00 CLEAN P 19:00 - 20:00 1.00 CLEAN P 20:00 - 20:30 0.50 CLEAN P 20:30 - 21:30 1.00 CLEAN P 21:30 - 22:00 0.50 CLEAN P 22:00 - 00:00 I 2.001 CLEAN I P 110/8/2007 100:00 - 03:30 I 3.501 CLEAN 1 P 03:30 - 05:30 I 2.001 CLEAN I P 05:30 - 11:00 I 5.501 CLEAN I P 11:00 - 13:00 I 2.001 WHSUR I P Description of Operations DECOMP test lines to 3000 psi. Pump 5 bbls water ahead down drill pipe w/Schlumberger. Start mixing cement at 22:00. Pump on the fly 139 bbls of 15.8 ppg Gcement w/additives at average 3 bbUmin. Red dye in 1st 10 bbls of cement. SD and drop ES Cementer closing plug. Follow w/Schlumberger pumping 10 bbls of displacement. Switch to rig pumps and displace w/139 bbls of 8.5 ppg seawater at 7 bpm average displacement rate down flow line to cuttings box. At 114 bbls displacement red dye to surface. SD. Close annular preventer. Open valve to line f/9-5/8" x 13-3/8" annulus direct to cuttings box to avoid cementing up BOP. Continue pumping displacement at 85 gpm. Bump plug on schedule. CIP 23:20. FCP = 845 psi. 23 bbls. cement weighed at 15.2 ppg back to surface. Bring pressure to 2000 psi, (see indication at floor that ES cementer closed) and hold for 5 minutes. Release pressure and check ES cementer. No bleed back. DECOMP Open annular preventer and flush stack to clear cement. DECOMP Continue to flush stack, clear and BD lines. DECOMP Use Schlumberger cementer unit charge pump to circulate 7.75 bbls of 15.8 ppg G cement down 1" x 10' pipe into 13-318" annulus. Good cement back at surface. Catch all returns to surface in "Katch-Can" w/Super Sucker. DECOMP RD cementing lines and Schlumberger unit. Clear/clean floor and "Katch-Can" in cellar. DECOMP WOC, 1000 psi compressive strength per Schlumberger. Bring equipment f/casing cutting operation to floor. Clean rig, service top drive. Clean cuttings box. CO brushes on top drive motor. Change out "O" rings on upper valve body on topdrive. Clean/paint and then paint/clean. DECOMP PU 9-5/8" multistring casing cutter BHA #39 w/ball on seat. DECOMP RIH to 20' below RKB. Cut 9-5/8" casing, 915 psi, 48 rpm, 3K tq. Casing cut through in 6 minutes. SD and POH and LD 23.75' cut off stub. DECOMP LD multistring cutter BHA #39. Clear floor. CO bails. DECOMP PU cleanout BHA #40. DECOMP PU 24 jts of 4" HWDP. DECOMP RIH to 1992' and wash down to cement at 2025'. 259 gpm, 243 psi. DECOMP Drill cement, plugs, ES Cementer,baffle collar/plug from 2025' to 2035'. Orop through. 259 gpm, 243 psi, 85 rpm, 1.5K tq. ROT 80K. CBU. Rotate and reciprocate pipe through cleanout area. No drag, no obstructions. DECOMP RIH to EZSV at 9941'. PU to 9933'. PU 198K, SO 135K, ROT 170K. DECOMP Circulate surface to surface w/35 bbl Hi-Vis sweep. 465 gpm, 2100 psi., 40 rpm, tq. 9.2K. Pump 671 bbls. Small amount of rubber, scale, and no metal noted across shakers. DECOMP POH f/ 9933' to surface. MW = 8.3 ppg. Stand back collars and LD BHA # 40. Found metal in boot baskets, bolts and pieces of metal f/9-5/8" centralizers. DECOMP RIH with 1/2 muleshoe, nine 6.25" drill collars, 8 stds 4" HWDP below RTTS stormpacker. 35K string wt below packer. Set stormpacker @ 35' below RKB in 9-5/8" csg. Printed: 10/25/2007 1:26:19 PM • BP EXPLORATION Page 79 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9/13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date ~ From - To , Hours I Task I Code, NPT I Phase' Description of Operations ~ 10!8(2007 13:00 - 14:00 1.00 WHSUR P DECOMP PJSM. Test casing below stormpacker to 3500 psi f/30 mins art. Good test. Rotate stormpacker on off tool. POH with on/off tool closing stormpacker valve in top of RTTS. LD on/off tool. 14:00 - 15:30 1.50 BOPSU P DECOMP PJSM w/crew. ND BOP stack. 15:30 - 19:30 4.00 WHSUR P DECOMP Split stack and cut 9-5/8" casing above old tubing spool. NDiLD old tbg. spool. Stand back BOP stack. Cut 13-3/8" casing below GL and remove old well head. RU Wachs cutter and cut 9-5/8" csg 5" above ground level per Cameron specifications. 19:30 - 21:30 2.00 WHSUR P DECOMP Jnstall C:am~ron Slio Lock Head w/CANH metal seals. Test well head slip lock flange to 3800 psi (80% of collapse of L-80 9-5/8") fi30 minutes. 21:30 - 23:30 2.00 WHSUR P DECOMP NU adaptor and BOP stack. 23:30 - 00:00 0.50 BOPSU P DECOMP PJSM and CO bottom pipe rams f/9-5/8" to 2-7/8" x 5" variables. 10/9/2007 00:00 - 01:00 1.00 BOPSU P DECOMP Continue CO f19-5/8" rams to 2-7/8" x 5" variable lower rams. 01:00 - 05:30 4.50 BOPSU P DECOMP BOP test. 250 psi low, 3500 psi high pressure. Test witnessed by NAD TP Biff Perry and Lowell Anderson BP WSL. AOGCC representative Bob Noble waived AOGCC representation at the test. 05:30 - 06:00 0.50 BOPSU P DECOMP Rig down test equipment and blow down lines. 06:00 - 08:00 2.00 DHB P DECOMP Pick up 1 joint of drill pipe and RTTS running tool Run in hole and sting into RTTS, check for pressure bellow RTTS, no pressure Release RTTS and pull out of hole, Lay down RTTS Rack back drill collars 08:00 - 09:00 1.00 DHB P DECOMP Install wear ring PJSM with Schlumberge~wireline Rig up Schlumberger wireline 09:00 - 11:00 2.00 DHS P DECOMP Run in hole with 8 1/2" gauge ring junk basket and casing collar 4ocater to 9,920' eline depth 11:00 - 11:30 0.50 DHB P DECOMP Pull out of hole from 9,920' to 1,860', wire came out with a bird's nest 11:30 - 12:00 0.50 DHB N MISC DECOMP Work on Schlumberger Wire 12:00 - 12:30 0.50 DHB N MISC DECOMP Feed Bird Nested E-line over sheave and out to unit 12:30 - 13:00 0.50 DHB P DECOMP Continue pull out of hole from 1,860' to Surface, 2 gallons of cement, rubber, rocks, and metal recovered in junk basket 13:00 - 14:30 1.50 DHB N MISC DECOMP Rig down E-line, un-spool 2,000' of E-line, cut bad line and re-head E-line 14:30 - 17:30 3.00 DHB P DECOMP Rig up E-line and run in hole to 9,820' with gauge ring junk basket and casing collar locater Pull out of hole, junk basket empty Lay down junk basket 17:30 - 21:30 4.00 DHB P DECOMP Pick up 9 5/8" EZSV and casing collar locater Run in hole to 9,700' Log up and correlate to 9 5/8" USIT log Set top of 9 5/8" EZSV at 9,523' Positive indication EZSV setting tool fired on tension, lost 700 Ibs of tension Set down on EZSV, did not move Normal up tension was 230 Ibs less after EZSV was set Pull out of hole from 9,523' to surface, lay down Casing collar rnntea: iurzo¢uui ~:zn:~a rnn SG-~ i 'CJ • • BP EXPLORATION Page 20 of 31 Operations Summary Report Legal Well Name: G-19 Common Well Name: G-19 Spud Date: 6/6/1986 Event Name: REENTER+COMPLETE Start: 9!13/2007 End: Contractor Name: NABORS ALASKA DRILLING I Rig Release: Rig Name: NABORS 7ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 10/9/2007 17:30 - 21:30 4.00 DHB P DECOMP locater and setting tool 21:30 - 22:00 0.50 DHB P DECOMP Rig down Schlumberger E-line 22:00 - 22:30 0.50 DHB P DECOMP Test 9 5/8" casing and 9 518" EZSV to 3,500 psi Record and Chart for 30 minutes 22:30 - 00:00 1.50 STWHIP P WEXIT Pick up 9 518" Milling/Whipstock BHA 10(10/2007 00:00 - 01:00 1.00 STWHIP P WEXIT Finish picking up Milling/Whipstock BHA 01:00 - 02:00 1.00 STWHIP P WEXIT Run in the hole to 2,066' 02:00 - 02:30 0.50 STWHIP P WEXIT Shallow hole test MWD tool, test good 450 GPM @ 865 psi 02:30 - 06:30 4.00 STWHIP P WEXIT Run in hole from 2,066' to 9,250' with milling/whipstock BHA 06:30 - 07;00 0.50 STWHIP P WEXIT Orient Whipstock to 45 degrees left of high side PUW=203K, SOW=128K 450 GPM @ 1,950 psi 07:00 - 07:30 0.50 STWHIP P WEXIT Run in hole to 9,509', tag EZSV Check orientation, 44 degrees left of high side 450 GPM @ 1,950 psi Set bottom anchor Pick up to 215K to confirm anchor set Slack off and shear brass bolt with 35KIbs Pick up to 9,486' for mud displacement 07:30 - 09:00 1.50 STWHIP P WEXIT Displace well from seawater to 10.8 ppg milling fluid Pump 35 bbls Hi Vis Spacer 450 GPM @ 1,200 psi Pump 716 bbls 10.8 ppg LSND 450 GPM @ 1,450 psi initial, 450 GPM @ 2,300 psi final 0 0 - 5: 6.00 WEXIT ill window in 9 8 casing w+t a er generation mi mg assembly ~ Top of window = 9,487', Bottom of window = 9,504' `~ 110 RPM @ 8-10 Kftllbs, 500 GPM @ 2,651 psi, WOB = 4-10K 2751bs of metal in return 15:00 - 17:00 2.00 STWHIP P WEXIT Mill formation to 9,529' 110 RPM @ 9-10 KfUlbs, 500 GPM @ 2,651 psi, WOB 9-10K Appear to have good cement behind casing 17:00 - 18:30 1.50 STWHIP P WEXIT Circulate 1.5 bottoms up to clean hole for FIT Super Sweep surface to surface rotating and reciprocating pipe 60' Circulate 952 bbls of 10.8 ppg LSND mud 70 RPM @ SKft/Ibs, 500 GPM @ 2,760 psi 18:30 - 19:30 1.00 STWHIP P WEXIT Rig up to Perform FIT Perform FIT Hole depth 9,529' Shoe depth 9,496' Shoe TVD 7,550' MW 10.8 ppg Test Pressure 475 psi EMW = 12.0 ppg Charted for 10 minutes Rig down head pin 19:30 - 00:00 4.50 STWHIP P WEXIT Pull out of hole from 9,529' to 120' with milling assembly Rack back HWOP Lay down drill collars 10/11/2007 00:00 - 01:00 1.00 STWHIP P WEXIT Lay down milling assembly Upper mill full gauge 01:00 - 02:00 1.00 STWHIP P WEXIT Pull wear ring Printed: 10125!2007 1:26:19 PM TREE= 4"CAMERON WELLHEAD = McEVOY ACTUATOR = AXELSON KB. ELEV = 67.11' BF. ELEV = 37.18' KOP = 10,604' Max Angle = 94.5 Datum MD = Datum TV D = 8800 13-3/8" CSG, 72#, I L-80, D = 12.347" G-19B ` DRLG DRAFT 2,028' HESS ES Cementer ! 9-5l8", 47#, L-80, Hydri1563 2,090' Top of Cement 9 5!8" x 13 318" 2,189' 4-1/2" X LA NDgVG NtP, D = 3.813" 2,705 13-3/8", 72#, L-80, D=12.347" 9,342 9-5l8" X 7" Baker HMC ilner~ hanger, ZXP inr top packer I 9-518" Window 9 487'-9 804' EZSV / CIBP 9943' Top Of Cement 10007' Tub~g cut 10142' s-5is'x4-vr' nwP-cR 10183' a 1R" FZSV squeaze pacl®r 10210' TOP OF 2-7/8" LNR 10247' TOP OF 7" LNR 10340' 4-1/2" TBG, 12.6#, L-80, D=3.958" 10291' D = 8.681 #, L-80, 10598' 7" LNR, 26#, L-80, D = 6.276" 11253' 2-7/8" LNR, 6.16#, L-80, D=2.441" 12758' Minumum ID = 3.725" @ 10498' 4-1/2" XN NIPPLE 10,403 41/2"'X' Landing N~ple, ID=3.813" 10433' 7" X 4-1/2" Baker S-3 PKR 10,467 4 1 /2" 'X' Landing Nipple, D = 3.813" 10,498 4 1/2"'XN' Landing Nipple, D= 3.725" 10,510 4 1/2",12.6#, 13Cr-80, VamTop ~ X 4-1/2" Baker FN1AC liner hanger, ZXP Inr top 10,493 packer w / 76S 10667' 7" , 26#, L-80, BTGM liner PERFORATION SUMMARY REF LOG: ???? ON MM/DD/YY ANGLEATTOPPERF:90° (t~ 12030' Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL OPWSOZ DATE 2-7/8" 6 12030 - 12200 O 10/24/07 2-7/8" 6 12750 - 12930 O 10/24/07 2-7/8" 6 12980 - 13220 O 10!24!07 2-7/8" 6 13300 - 13550 O 10!24107 13602' Baker Landing coaar 13690' 4-1/2" , 12.6#, L-80, IBT-M LNR DATE REV BY COMMENTS DATE REV BY COMMENTS 08/29!86 ORIGINAL COMPLETION 11/04199 CTDSIDETRACKCOMPL 10/26107 MES SIDETRACK (G-19B) 10/31/07 lfLH CORRECTIONS PRUDHOE BAY UNR WELL; G-19B PHiBMT No: 2071240 API No: 50-029-21599-D2 SEC 12, T11N, R13E, 1534' FSL S 3004' FEL t3P Expbration (Alaska) Schlumbergep Alaska Data & Consulting Services 2525 Gambel! Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth scCANNED 0 C1 3 1 ZOO? Well Job# LOll Description Date F-48 11846815 US IT 111/- Oí lL> 10/12/07 G-19A 11890315 US IT iyq - Ù't' ~ 09/30/07 NGI-13 11890313 USIT 'YIt' J=r -dJ..t 09/30/07 MPE-30A 11855817 USIT ,¿O/-o ( 10/01/07 - F-11B 11649954 MCNL ;} cf-I - I t '-I '1t I::) 5 -t') 03/22/07 W-12A 11418301 MCNL 1'ì1(-t"1f~ .. I~~q 09/10/06 11-27 11637127 RST i-1s'(" - 147í ~ I Ç-S-~Cø 06/05/07 02-22A 11216214 MCNL !J1'Il..... - h ~O¡ ... J "'-~ '"). "+ 1 0/02/06 01-16 11630486 RST /~*-OO7r"" ~.s-j--'ff 06/28/07 01-14 11801086 RST I~~- ()'J.-':. .. 1 K-:"\ +'-1 07/07/07 L5-05 11767129 MCNL / '?r "':} -Öf.nc.. .." K:~ 0 06/17/07 D-21 11626119 RST ,e¡¡- ~ - ('~':::> ... ",,\J-''7ri 09/12/07 14-15 11221550 RST I",;{/- ó"ð'-I "JI 1:"1:> 7kl 03/07/06 D-18A 11695074 RST [)(') I - 1(')7- 11:- 1':'\:'1 "75 08/28/07 14-05A 11813055 RST i Oo¡ ~ -(1U / .. l~1fto 06/11/07 1-23/0-15 11846802 RST ¡j-tt". Iß\'-/'-/::1-;,- 'It 1~:-5155 08/11/07 S-03 11223120 RST /1fl - Il\(") 1!t1'):'\"ðL( 06/13/06 1-09A1L-21 11849930 RST Io.~ - (),9q ~ /5""S"" +~ 08/04/07 P2-19A 11649963 MCNL ~')()+-l')jd .... I ~5-:¡.;) 04/22/07 OWDW-NW 11211370 RST lJ"U'\ ,-" -V/~ t:i 1~5-=;-/ 02/28/06 K-01 11695073 RST J~~- WI ~ /00'7-6 08/27/07 11-32 11630498 RST D¡Lf-31 ""1~5(."t:¡ 09/03/07 3-25B/L-27 11630490 RST .Qt"lQ t'\~1 +- .c-C7. 'V 07/26/07 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COpy EACH TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Date Delivered: NO. 4459 Company: State of Alaska Alaska Oil & Gas Cons Gomm AUn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: P.Bay, Endicott, Aurora, Milnn Pt.,LisburnE BL Color 1 1 1 1 CD 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Alaska Data & Consulting Services 2525 Gambe" Street, Suite 400 A"oho.,., AK "50~""L ATTN: Beth ~ Received by: (1/Ì 10/23/07 . . • Maunder, Thomas E (DOA) From: Hobbs, Greg S (ANC) [Greg.Hobbs@bp.com] Sent: Tuesday, October O2, 2007 9:01 PM To: Maunder, Thomas E (DOA) Subject: RE: G-19A ~ q~~- ~, The 13 3/8" was collapsed and barely passed a 9 5/8" collar. We pulled 100,000 over to get the first collar through, then were able to fish the rest out. We then swaged out the 13 3/8" with a 10 3/4, 11 1/4 and 12 1/8" swage respectively to get the i1 3/4 washover shoe through to the top of the 9 5/8" stub. We then tied back with a patch successfully and fished the rest of the tubing and laid the abandonment plug and set a CIBP above the packer. We are now tying back the 9 5/8" from about 2050' per the original sundry. All in all the well was a mess. All the damage was caused by ice on the casing, the tubing was pressure. I have a presentation that I am putting together that I will send to you. I am heading to the slope tommorrow, but will catch up with you! Greg From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov) Sent: Tue 10/2/2007 1:06 PM To: Hobbs, Greg S (ANC) Subject: RE: G-i9A Based on what you relate, it appears that you were successfully able to deal with the collapsed 13-3/8". If you can describe what was found, I'd appreciate. Regards, Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [mailto:Greg.Hobbs@bp.com] Sent : Monday, October Ol, 2007 1:13 PM ~ -"` --"""``" To: Maunder, Thomas E (DOA) Cc: Nigh, Jim Subject: RE: DS 14-18B Tom- o ow up- ~ ~ .~ ~^. --\~ G-19 has an abandonment plug above the old production packer now, and we are working on doing the 9 5/8" tieback at this time- i RE: G-19 Progress • Page 1 of ~ • ~~~' "~ I 3 Maunder, Thomas E (DOA) From: Hobbs, Greg S (ANC) [Greg.Hobbs@bp.com] ' ~. Sent: Monday, September 24, 2007 3:54 PM '~~~ w To: Maunder, Thomas E (DOA) Cc: NSU, ADW Drlg Rig 7 ES Subject: RE: G-19 Progress Thanks for the quick turnaround Tom, this helps Duncan firm up his plans forward. Also to clarify, we will weld a wellhead on the well if a 7" tieback is required for any 9 5/8" corrosion right now. If we do nat need a 7" tieback at this time, we will use a Cameron Sliplock wellhead with Primary and Back-up metal seals. The same seal has been used to hang casing in in Arctic conditions in Russia with no issues. The metal seals allow it to have the Arctic rating we require. Cameron has successfully tested it in their Anchorage shop, and it passes their engineering requirements. Greg From: Maunder, Thomas E (DOA) [maiitoaom.maunder@aiasica.gov] Sent: Monday, September 24, 2007 3:42 PM To: Hobbs, Greg S (ANC) Cc: Jim Regg Subject: RE: G-19 Progress Greg, The further information answers my questions. It is important to know the behavior of the well since the cement was placed through the retainer. It appears that you have demonstrated that the remaining "structure" of this wounded well is competent to allow you to safely proceed with the repairs. Employing the 9-518" rams as you plan appears to be appropriate. Thanks for the update. Call or message with any questions. Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [mailto:Greg.Hobbs@bp.com] Sent: Monday, September 24, 2007 3:26 PM To: Maunder, Thomas E (DOA) Cc; NSU, ADW Drig Rig 7 ES Subject: RE: G-19 Progress Tom- After discussion this morning, with the well not losing at all since laying the cement, and following the IA circulation with 9.8 brine, we decided to test the well to 1000 psi and monitor the OA. The abandoned perforations and the production packer held 1000 psi for 10 minutes, losing 10 psi initially, then flatlining. The OA only pressured up to 100 psi and went back to zero as the pressure was bled off the well. The bradenhead of the well has a leak (screwed on the 13-3/8"} that has held 500 psi in the past and failed at 1000 psi. We have not re-tested this as it is a known leak. We did not want to exacerbate it. We wanted to test the barriers down the hole to support their integrity to better support moving forward with our current plan, keeping the well full of 9.$ brine while we abandon the production packer and re-build the 9 5!8" to weld a new wellhead to it and eliminate the 13 3/8" casing string from the picture. Hope that helps- 10/3/2007 RE: G-19 Progress Greg From: Maunder, Thomas E (DOA) [mailto:tom.maunder@aiaska.gov] Sent: Monday, September 24, 2007 2:40 PM To: Hobbs, Greg S (ANC) Subject: RE: G-19 Progress Page 2 of • ~~~~~.~ ~ ~ ~"l - ~ ~ Greg, It appears that the perforations have been successfully plugged. Your plan doesn't sound unreasonable. A couple of questions ... 1. Is your OA sound? Holding the 9-5/8" joint as you plan leaves that annulus exposed to any wellbore pressure. 2. Has the well bore been pressure tested at any time? i look forward to your reply. Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [maiito:Greg.Hobbs@bp.com] Sent: Monday, September 24, 2007 2:32 PM To: Maunder, Thomas E (DOA) Cc: NSU, ADW Drlg Rig 7 ES Subject: RE: G-19 Progress Tom, Over the weekend, cement was placed below the EZSV with no issues and a bit of pressuring up as it entered the perforations. We came out of the EZSV and Payed ~60' of cement on it, circulated the drilfpipe clean and came out of the hole. We then ran a-line and tagged cement at 10152' MD (58' on cement on the EZSV) and cut the tubing at 10142' MD. We ran in with a 4.5" RTTS to 1500' to get below the back-off point in the 4.5" tubing and circulated the well to 9.8 brine through the cut at 10142' MD. Plan forward is to cut the 4.5" tubing at 200' and pull it out of the hole. Duncan would like to change the lower set of pipe rams to 9 5/8" rams and test them during the BOP test. We want to use this set of rams to space out and hold the section of 9 5/8" casing that we run back in the well to replace what is currently damaged. This eliminates breaking the stack to set slips on this temporary piece of 9 5/8" in the well. The remainder of the 4.5" tubing will then be pulled out of the well with the upper set of VSR's that will be tested for the tubing and 4" drilfpipe, the annular and the blind rams. After pulling the tubing, we will lay a 100' cement plug on top of the production packer to abandon the current production interval once and for all. We will then proceed with re-building the well with new 9 518" casing from 2100' to surface per the sundry. Just keeping you up to date. If you have any comments or questions, feet free to get back with me! Greg 10/3/2007 RE: 0-19 Progress . Page 1 of2 . Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Saturday, September 22,200712:16 PM To: Hobbs, Greg S (ANC) Cc: Regg, James B (DOA) Subject: RE: G-19 Progress C:, - \sp\ \q~-\O ) Greg, Good news on the progress. I have spoken with Jim Regg and we agree that your request to go beyond 7 days on the BOP test is appropriate. Plan to test when you have the upper portion (-200') of the 4-1/2" tubing removed from the well and the BOP is clear. A copy of this message should be available at the rig. Call or message with any questions. Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) [mailto:Greg.Hobbs@bp.com] Sent: Sat 9/22/20078:33 AM To: Maunder, Thomas E (DOA) SUbject: RE: G-19 Progress Good Morning Tom- As of7:45 this morning, they are running the 27/8" PAC pipe to the plug, and are about ready to space out and pump cement. Regarding the extension of the BOP test, the blinds and bottom pipe rams were tested last Tuesday. The test of the full stack minus the bottom rams was last Saturday. With our 4 1/2" tubing in the stack that is currently allowing access deep in the well, we will not be able to test at midnight tonight. Our plan forward of cutting the 4 1/2" tubing above the packer at 10183' and 200' is to complete all work within the 41/2" tubing while we have that conduit. We want to minimize control line junk above the tubing fish in the well while we re-gain access through the 9 5/8" casing to finish the abandonment of the reservoir above the production packer. Hope that helps, and we appreciate the help! Greg SCANNED SEP 2 3 2007 From: Maunder, Thomas E (DOA) [mailto:tom.mauoder@,tla¡;;ka.goy} Sent: Fri 9/21/2007 1 :42 PM To: Hobbs, Greg S (ANC) Subject: RE: G-19 Progress Good news Greg. I hadn't seen tubing mashed that flat before. Now to fmd out ifthe 13-3/8" is not deformed. Tom 9/24/2007 RE: 0-19 Progress . . Page 2 of2 From: Hobbs, Greg S (ANC) [mailtQ:Cìteg.1I9Þb¡;;@bp.C9m] Sent: Friday, September 21,200710:25 AM To: Maunder, Thomas E (DOA) Subject: G-19 Progress Tom, Got an EZSV set in the 4 1/2" tailpipe last night, and are progressing forward with a cement abandonment of the perforations under the EZSV. Greg 9/24/2007 0-19 Progress . Page 1 of 1 . Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, September 21,200710:43 AM To: 'Hobbs, Greg S (ANC)' Subject: RE: G-19 Progress G-\~ ~ \S~ -\Ü~ Good news Greg. I hadn't seen tubing mashed that flat before. Now to find out if the 13-3/8" is not deformed. Tom From: Hobbs, Greg S (ANC) (mailto:Greg.Hobbs@bp.com] Sent: Friday, September 21, 2007 10:25 AM To: Maunder, Thomas E (DOA) 5'CANNED SEP 2 12007 Subject: G-19 Progress Tom, . ..:.. Got an EZSV set in the 4 1/2" tailpipe last night, and are progressing forward with a cement abandonment of the perforations under the EZSV. Greg 9/21/2007 FW: 0-19B plan forward . . Page 1 of 1 Maunder, Thomas E (DOA) From: Hobbs, Greg S (ANC) {Greg.Hobbs@bp.com] Sent: Thursday, September 20,200712:40 PM To: Maunder, Thomas E (DOA) Subject: FW: G-19B plan forward Attachments: Collapsed tbg.ZIP; G-19 Plan forward.doc Tom- Things are going well on G-19, we are changing our plan a bit given that we found collapsed 9 5/8". As the attached plan notes, we are focusing on establishing a 4 1/2" conduit through the tubing to the perforations (currently being confirmed with a drift after hopefully re-screwing on to it this morning). We will abandon the perforations with cement below a 4 1/2" ezsv, then fix the 9 5/8" (hopefully the 133/8" is not collapsed), and then proceed with abandoning above the packer with the attached plan. Attached are the plan forward, pictures of the collapsed tubing that was recovered as well as a picture of the 9 5/8" collapse. Greg «Collapsed tbg.ZIP» From: Phillips, Ron Sent: Thursday, September 20,200711:56 AM To: NSU, ADW Drtg Rig 2es; Hobbs, Greg S (AN C) Subject: G-19B plan forward «G-19 Plan forward.doc» Thanks, Ron Phillips Operations Drilling Engineer GPB Rotary Office (907) 564-5913 Cell (907) 748-7868 9/21/2007 . . 09/20/20070-19 Plan Forward 1136 Hours Phillips/HobbslReem Prima" Plan 1. RU E-line and drift 4 W' tbg to 10,225'. 2. RIH wÆZSV squeeze PKR on E-line and set at 10,210'. RD E-line. 3. RIH w/stinger on PAC drillpipe and sting into squeeze PKR and bullhead cement thru perfs. Come off PKR and circulate PAC pipe clean. Call town to confmn next plan before continuing. Secondary Plan 4. RU E-line and cut 4 w' tbg in the middle of the first full jt above the TIW PKR @ ~10,183'. RD e-line. 5. Pull the top 1,165' of 4 W' tbg out of hole. 6. Cut and pull collapsed 9 5/8" csg out of hole. 7. Run round 9 5/8" csg back in hole with a patch. 8. Pull 4 W' tbg out of hole from ~10,183'. 9. Lay 100' of cement on top of9 5/8" TIW PKR @1O,183' and 4 W' EZSV@ 10,210'. 0-19 W orkover Update . . Page 1 of2 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, September 18, 2007 3:55 PM To: 'Hobbs, Greg S (ANC)' Cc: Forman, Paul Subject: RE: G-19 Workover Update Greg, Thanks for the updated documents. To confirm our conversation, I would like to receive the operations summaries of the pre-rig and rig work. Tom Maunder, PE AOGCC --- From: Hobbs, Greg S (ANC) (mailto:Greg.Hobbs@bp.com] Sent: Tuesday, September 18, 2007 3:46 PM To: Maunder, Thomas E (DOA) Cc: Forman, Paul Subject: RE: G-19 Workover Update Tom- Here is the G-19 current plan again, I had some steps in the text referenced incorrectly from drafts that Ron, Duncan and I put together. This is a correct version. I also attached the sundry application and the pre-rig requests. Both indicated a jet cut at 37' pre rig that was approved in the sundry. We opted to do the cut with a mechanical cutter with the rig on location due to Schlumberger having discomfort with a jet cut at such a shallow depth. It is my error that I did not inform you that we moved that single operation from the pre-rig operations to the rig operations. I felt that we were still following the Sundry as far as the mechanical changes with the well- I apologize and will be cognizant of this in the future. Let me know if you need any other information, I can cut and paste from Digital wellfile and DIMS I believe. Greg From: Maunder, Thomas E (DOA) [mailto:tom.maunder@aJaska.gov] Sent: Tuesday, September 18, 2007 3:11 PM To: Hobbs, Greg S(ANC) Cc: Forman, Paul Subject: RE: G-19 Workover Update Greg, Would it be possible for you to send the actual operational summaries for the work accomplished pre-rig and rig? With the shallow cOllapse point, it appears that changing the procedure was valid however I don't find any note regarding the change. Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC From: Hobbs, Greg S (ANC) (mailto:Greg.Hobbs@bp.com] Sent: Tuesday, September 18, 2007 1:08 PM To: Maunder, Thomas E (DOA) 9/21/2007 0-19 W orkover Update . Page 2 of2 . Cc: Forman, Paul SUbject: G-19 Workover Update Tom- Over the weekend, Rig 7es moved on to G-19A and nippled up and tested the BOP. Originally, the pre-rig plan was to cut the tubing at 37 feet as the tubing was collapsed at 42'. With the risk of a jet cutter at a shallow depth, the well was bullheaded with a 9.8 brine down the tubing and bled to zero on the tubing, inner and outer annuli for pre rig preparation. The rig arrived on Friday, 9/14, the well was showing 0/0/0 on the tubing, fA and OA. The rig moved on, and the stack was nippled up and tested. A mechanical cut was made on the tubing at 37 feet on Saturday morning, 9/15. At this point, the IA pressure came up to 100 psi, and aereated diesel (no LEL) was noted in the stack. The blind rams were closed at this point, and the diesel was lubricated out of the well with 9.8 brine from Saturday until 4:00 a.m. this moming. A total of 289 bbl of diesel were recovered from the IA with over 400 bbl of 9.8 brine lubricated in the well. At 4:00 a.m. this morning, diesel returns were minimal, and the blinds were opened and the loss rate to the well of the 9.8 brine was 1.7 bbVhour. Returns from the well were pure Diesel. This was confirmed by the lab. Lou Grimaldi was contacted and aware of the operations. We are currently proceeding forward with the attached plan for the well now that the well is fluid packed with 9,8 brine in the tubing and the fA. Please call me if you have any questions. Greg «G-19 Plan. doc» 9/21/2007 . . 0-19 Plan Forward 9/18/07 Oreg Hobbs/ Ron Phillips/ Duncan Ferguson 1. Pull the hanger and lay down the cut stub and control lines. 2. Test the lower pipe rams and the blind shears. 3. Allow the fluid level to drop 60' (30 psi) in the well after the test. 4. Run a camera to inspect and capture the condition of the welL Re-fill the well. 5. Call Ron Phillips (748-7868/357-7448) and Greg Hobbs (980-1439/688-4622) to initiate conference call. Conference Number is: 1-866-634-1110, Leader Code: 6310, Conference Code: 1264105294. 6. If the 9 5/8" is not collapsed, move forward to step 7. If the 95/8" casing is collapsed, consider the options in steps 16 and 17. Final plan will be determined in the conference call following the picture of the wellbore. 7. Pick up three joints of wash pipe, RIH, cut 4 ~"tubing with outside cutter. 8. POOH. Lay down fish. 9. Rill with 41/2" workstring with overshot. Latch up on stub. Pick up and pull 20K over to confirm latch. 10. Set workstring in slips. RU full pressure control with E-line. Drift with gauge ring. Run 4 W' EZSV set up to squeeze through. Set plug at 10210' (full joint above x-nipple). 18E tally 6/22/86. 11. Jet cut tubing at middle if first joint above the packer ~10183' MD. POOH and RDMO e-line. 12. Circulate the well to 9.8 brine. Monitor for losses. 13. POOH with tubing, lay down same. 14. RIH with drillpipe and stinger. Wash down to EZSV. Stab into EZSV, squeeze perforations. Come off of EZSV and lay 100' of cement on top of the EZSV in the 9 5/8" casing. CBU. POOH. 15. Return to step 13 of the original operations summary. 16. If the 9 5/8" is collapsed, and the tubing stub is visible, consider getting on the stub with the overshot and gently taking a stretch reading on the pipe. The next step would be to consider a blind back-off. 17. If the 9 5/8" is collapsed and the tubing stub is not visible, prepare to use casing rollers! swage in the pipe to pass through it to re-establish connectivity with the tubing with a spear or overshot. · . ~1f~1fŒ (ID~ ~~~~~~ / I A.",A.~1i& OIL AND GAS / CONSERVATION COmnSSION , I SARAH PALIN, GOVERNOR 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279·1433 FAX (907) 276-7542 Greg Hobbs Senior Drilling Engineer BP Exploration Alaska Inc. PO Box 196612 Anchorage, AK 99519-6612 \~q/ (03 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU G-19A Sundry Number: 307-251 Dear Mr. Hobbs: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, sCANNED AUb () 9 2007 DATED this t6 day of August, 2007 Enc!. · q¡;¡. \ ,,"..-07 ¡)7S ?/¡¡c STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COM SION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25 280 ~t~ RECE JUt 2 6 1. Type of Request: ~ Abandon / o Alter Casing o Change Approved Program o Perforate o Stimulate o Waiver iUaska Oil & Ga!i: rOM f o Time Extension ;¡... o Re-Enter Suspended Well o Other o Suspend o Repair Well o Pull Tubing o Operation Shutdown o Plug Perforations o Perforate New Pool . .> 4. Current Well Class: 181 Development . 0 Exploratory o Service 0 Stratigraphic 5. Permit To Drill Number 199-103 ' 6. API Number: 50-029-21599-01-00 . 8. Well Name and Number: 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line where ownership or landownership changes: Spacing Exception Required? 0 Yes 181 No 9. Property Designation: \10. KB Elevation (ft): ADL 028285 67.06' . 12.< ... .CCC. ..... \N....II Total Depth MD (ft): Total Depth TVD (ft): I Effective Depth MD (ft): 12758 9008 . I 12691 Casino Lenoth Size MD Structural Conductor Surface Intermediate Production Liner PBU G-19A . 11. Field / Pool(s): Prudhoe Bay Field / Prudhoe Bay Pool -- - Tubing Grade: L-80 packers and SSSV MD (ft): 10183' 14. Well Class after proposed work: ,. o Exploratory 181 Development 0 Service Effective Depth TVD (ft): Plugs (measured): 9007 None TVD Burst Liner 110' 20" 110' 110' 2703' 13-3/8" 2703' 2641' 4930 10595' 9-5/8" 10595' 8381' 6870 912' 7" 10341' - 11253' 8188' - 8869' 7240 2511' 2-7/8" 10241' - 12758' 8114' - 9008' 13450 Perforation Depth MD (ft): I Perforation Depth TVD (ft): I 11355' - 12642' 8924' - 9001' Packers and SSSV Type: 9-5/8" x 4-1/2" TIW 'HBBP' packer Tubing Size: 4-1/2", 12.6# 13. Attachments: 181 Description Summary of Proposal 0 BOP Sketch o Detailed Operations Program 15. Estimated Date for 16. Well Status after proposed work: CommencinQ Operations: August 7,2007 0 Oil 0 Gas 17. Verbal Approval: pate: 0 0 Commission Representative: / WAG GINJ 18. I hereby certify that the for~~g i~lrue and correct to the best of my knowledge. Printed Name Greg Hob/:Ss / A I. Title Senior Drilling Engineer <LVf#;~ /U/ /1 c/ c'; Conditions of approval: Notify Commission so that a representative may witness o Plug Integrity '~OP Test 0 Mechanical Integrity Test 0 Location Clearance Junk (measured): 12480 CollaDse 2670 4760 5410 13890 Tubing MD (ft): 10291 ' o Plugged OWINJ 181 Abandoned o WDSPL Contact Ron Phillips, 564-5913 Signature 564-4191 DateY/J/1J' {< <vI",; Phone Commission Use On Iv Prepared By Name/Number: Terrie Hubble, 564-4628 1 Sundry Number:, ?/)'7.. J.5/ Other: ~soO ~'\ rov ~~~\- Subsequent Form Required: '-\0 \ Approved Bv: Form 10-403 Revised 06/2006 ., I/J ß ~ APPROVED BY './J r ~OMMISSIONER THE COMMISSION V(/~ OR' GINA L RBDMSBFl AUG 09 20D7 Date g-...~ttÞ~ Submit In Duplicate 4- 17 2-7,tt1 A-YA/ð 7 . . Obp GL.JJ.a6rAly To: AOGCC Date: July 20, 2007 From: Ron Phillips - BPXA GPB Rotary Drilling Subject: Reference: G-19A Application for Sundry Approval - P&A for Sidetrack Operations ./ API # 50-029-21599-01 Approval is requested for the proposed P&A of PBU well G-19A. This well has IA x OA x Conductor communication and in its current status is unable to be produced. In order to return to production, the well requires a tubing swap and a 9 5/8" casing replacement from 2000' MD to surface. Due to the Bradenhead/mandrel hanger leak the 13 3/8" x 9 5/8" annulus will be cemented to surface and a new 9 5/8" wellhead will be installed. In its current location, the remaining reserves cannot justify the expense of a workover. A horizontal sidetrack to the base of Zone 1 B is seen as the best way to maximize value from the wellbore. The sidetrack is currently scheduled for Nabors rig 7ES, beginning around September 30, 2007. The pre- rig work for this sidetrack will begin at the Well's Group earliest convenience after sundry approval. Current Condition: ./ Secured with Load and Kill with seawater and 97 bbfs crude 7/23/03 ./ Attempt fA test - crude noted escaping through flutes in surface casing hanger 7/23/03 v ./ Static pressure survey 9/11/03 . ./ MITOA with N2 passed to 500 psi. Ice wedges in the flutes, may be masking a surface casing leak v 10/30/05 ./ MITIA to 3000 psi - passed. Pumped 61 bbls diesel + 12 bbls crude 12/04/05 ./ PPOT-/C to 3500 psi passed after re-energizing Y seals 12/10/05 ./ MITOA to 3000 psi - passed (T and IA = zero) 12/15/05 ./ Hot oil treatment 5 bbls MeOH + 50 bbls 180-degr crude T +IA 0 to 2500 psi 4/12/06 ./ Hot Diesel treatment 22 bbls at 1800 F. Pressure tubing to 2500, bleeds to 1100 in 1.5 hrs 4/24/06 ./ 2.0" gauge ring and 3.0" tapered lead impression block indicates collapsed tubing at 42' MD. 4/25/06 ./ MITIA Failed. Tubing tracked IA pressure to 500 psi and bled 40 psi in 30 minutes. OA remained O. 5/06/06 . ./ 1.5" drift sat down at 42'. 10/22/06 Scope Pre-RiQ Work: 1. Bleed casing and annulus pressures to zero. 2. Cycle all LDS, repair or replace as needed. 3. Kill well with 9.8ppg brine. Freeze protect well with diesel. 4. Cut Tubing at 37' with e-line. 5. Set a BPV and test to 1000 psi from tubing annulus (or maximum allowable up to 1000 psi). 6. Secure the well. Level the pad as necessary. RiQ Operations: 1. MI/RU Nabors rig 7ES. Pull BPV. 2. Set and re-test TWC to 1,000 psi. 3. Nipple down tree. Nipple up and test BOPE to 3,500psi. Pull TWC. 4. Fish tubing hanger and cut stub. 5. RIH with wash-over pipeloutside cutter. Wash-over tubing stub 90' to swallow collapsed pipe. 6. Cut tubing below collapse and POOH with fish. G-19A Application for Sundry ~~") ~ ~ç~ ~ ~ . . 7. RIH with overshot on 5" drillpipe. Latch tubing stub. 8. Attempt to pull 4-%" tubing from the SBR at 10,168' (80% Yield = 231,000 Ibsf). 9. RU wireline. Punch tubing in the first full joint above the SBR TBG seal assy at 10,183'. 10. Circulate well to seawater. 11. RIH with jet cutter and cut tubing at ± 10,173'. 12. Recover tubing fish. 13. RIH with EZSV squeeze packer on DP and set at 10,163'. # 14. Pump 18.5 bbls of cmt to fill tbg/csg, squeeze 24.2 bbls into perfs, unsting from packer and lay 7.3 bbls (100') on top of squeeze packer. POOH. 15. RIH wI 8-W' gauge ring I junk basket to top of cement -10,063'. 16. RIH with HES EZSV bridge plug on E-line and set at -10,022' md, as required to avoid cutting a casing collar while milling the window. POH. RID E-line. 17. Run USIT in 9-%" casing from surface csg shoe @2,70S' up to surface, run in corrosion and cement mode. POOH. RID E-line. 18. String shot 9-%" casing at back off point (-2,152' or where USIT indicates TOC) to ease break out. RD e-line. 19. Change out to 9-%" rams, and test doors. 20. MU a Baker 9-%" cutting assembly. RIH picking up DP. Cut the 9-%" casing per Baker representative instructions. Cut -4' above the string shot casing collar. POOH, UD assembly. 21. BOLDS, RU/MU casing spear assembly, and unseat the 9-%". Circulate the Arctic Pack from the annulus with warm diesel followed by seawater and detergent sweeps. Pull the 9-%" casing from the cut. 22. MU Wash over assembly, and 13-%" casing scraper. 23. RIH, Clean out the 13-%" casing, and the 9-%" casing stub, POOH, UD the assembly. 24. RU BKR back-off assembly, RIH, and back off the 9-%" casing joint. POOH, UD assembly. 25. MU casing spear assembly, RIH, recover cut stub. POOH. 26. MU 9-%" ES Cementer on screw in sub and RIH wI new 9-%", TC-II casing. 27. Nipple down BOPE. 28. Weld on 9-5/8" FMC starting head. 29. Nipple up and test BOPE. 30. Shear open ES cementer and cement 9-%" x 13-%" annulus wI 126 bbls class G 15.8ppg cement with Latex (2,152' of 13-%" x 9-%"). 31. PU 4" DP and mill tooth bit. Make clean out run through the ES Cementer. _ 32. Pressure-test the 9-%" casing to 3,500 psi for 30 minutes. Record test. \ ~\""'> 33. Change BOP rams back to VBR's and test. Co\. '(>'\>~~ G. \ 34. P/U and RIH with 9-%" Baker bottom-trip anchor whip stock assembly. Orient whip stock, as desired, and set on EZSV bridge plug. Shear off of whip stock. 35. Displace the well to 10.8 ppg LSND based milling fluid. Completely displace the well prior to beginning . . . 36.r\ÃITïwindowi"n -9=%" casing at ± 10,000' MD, plus approximately 20' beyond middle 0 window. Circulate well bore clean. 37. Pull up into 9-%" casing and conduct an FIT to 12.0 ppg EMW. POOH. 38. M/U 8-%" Dir/GR/Res assembly. RIH, kick off and drill the 8-W' intermediate section to the top of the Sag River, per directional proposal. Circulate well clean, short trip to window. POOH. 39. Run and cement a 7", 26.0#, L-80 intermediate drilling liner. 40. Test the 9-%" casing X 7" liner to 3,SOOpsi for 30 minutes. Record the test. 41. M/U 6 1/8" Dir/GR/Res/ABI assembly. RIH to the landing collar. 42. Drill out the 7" liner float equipment and cement to the shoe. 43. Displace the well to 8.4 ppg Flo-Pro drilling fluid. 44. Drill out the 7" shoe plus drill -20' new formation; pull up into the shoe and conduct an FIT to 10.0 ppg EMW. Drill ahead to horizontal landing point. POOH for bit I BHA change. PU Neu/Den. 45. RIH, drill horizontal section to planned TD, short trip as necessary. 46. Circulate, short trip, spot liner running pill, POOH. 47. Run and cement a 4-%",12.6#, L-80 solid production liner. POOH UD all drill pipe. 48. RIH with 2-W' perf guns and perforate ±800'. 49. R/U and run 4-%", 12.6#, L-80 completion tubing. Land the tubing RILDS. 50. Reverse circulate seawater and corrosion inhibitor. Drop the ball and rod, set the packer. 51. Individually test the tubing and annulus to 3,SOOpsi for 30 minutes. Record each test. 52. Pressure up on annulus to shear the DCK valve. Confirm two-way circulation. 53. Set a TWC and test to 1000 psi. 54. Nipple down the BOPE. Nipple up the tree and test to 5,000psi. 55. Pull TWC. Reverse in sufficient diesel to freeze protect to 2,200' TVD. U-tube. 56. Install BPV and test. Secure well. RDMO. G-19A Application for Sundry . . Post-Ria Operations: 1. Mil RU slick line. 2. Pull the ball and rod I RHC plug from landing nipple below the production packer. 3. Install well house and instrumentation. Well Coordinates: Surface Location Target Location Northin 5,965,667 Bottom Location Northin 5,966,891 Estimated Pre-rig Start Date: 07/30/2007 Estimated Spud Date: 09/30/2007 Ron Phillips Operations Drilling Engineer 564-5913 Offsets 1,535' FSL 12,276' FWL Offsets 4,703' FSL 12,468' FWL Offsets 612' FSL I 4,229' FWL G-19A Application for Sundry TRS 11 N, 13 E, Sec 12 TRS 11 N, 13 E, Sec 14 TRS 11 N, 13 E, Sec 11 TREE= 4"CAMERON G~9A WELLHEAD:;: M::EVOY . I SA_TE: TxlA communication. Occasional I ACTIJA TOR = AXELSON pre-rig crud urface thru fluted surf csg hgr KB. ELEV = 67.06' BF. ELEV = 40.41' :;.-- c.ub :d 31' KOP= 2000' X~ ~ I\IIax Angle = 95 @ 11622' 42' Collapsed tubing « 1.S" restriction) I Datum MD = 11250' Datum ìVD = šãOOSS . I 2070' 4-1/2" SSSV OTIS LANDING NIP, ID = 3.813"1 1 13-3/8" CSG. 72#, L-80, ID = 12.347" I 2705' "J-.4 .. I 10107' H 4-1/2" OTIS XA SLIDING SLV, ID = 3.813" I Minumum ID = 2.37" @ 10247' I I 2-7/8" LINER TOP, PIN ID i I 10168' H SBR TBG SEAL ASSY 1 ì :8: """"'" I 10183' H 9-S/8" X 4-1/2" HBBPTIIIV PKR, ID = 4.7S" I ""-'" I I I 1 0226' H 4-1/2" OTIS X NIP, ID = 3.813" I 1 TOP OF 2-7/8" LNR H 10247' I I I 10247' H 2-7/8" BKR DEPlOYMENT SUB, ID - 3.000" I I - I 10258' H 4-1/2" OTIS XN NIP, ID = 3.72S" . 14-1/2" TBG, 12.6#, L-80, .0152 bpf, ID = 3.9S8" I 10291' I 1 10291' H 4-1/2" TUBING TAIL I 1 TOP OF 7" LNR 1 10340' I I I I 10302' H ELMD TT LOOGED OS/06/90 1 I 9-S/8" CSG. 47#, L-80, ID = 8.681" I 10595' r-- ~ MILLOlJT WINDOW 11253' - 11259' I TOP OF WHIPSTOCK I 11250' I ~ I 7" LNR, 26#, L-80, .0383 bpf, ID = 6.276" - 11253' "- PERFORA TlON SUIIIII/IARY I 12480' H FISH - POSSIBLE JUNK (6126/03) I REF LOG: MJI/D GR ON 01/02/99 .-; ANGLEATTOPÆRF: 62°@ 11355' ~~[ Note: Refer to A"oduction DB for historical perf data 12687' H MILLED CIBP (6/7103) I SIZE SPF INTERVAL OPNISQZ DATE 2 6 11355 - 11375 0 02/13/02 ........7C 2 6 11513-11535 0 02/13/02 I PBTD 1 12691' I ~ r 2 6 11535·11560 0 02/13/02 2 4 11619 - 11830 0 11/04199 2 4 11880 - 11970 0 11/04/99 2 4 1200S - 12045 0 11/04/99 I 2-7/8" LNR, 6.16#, L-80, .OOS8 bpf. ID = 2.441" H 12758' 1/ 2 4 12170 - 12400 0 11/04/99 2 4 12440 - 12529 0 11/04199 2 4 12584 - 12642 0 11/04199 DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BA Y UNrr 08/29/86 ORIGINAL COMPLETION 12/05/05 CJA/PAG Tl\N PACKER CORRECTlON WELL: G-19A 11/04/99 CTD SIDETRACK COM PL 07/20/07 RLP A"e- Rig ÆRMrr No: '1991030 02101/02 RNfTP CORRECTlONS API No: 50-029-21599-01 02117/02 JAFfTLH ADD ÆRFS SEC 12, T11 N, R13E, 3744' SNL & 3003' WEL 06/07/03 DBM'TLH MILL CIBP 06125/03 SRB/KK FISH BP Exploration (Alaska) I EZSV CIBP H 10022' I I Top Of Cerrent H 10063' I 10,424 4 112" 'X' Landing Nipple, 10 = 3.813" 10444' 7" X 4-112" Baker 5-3 PKR I EZSV Squeeze PKR H 10163' I 10,464 41/2" 'X' Landing Nipple, 10= 3.S13" I Tubing cut H 10173' I 10,484 41/2" 'XN' Landing Nipple, ID = 3.725" I H I 10,498 41/2",12.6#, L-80, TCII 9-518")(4-1/2" TIWPKR 10183' 7" X 4-112" Baker HMC liner hanger, ZXP 1m top H 1 packer w / TBS TOPOF 2-7/S" LNR 10247' 7" , 26#, L-SO, BTC-M liner TOP OF 7" LNR H 10340' I 4-112" TBG, 12.6#, L-80,10=3.958" 9-5/8",47#, L-80, 10 = 8.681" 10595' TRI;E = ~ 4" CAI\IERON W3..LH~O = III'cEVOY ACTUATOR = AX8..S0N KB. a.EV = 66.36' BF. a.EV = 40.41' KOP = 9950 Max Angle ~____ Datum M) = Datum lVD = I 9-5/8" Window H 10000'-10019' I 7" LNR, 26#, L-BO, Î 10 = 6.276" 2-7/8" LNR, 6.16#, L-80, 1D=2.441" DATE 10103/06 05108/07 07101/07 REV BY PGS RLP RLP COMMENTS Proposed Com pl. (Wp02) Updated Proposed Com pl. (Wp09) PRUDHOE BAY UNIT WELL: G-19B ÆRMIT No: API No: 50-029-21599-02 SEC 12, T11N, R13E, 3744' SNL & 3003' WEL G-1ts Proposed . 2,152 H HES ES Cerrenter I 2,200 H 4-112" X LANDING NIP, 10 = 3.813"1 2,705 H 13-3/8",72#, L-BO, 10=12.347" I 9,850 ~ 9-5/8" X 7" Baker HMC liner I hanger, ZXP Inr top packer I 10,100 H 7",26#, TC-II x-over BTC-M LNR I 13612' H 4-1/2",12.6#, L-80, LNR [}Þ, TE REV BY COMMENTS BP Exploration (Alaska) . . Review of Sundry Application 307-251 BP Exploration (Alaska) Inc. Well Prudhoe Bay Unit G-19A Prudhoe Bay Field, Prudhoe Oil Pool AOGCC Permit 199-103 Requested Action: BP Exploration (Alaska) Inc. (BPXA) proposes to plug the existing well to prepare it for sidetracking. Recommendation: I recommend approval of BPXA's request. Discussion: Well G-19 was originally drilled and completed in 1986. The well produced a total of 5 MMBO before being plugged in preparation of the G-19A sidetrack in 1999. The G-19A sidetrack was completed in November 1999. G-19A produced on a "continuous" basis for on 5 months and then production began to cycle. Oil production dropped quickly, from over 2,800 BOPD initially to less than 800 BOPD less than two years later, and the GOR rapidly increased, from less than 5,000 SCF/STB to over 25,000 SCF/STB in only five months. In January 2002 BPXA added additional perforations to the well in a failed attempt to improve performance, production actually dropped from about 800 to 300 BOPD and GOR increased from about 30,000 to 50,000 SCF/STB after the perforations were added. The well then began to produce sporadically until July 2003 when it was shut-in due to IA x OA x conductor communication that will require the replacement of tubing and casing in order to remedy. Cumulative production from the G-19A wellbore is approximately 0.5 MMBO. BPXA states that the remaining reserves in the current wellbore would not justify the needed expense of replacing the tubing and 2,000 feet of the 9 5/8" casing to return this well to an operable condition and that plugging the existing wellbore so that a horizontal sidetrack to the base of the Zone 1 B sand is the best option. Conclusion: Based on the historically poor performance of the G-19A wellbore, particularly after the January 2001 workover, BPXA's proposal to abandon the existing well so that the mother wellbore can be repaired and the well sidetracked to a more favorable location appears to be the best option for this well. D.S. RobY~~----------- Reservoir~ August 1, 2007 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Performed: Abanon r-~ suspend[~] Operation Shutdown r-~ Perforate F'I variancer-] Annuar Disposal [--] After Casiner"'] Repair Well[~] Plu~ Perforations[~ Stimulater~ Time Extension~] Other[] Change Approved Programr-1 Pull TubingS] Perforate New Pool~'-1 Re-enter Suspended Welir"] MILLED CIBP '2. Operator 4. Current Well Class: 5. Permit to Drill Number: Name: BP Exploration (Alaska), Inc. Development [ Exploratoryr'~ 199-1030 3. Address: P.O. Box 196612 6. APl Number Anchorage, Ak 99519-6612 Stratigraphic r--~ Service E] 50-029-21599-01-00 7. KB Elevation (ft): 9. Well Name and Number: 67.06 G-19A 8. Property Designation: 10. Field/Pool(s): ADL 028285 Prudhoe Bay Field ! Prudhoe Bay Oil Pool 11. Present Well Condition Summary: Total Depth measured 12758 feet true vertical 9008 feet Plugs (measured) Tagged TD @ 12687' (06/07/2003). Effective Depth measured 12687 feet Junk (measured) Pushed CIBP to 12687' (06/07/2003). true vertical 9007 feet Casing Length Size MD TVD Burst Collapse Conductor 110' 20" 137' 137' 40K 520 Surface 2676' 13-3/8" 2703' 2641' 80K 2670 Intermediate 10568' 9-5/8" 10595' 8387' 80K 4760 Liner 912' 7" 10341'-11253' 8188'-8869' 80K 7020 Sidetrack Liner 2511' 2-7/8" 10247'-12758' 8114'-9008' 80K 11160 Perforation depth: Measured depth: Open Perfs 11355'-11375', 11515'-11560', 11619'-11830', 11880'-11970', Open Perfs 12005'-12045', 12170'-12400', 12440'-12529', 12584'-12642'. True vertical depth: Open Perfs 8924'-8934', 8989'-8993', 8990'-8990', 8988'-8991', 8994'-8997', Open Perfs 9006'-9009', 9001 '-9012', 9010'-9007'. Tubing: (size, grade, and measured depth) 4-1/2"12.6# L-80 TBG @ 10291 '. SBR TBG Seal ~[.~S'~!~i.~ll~l'~, @-.1.Q168.!... · · · ...: Packers & SSSV (type & measured depth) 9-5/8"x4-1/2"TIW Packer@ 10183'. JUL ~'~ ~ 2003 4-1/2" otis sssv Landing Nipple @ 2070'. t~l~.~...~,.,,, ~r'i?, ~.. .... , ,..~ 12. Stimulation or cement squeeze summary: /:i, ,i,~ ~,~I : , ,~,,, ~,,,,,, Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13 Representative Daily Average Production or Iniection Data Oil-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: SHUT-IN Subsequent to operation: SHUT-IN 14. Attachments: 15. Well Class after proposed work: ExploratoryE] Development~ Service r'-'l copies of Logs and Surveys run _ 16. Well Status after proposed work: Oil[] Gasr-] WAGE~ GINJ[-1 W,NJI--I WDSPLr-1 Daily Report of Well Operations _X 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISundry Number or N/A if C.O. Exempt: Contact DeWayne R. Schnorr I NIA Printed Name DeWayne R. Schnorr Title Techical Assistant Signature _,~-'~~,~/'.~/~~ Phone 907/564-5174 Date June16,2003 Form 10-404 Revi ,s~A~E[)' ;JUL 0 9 2003 ORi6iiiAL G-19A DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS 03/24/2003 TESTEVENT --- BOPD: 480, BWPD: 28, MCFPD: 18,360, AL Rate: 0 06/06/2003 PACKERS/BRTDGE PLUGS/POGLiVlS: CAST IRON BRIDGE PLUG; HILL 06/07/2003 PACKERS/BRIDGE PLUGS/POGLMS: HILL EVENT SUMMARY 03/24/03 TESTEVENT --- BOPD: 480, BWPD: 28, MCFPD: 18,360, AL Rate: 0 06/O6/O3 MIRU CTU #5 FOR MILLING CIBP. WEEKLY BOP TEST. RIH W/2 1/8" BAKER MOTOR & 2.30" THREE BLADE JUNK MILL. FIND CIBP @ 11863' CTM. MILL/PUSH TO 11890'. GOT STUCK ABOVE JARS. WORKED FREE. POOH. REMOVE MOTOR/MILL. INSTALL 2 1/8" VENTURI. RIH. 06/07/O3 RIH W/VENTURI. RUN VENTURI FROM 11300'. PUSH CIBP TO BOTTOM @ 12687' (UP CTM). POOH. STICKING @ 11604'. POOH. RECOVERED 5 + PARTIAL UPPER SLIPS SECTIONS + MISC MILLED METAL PARTS. RDMO. **JOB COMPLETE** FLUIDS PUMPED BBLS 38 METAHNOL WATER 59 50/50 METHANOL 375 2% EXTRA SLICK KCL WATER 100 CRUDE 572 TOTAL Page 1 ~B~--E~_'~E~- ~ 67.06' BF. ELEV = 40.41 ~OP = 2000' ~A~-e~-DatumMD= .......... ~'@ i;1'6~'11~0, t H I I t I-t I I 0-5~8" cs~,47#, C-80, ~D= 8.681" I--~ a0S*S' '-~ i · MILLOUT WINBOW 11253'-11259' PI~FO~TION SUMMA RY ' REF LOG: MWD GR ON 01/02~9 Note: Refer to R'oduclJon DB for historical perf data SIZE SPF INTERVAL OPN/SQZ DATE 2 6 11355-11375 O 02/13/02 I FBTD H 12691' ~ 2 6 11513 - 11535 O 02/13/02 2 6 11535-11560 0 02113102 2 i 4 11619-11830 0 11104199 2 4 11880-11970 O 11/04/99 I 2-?I8"L~R, 6.1C~,L-80,.OOS8bpf, ID= 2.441" ]~ '12758' I 2 4 12005 - 12045 O 11/04/@9 2 4 12170 - 12400 0 11/04l~ 2 4 12440 - 12529 0 11104199 2 4 12584 - 12642 O 11/04100 DA'I'I= RI=V BY ODMMI=NTS DAlI= R~t BY GOMMI~qTS Ft~UDHOI= BAY UNIT 08129/86 ORIGINAL COMPLETION WELL: G-19A '11104199 CTD SIDETRACK COMPL PERMIT No: 1991030 03/02/01 SIS-MD RNAL APINo: 50-029-21599-01 02/01/02 RN/TP CORRECTIONS SEC 12, T11N, R13E 02/17/02 JA F/TLH ADD PERFS 06/07/03 DBM/TLH MILL CIBP BP Exploration (Alas k a) PI~,FORATION SUMMA RY REF LOG: MWD GR ON 01/02/99 ANGLEATTOP PERF: 62° @ 11355' Note: Refer to R'oduclJon DB for historical perf data SIZE SPF INTERVAL OPN/SQZ DATE 2 6 11355 - 11375 O 02/13/02 2 6 11513 - 11535 O 02/13/02 2 6 11535 - 11560 O 02/13/02 2 4 11619 - 11830 O 11/04/99 2 4 11880 - 11970 O 11/04/99 2 4 12005 - 12045 O 11/04/99 2 4 12170-12400 O 11/04/99 2 4 12440 - 12529 O 11/04/99 2 4 12584 - 12642 O 11/04/99 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging_ Perforate _X Add Perfs Pull tubing _ Alter casing _ Repair well _ Other_ 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchorage, AK 99519-6612 4. Location of well at surface 3744' FNL, 3003' FEL, Sec. 12, T11N, R13E, UM At top of productive interval 474' FNL, 3622' FEL, Sec. 14, TllN, R13E, UM At effective depth 137' FNL, 3546' FEL, Sec. 14, T11 N, R13E, UM At total depth 359' FNL, 2761' FEL, Sec. 14, T11 N, R13E, UM 5. Type of Well: Development __X Exploratow__ Stratigraphic__ Service__ (asp's 657248, 5967883) (asp's 651394, 5965753) (asp's 651462, 5966091) (asp's 652252, 5965885) 6. Datum elevation (DF or KB feet) RKB 67 feet 7. Unit or Property name Prudhoe Bay Unit 8. Well number G-19A 9. Permit number / approval number 199-1030 10. APl number 50-029-21599-01 11. Field / Pool Prudhoe Bay Oil Pool 12. Present well condition summary Total depth: measured true vertical 12758 feet Plugs (measured) 9008 feet Effective depth: measured 11858 feet Junk (measured) true vertical 8989 feet CIBP set @ 11858' (01/08/2002) Casing Length Size Cemented Measured Depth True Vertical Depth Conductor 110' 20" 72 c.f. Concrete 137' 137' Surface 2676' 13-3/8" 3808 cf Permafrost 2703' 2641' Production 10568' 9-5/8" 575 cf Class 'G' 10595' 8387' Liner 912' 7" 448 cf Class 'G' 10341' - 11253' 8188' - 8869' Sidetrack Liner 2511' 2-7/8" 129 cf Class 'G' 10247' - 12758' 8114' - 9008' Perforation depth: measured Open Perfs 11355'-11375', 11515'-11560', 11619'-11830', 11880'-11970', 12005'-12045', 12170'-12400', 12440'-12529', 12584'-12642' true vertical Open Perfs 8924'-8934', 8989'-8993', 8990'-8990', 8988'-8991', 8994'-8997', 9006'-9009', 9011 '-9012', 9010'-9007' ~ " ....: ~i. '- " /' ~ ~ '. -'::1' Tubing (size, grade, and measured depth) 4-1/2", 12.6#, L-80TBG @ 10291'. SBRTBG SealASSY @ 10168'...'.;- ..::.i';.ii ,' ~i!~ !..~ Packers & SSSV (type & measured depth) 9-5/8" x 4-1/2" TIW Packer @ 10183'. 4-1/2" Otis SSSV Landing Nipple @ 2070'. 13. Stimulation or cement squeeze summary Intervals treated (measured) (see attached) Treatment description including volumes used and final pressure 14. Prior to well operation 02/11/2002 Subsequent to operation 02/16/2002 OiI-Bbl 371 704 Representative Daily Averaqe Production or Iniection Data Gas-Mcr Water-Bbl 21422 4 16045 22 Casing Pressure Tubing Pressure 775 279 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations __ 16. Status of well classification as: Oil __X Gas __ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. DeWayne R. Schnorr Date February 21, 2002 Prepared by DeWayne R. Schnorr 564-5174 Form 10-404 Rev 06/15/88 · SUBMIT IN DUPLIcATE%~ G-19A DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS 12/06/2001 MECH SET BRIDGE PLUGS: DRIFT 100' INTO 2 7/8 LINER. 01/07/2002 MECH SET BRIDGE PLUGS: MEM GR/CCL SET CIBP 01/08/2002 MECH SET BRIDGE PLUGS: MEM GR/CCL, SET CIBP AT 11858' 02/12/2002 PERFORATING: JEWELRY LOG--DEPTH CONTROL; PERFORATING 02/13/2002 PERFORATING: PERFORATING 02/14/2002 PERFORATING: PERFORATING EVENT SUMMARY 12/06/01 RAN 2.25 CENTRALIZER 100' INTO 2 7/8 LINER, 10445' WLM. RDMO. 01/07/02 MIRU CTU #1. RIG UP AND PRESSURE TEST SURFACE EQUIP. AMBIENT -42. SLOW PROGRESS DUE TO LOW ABMIENT TEMPERATURE. 01/08/02 BOP TEST. C/O STUFFING BOX. PU WFD 1-11/16" MHA & SCHLUMBERGER'S MEMORY GR/CCL TOOL STRING. KILL WELL DOWN BACKSIDE 185 BBLS KCL, WELL ON VACUUM. RIH. SWITCH TO CRUDE. PUMP 90 BBLS CRUDE. MEMORY LOG 12,100' UP TO 11,750'. FLAG PIPE AT 11,800. POOH. PU HALLIBURTON MODEL M CIBP. RIH. SET AT 11858'. TAG TO CONFIRM SET. POH. NOTIFY PAD OPERATOR TO POP WELL. 02/12/02 PU SLB MEMORY LOGGING TOOLS. RIH AND LOG FROM UP/DOWN PASS FROM 11200' TO TAG @ 11882'. PAINT FLAG @ 11200'. POOH. MU GUN #1:25 FT 2" POWER JETS, 6 SPF, RIH. TIE INTO FLAG. 02/13/O2 TAG CIBP, PULL TO DEPTH. DROP 0.5" BALL. SHOOT 11,535' - 11,560'. GUNS: 2" PJ HMX CHARGES, 6 SPF, --0.23" DIA., 18.6" PENE. PERFORM WEEKLY BOP TEST. SHOOT SECOND INTERVAL, 11,515' - 11,535' W/SAME TYPE GUNS. SHOOT THIRD INTERVAL, 11355' - 11375' W/SAME TYPE GUNS. POOH, BO GUNS. RIH TO PUMP DIESEL TO HELP BRING WELL ON. 02/14/02 PERFORATING COMPLETE, WELL NOT FLOWING. RIH TO 11,600', SWAP WELL OUT WITH DIESEL TO HELP BRING WELL ON. UNABLE TO GET WELL FLOWING, DECIDED TO LIFT WELL W/N2 AFTER UNSUCCESSFUL BACKFLOW. LIFT W/INITIAL 2,000 GAL OF N2, WELL PRODUCES - 190 BBLS FLUID. MONITOR UNASSISTED FLOW. WELL PRODUCING ON ITS OWN AFTER 1-1/2 HRS. FINAL SPOT RATES: Qo = 3450 BPD; Qg = 9.4 MMSCF/D; Qw = 650 BPD. WHP = 210 PSI. TEMP = 74 DEG. *** FLOWING WELL TURNED OVER TO PCC *** FLUIDS PUMPED BBLS 1 DIESEL FOR PRESSURE TESTING SURFACE PRESSURE CONTROL EQUIP 87 METHANOL Page 1 G-19A DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS 10 60/40 METHANOL WATER 225 METHANOL WATER 2OO DIESEL 9O CRUDE 440 2% KCL WATER 49 NITROGEN (2000 GALS) 1152 TOTAL 02/13/2002 ADD PERFS THE FOLLOWING INTERVALS WERE PERFORATED USING THE 2" POWER JET, LOADED 6 SPF, 60 DEGREES PHASING, RANDOM ORIENTATION. 11355' - 11375' 11515' - 11560' Page 2 Schlumberger Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 AT[N: Sherrie NO. 1716 Company: State of Alaska Alaska Oil & Gas Cons Corem Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay 01/14/02 Color Well Job # Log Description Date Blueline Sepia Prints CD G-19A //-~ (~ / O.~ 21505 MCNL 11/07/01 1 1 1 W-21A 21507 PP,IMP,ARC & DIN 11/10/01 1 W-21A ~, (~1- J! ) 21507 MDVISION RESISTIVITY 11/10/01 1 1 W-21A 21507 TVD VISION RESISTIVITY 11/10/01 1 1 W-21A 21507 MD VISION D/N 11/10/01 I 1 W-21A 21507 TVD VISION DIN 11/10/01 1 1 D.S. 7-16A d-~O)-I..~ 21520 PP,ARC 09/09/01 1 D.S. 7-16A 21520 MD VISION RESISTIVITM 09/09/01 1 1 D.S. 7-16A 21520 ~O VISION RESISTIVITY 09/09/01 1 1 , , PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center LR2-1 900 E. Benson BIvd. Anchorage, Alaska 99508 Date Delivered: RECEIVED JAN 1 5 200Z Alaska Oil & Gas Cons. Commissio. Anchorage Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATI'N: Sherrie Received b ~ld~~~ ~. ~fl~O.,~ Permit to Drill No. 1991030 DATA SUBMITTAL COMPLIANCE REPORT 2/5/2002 Well Name/No. PRUDHOE BAY UNIT G-19A Operator BP EXPLORATION (ALASKA) INC APl No. 50-029-21599-01-00 MD 12758 TVD 9008 Completion Date 11/4/1999 Completion Status l-OIL Current Status I-OIL UIC N ...................................................................................... ~-'::~'- ~:__~._.-_-:-_z:~:~:-_~::z:-_--::z_: ~ : ~.:: ::~_~-:---:~ ::~ :.-_-: z_:~-::::-_:.-_:~ . ~--:'._:~:_w:_:~_~:~:~:--- :~__~._z~r~-~-:~:_-_~-- :z-. REQLIIRED INFORMATION Mud Log No Samples N_~o Directional Survey No -- DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: (data taken from Logs Portion of Master Well Data Maint) Log/ Data Digital Digital Log Log Run Interval OH / Dataset Type Media Format Name Scale Media No Start Stop CH Received Number Comments R LIS Verification FINAL ~,~ ........ 2~2~2~0 ~ ..... I~ I' S -~-r i~-~a ~i-o-r~-~p ~.r - ~;-(~ p-~ ................ ~ ~ 5 ~...C~'~ 2/27/2001 09917~i1235-12733 D-'-' R~S~VY LSTNG OH 12/10/1999 SCHLUM 11200.-12578. '~E~ N U/GR/CCL 5 FINAL 11000 12625 CH 1/3/2001 BL, Sepia 19-- "~i~ SRVY RPT OH 12/10/1999 SPERRY 11200.-12578. Lo Press 2 BS final 11410 12705 Cas 11/27/2001 Lo Spin 2 BS final 11410 12705 Cas 11/27/2001 Lo Temp 2 BS final 11410 12705 Cas 11/27/2001 Lo Prod 2 BS final 11410 12705 Cas 11/27/2001 ~ J~._. Ne~u~' 2 BS final 11410 12705 Cas 11/27/2001 / TVD Natural GR 5 FINAL 8791 8941 oh 3/16/2001 BL, Sepia .... '~ MD ROP/Natural G ' 5 FINAL 9523 12763 oh 3/16/2001 BL, Sepia ~'"~' C 1/3/2001 09790--'"~'" 11012-12686 Interval Dataset Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y O Daily History Received? (~)/N Formation Tops Receuived? '~)/N DATA SUBMITTAL COMPLIANCE REPORT 2/5/2002 Permit to 1)rill No. 1991030 Well Name/No. PRUDHOE BAY UNIT G-19A Operator BP EXPLORATION (ALASKA) INC APl No. 50-029-21599-01-00 MD 12758 TVD 9008 Completion Date 11/4/1999 Completion Status 1-OIL Current Status I-OIL UIC N Comments: Sch umberBer Alaska Data & Consulting Services 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrie NO. 1638 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Lisa Weepie 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay, Niakuk Color Well Job # Log Description Date Blueline Sepia Prints CD G-19A /6j_~..-IO~ MEM PROD PROFILE 11/07/01 1 1 N-4A / ~.~-/j~-7 PROD PROFILE/DEFT/GHOST 11/16/01 1 1 D-04A / ~-~-/<~ 21461 EST 10/22/01 i 1 1 D.S. 15-41B c-~L3t-/~j'{o 21471 MCNL 10/08/01 1 1 1 D.S. 16-05A ~ l~.J~ .- ¢.~ t ~ 21475 MCCL (PDC) 03/07/01 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: 11/21/01 BP Exploration (Alaska)Inc. Petrotectnical Data Center LR2-1 900 E. Benson Bivd. Anchorage, Alaska 99508 Date Delivered: Schlumberger GeoQuest 3940 Arctic Blvd, Suite 300 Anchorage, AK 99503-5711 ATI'N: Sherrie MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Julie Heusser, Commissioner THRU: Tom Maunder, P. I. Supervisor FROM: Chuck Scheve; SUBJECT' Petroleum Inspector DATE: April 24, 2001 Safety Valve Tests Prudhoe Bay Unit G Pad Tuesday, Apr!! 24, 2001' I traveled to BPXs G Pad and witnessed the one-month retest of the safety valve systems. As the attached AOGCC Safety Valve System Test Report indicates I witnessed the testing of 16 wells and 32 components with no failures. The surface safety valve on well G-03Aclosed rather slowly but passed its pressure test. The wing valve on wells G-16 and G-18A had very slow leaks but did not prohibit a valid test of the surface safety valve. :WellG,21 which_.failed the previous months testdueIo-a frozen pilot, has-the new style insulation box in place and functioned properly. Merv Liddelow performed the testing today; he demonstrated good test procedures and was a pleasure to work with. A walk through inspection of the Well houses on this pad Was performed during the SVStesting with no problems noted. Well G-t4A which was shut in at this time and not tested was found to have the new style insulation box on the pilot. This should fix the Problems found on previous tests. Summary: I witnessed the one-month retest of the safety valve systems at BPXs G-Pad. .PBUG Pad, 16 Wells, 32 Components, Ofailures 22 wellhouse inspections Attachment: SVS PBU G Pad 4-24-01 CS X Unclassified Confidential (Unclassified if doc. removed ) Confidential SVS PBU G Pad 4-24-01 CS Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator: BPX Operator Rep: Merv Liddelow AOGCC Rep: Chuck Scheve Submitted By: Chuck Scheve Field/Unit/Pad: Prudhoe/PBU / G Pad Separator psi: LPS 174 Date: 4/24/01 HPS 720 Well Permit Separ Set L/P Test Test Test Date Oil, WAG, GIN J, Number Number PSI PSI TAp Code Code Code Passed GAS or CYCLE G-01A 1931710 720 550 530 P P P OIL G-02A 1950230 G-03A 1970700 174 125 100 P P P OIL G-04A 1951630 iG-05 1780970 720 550 525 P P P OIL G-06 1790120 G-07 1790180 174 125 110 P P P OIL G-08 1810480 G-09A 1982630 G-10A 1950390 G-11A 1931600 720i 550 540 P P P OIL G-12A 1961050 G-13 1810720 174 125 125 P P P OIL G-14A 1980530 G-15A 1981340 720 550 500 P P P OIL G-16 1811220 720 550 500 P P P OIL G-17 1810940 G-18A 1990320 720 550 550 P P P OIL G-19A 1991030 720 550 530 P P P OIL G-21 1951540 720 550 500 P P P OIL G-23A 1960200 720 550 510 P ~ P P OIL G-24 1861830 G-25 1861620 720 550 5101 P P P OIL G-26A 1981510 720 5501 500 P P P OIL G-27 1861560 720 550 525 P P P OIL G-29 1861600 G-30A 1950760 G-31A 1980540 720i 550 525 P P P OIL G-32A 1970010 90 Day RJF 1/16/01 Page 1 of 2 SVS PBU G Pad 4-24-01 CS Well Permit Separ Set L/P Test Test Test Date Oil, WAG, GINJ, Number Number PSI PSI Trip Code Code Code Passed GAS or CYCLE Wells: 16 Components: 32 Failures: 0 Failure Rate: 0.00% [-] 00 Day Remarks: Good Test. Surface safety Valve on Well G-03A closed slowly but passed its pressur test. The wing valve on wells G-16 and G-18A had very slow intemal leaks and will repaired by the Operator. RJF 1/16/01 Page 2 of 2 SVS PBU G Pad 4-24-01 CS To: WELL LOG TRANSMITTAL State of Alaska Alaska Oil and Gas Conservation Comm. Attn.' Lisa Weepie 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 March 14, 2001 MWD Formation Evaluation Logs · G-19A, AK-MW-90175 G-19A: lqq- toS 2" x 5" MD Gamma Ray Logs ' 50-029-21599-01 2" x 5" TVD Gamma Ray Logs · 50-029-21599-01 1 Blueline 1 Rolled Sepia 1 Blueline 1 Rolled Sepia PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY TRANSMITTAL LETFER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Jim Galvin 6900 Arctic Blvd. Anchorage, Alaska 99518 BP Exploration (Alaska) Inc. Petro-technical Data Center, LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 RECE,v D Signe~ 0o,%. Comrnissior~ Alaska Oil & Gas -',~ * Anchorage OF MEMORANDUM TO: THRU: Julie Heusser, Commissioner FROM: Tom Maunder. P. !. SUpervisor State of Alaska Alaska Oil and Gas Conservation Commission DATE: SUBJECT: JOhn crisp, Petroleum InSpectOr February 24, 2001 Safety Valve tests Prudhoe Bay Field F, G & J Pads February 24, 2.001- Commissioner Julie Heusser & mYself traveled to BP's Prudhoe Bay Field to witness miScellaneous safety valve tests. Merv Littlelow was Bp representative in charge of testing. Testing was done in a safe & efficient manner. Four cycle wells were teSted with three failures witnessed. The AOGCC test reports are attached for reference. Four wellhouses were inspeCted. SUMMARY: Julie HeUSSer & myself traVeled to BP's PBU to witness misc. SV$ tests. -4'Wells' 8 CompOnents tested. 3 failures witnessed. 37.5% failure rate. 4 wellhouses inspected. Attachments: Misc. sVS PBU F Pad 2-24~01jc MiSc. SVS PBU G pad 2-24-01jc Misc. SVS PBU J Pad;2-24-01jc cc; NON-CONFIDENTIAL Misc. SVS PBU 2-24-0 ljc Alaska Oil and Gas ConserVation Commission SafetY Valve System Test Report Operator: BPX Submitted By: John Crisp. Date: Operator ReP: Merv Littlelow Field/Unit/Pad: prudhoe Bay. i:ield F Pad AOGCC Rep: Heusser / Crisp Separator Psi: LPS HPS 2/24/01 660 i . i i i i i ii t i Well Permit Separ Set L/P Test Test Test Date o~ WAG, GI~J, Number Number PSI PSI Trip Code Code Code Passed GAS or CYCLE 0i' ' 1700460 ...... F- , F-02 1700560 F-03 1700580 , , F-04 17100201 F-05 1710090 ...... , , , F-06 1710120! . F_07 ,'1720230i ........ F-08 1740110 F-09 1790760i ., . , F-10A 2000670, . F-11A - 2000620: F-12 1791070 F-13A I 1961520 , , , F-14 1800120: , F-15 1811300 F-16A 1961600 F-17A 19416301 __ F-19 1811060' F221 1890560 ' " F-22 1890620 ...... F-23A 1990740 ........... , F-24 1831540 F-26A 1981890 F-27 1861690 F-28 1861590 , ,, , ,F-29 18613301 '~-30 1891100!' ' F-31 1861570 F-32 189O33O F-33 1960030! ' F-34A 1961090 F-35 1880810 F-36 1951960 F-37 18909~0 ....... , , ,, 3/12/01 Page 1 of 2 Misc. SVS PBU F Pad 2-24-01jc ii iii Well Pemit Separ Set L/P Test Test Test Date oa, WAG, GIN J, Number Number PSI PSI Trip Code Code Code Passed GAS or CYCLE I i i i I i. I i I F-S8 1901350 F'39 190'1410 ..... F40 1911170 F-41 1911040 F-42 1901580 F-43 1910750 F-44 1910080 F-45 1910286 ' 660 550 ~80 'P 1:; ' ' CYCLE F-46 19017'80 ''660 550 '320 3 P ' 2)24/01' ' ' ~2YCLE iF45A' 2066350 ........... i~-'48 1910860 ...... Wells: 2 4' Failures: 1 Failure Rate: 25.0%E3~0 var Remarks: Components: . , 3/12/01 page 2 of 2 Misc. SVS PBU F Pad 2-24-01jc Alaska Oil and Gas Conservation CommiSsiOn Safety Valve System Test Report Operator: BPx Operator Rep: MeTM LittleioW AOC~C Rep: Heusser / Crisp. Submitted By: John Crisp FieldfOnit/Pad: prUdh°e Ba,~, 'Field Separator psi: LPS Date: 2/24/01 HPS 670 Well Permit Separ Set L/P Test . Test Test Date oa, WAG, ..Number Number PSI PSI T,rip Code Code COde Passed GAS or CYCLE i i i i i i ii ii i i i i G-01~ '19313i0! " .... G-02 ,A 1950230 , G-03A 1~70700 ............. _.. G-04,_A 1951630 , G-05 17~0970 ............... G-06 '1'~96i20 ~ ' '7 ........ G-07 1790180! G-os '" 1810480! .................. ~-09A' :1982630". ....... ' ........ G-10A 1950390 G- 11A 1931600 G-12A 1961050 G-13 181:0720: ' G-143k ' "i98'0530~ " ' ' ' . ,, ~ G-15A 1981340: G-16 1811220: ' .............. .... G-17 1810940 .... [ ' " ' ' G-18A 1990320 . G~mA~I' ' , 19~}1,030 ,. 670 ' 550 540 'P 5 cYcLE G-21 1'951540 , I , , , , I, ,t ,1, , , ! ...... , ..... G723A ,,1960,200.......... G-24 1861830 " , G-25 18616201 ................. G-26A 1981510~ G-27 1861560: G-29 1'8616001 ........ · , ....... G-30A 1950760 ................ G.-31A " 1~80'540 " " ..... G-32A 1970010 Wells: 1 Components: 2 Failures: 1 Failure Rate: 50.0%[39o my Remarks: 3/12/01 page 1 of 2 Misc. SVS PBU G Pad 2-24-01jc Alaska Oil and Gas ConserVation Commission Safety Valve System Test RePort Operator: BPX Operator Rep: Merv Littlelow AOGCC Rep: Heusser / Crisp Submitted By: .John Crisp Field/Unit/Pad: .,Pm, dhoe Bay Field Separator psi: LPS Date: 2/24/01 lIPS 680 ii i . i i i ii i Well Permit Separ Set L/P Test Test Test Date Oil, WAG, GINJ, Number Number PSI pSI Trip Code Code Code Passed GAS or CYCLE I II J-01A 1941110 j..02A '1690~}70 .... J-06 1770200 J-07A 19608701 ...... J-08 1770470 ' ' J-09A 19409901 J- 10 1800160 J-11X 1961040 ' ' ~ ..... J-12 1800170 J-13 1800830 J- 14 1830750 J-15A 1981750 J-16 1830880 . J- 17A 1990920 J-18 1831080 Jzl'9: ' 1861350 680 " 550 '0 3 P 2/24/01 ' CYCLE J-20A 1961060 J-21 1870240 J-22A 2001240 J-23 1870310 J-24 1870020 J-25 1870680 J-26 [, 1870590 . " ' ' J-27 1870580 JX-02A 1941540 ...... Wells: Remarks: 1' CompOnents: 2 Failures:~ 1 Failure Rate: 50.0%U190 oar 3/12/01 Page 1 of 2 Misc. SVS PBU J Pad 2-24-0 ljc WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Comm. Attn.' Lisa Weepie 333 West 7t~ Avenue, Suite 100 Anchorage, Alaska RE: MWD Formation Evaluation Logs G-19A, AK-MW-90175 February 23,2001 1 LDWG formatted Disc with verification listing. AP1//: 50-029-21599-01 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY TRANSMITTAL LETTER TO THE ATI'ENTION OF: Sperry-Sun Drilling Services Attn: Jim Galvin 6900 Arctic Blvd. Anchorage, Alaska 99518 BP Exploration (Alaska) Inc. Petro-Technical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 OF Date' Signe~: (_~ ~Oo~r~..) Schlumberger GeoQuest (DCS) 3940 Arctic Bird, Suite 300 Anchorage, AK 99503-5711 ATTN: Sherrie NO. 708 Company: Field: Alaska Oil & Gas Cons Corem Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK 99501 Prudhoe Bay (Open Hole) 11/21/00 Well Job # Log Description Date BL Sepia CD G-19A 20032 CH EDIT McNL(PDC) ' ,. 991103 ., ' ,1 1 I ..... N-22A 20416 CH EDIT'R§T 000924 I i 1 , , ....... , , ,, , , , , ...... ....... .... , , PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotectnical Data Center MB3-3 900 E. Benson Blvd. Anchorage, Alaska 99519-6612 Date Delivered: Schlumberger GeoQuest 3940 Arctic BI 3940 Arctic Blvd, Suite 300 Anchorage, ~ Anchorage, AK 99503-5711 ATTN: Sherrie STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well [] Oil [] Gas [] Suspended [] Abandoned [] Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 199-103 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 . 50-029-21599-01 4. Location of well at surface 9. Unit or Lease Name 1535' NSL, 2276' EWL, SEC. 12, T11N, R13E, UM Prudhoe Bay Unit At top of productive interval } ~~..~".~'--}:i "~. . 11.10' Field andWell Numberpool 474' SNL, 3622' WEL, SEC. 14, T11N, R13E, UM G-19A At total depth 357' SNL, 2761' WEL, SEC. 14, T11N, R13E, UM _. Prudhoe Bay Field / Prudhoe Bay 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Pool KBE: 67.06' AMSL ADL 028285 12. Date Spudded10/29/99 113' Date T'D' Reached I 14' Date C°mp" Susp" °r Aband115' Water depth' if °fish°re 16' N°' °f C°mpleti°nsl 1/2/99 11/4/99 N/A MSL One 17. Total Depth (MD+TVD)I18. Plug Back Depth (MD+TVD)I19. Directional Survey t20. Depth where seeM set 121. Thickness of Permafrost 12758 9008 FT1 12691 9007 FTI [~Yes []No (Nipple) 2070' MD 1900' (Approx.) 22. Type Electric or Other Logs Run MWD, GE, ReP 23. CASING~ LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE WT. PER FT. GRADE TOP BO'FrOM SIZE CEMENTING RECORD AMOUNT PULLED 20" Insulated Conductor Surface 110' 26" 8 cu yds Concrete 13-3/8" 72# L-80 Surface 2703' 17-1/2" 3808 cuft Permafrost 9-5/8" 47# L-80 Surface 10595' 12-1/4" 575 cuft Class'G' 7" 26# L-80 10341' 11253' 8-1/2" 448 cuft Class 'G' 2-7/8" 6.16# L-80 10247' 12758' 3-3/4" 129 cuft Class 'G' 24. Perforations open to Production (MD+TVD of Top and 25. TUBING RECORD Bottom and interval, size and number) S~ZE DEPTH SET (MD) PACKER SET (MD) 2" Gun Diameter, 4 spf 4-1/2", 12.6#, L-80 10291' 10183' MD TVD MD TVD 11619' - 11830' 8990' - 8990' 11880' - 11970' 8988' - 8991' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 12005'- 12045' 8994' - 8997' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 12170' - 12400' 9006'- 9009' 2000' Freeze Protect with 30 Bbls of MeOH 12440'- 12529' 9011'- 9012' 12584'- 12642' 9010'- 9007' 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) November 11, 1999! Flowing Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE J GAS-OIL RATIO I TEST PERIOD Flow Tubing Casing Pressure CALCULATE OIL-BBL iGAS-MCF WATER-BBL OIL GRAVITY-APl (CORE) Press. D 24-HOUR 28. RATE CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. - _ Form 10-407 Rev. 07-01-80 Submit In Duplicate 29. Geologic Markers 30. Formation Tests Measured True Vertical Include interval tested, pressure data, all fluids recovered and Marker Name Depth Depth gravity, GOR, and time of each phase. 21N 11372' 8932' 21P 11378' 8935' 14N / 14P 11424' 8956' 13N 11975' 8991' 13P 12167' 9006' 31. List of Attachments Summary of Daily Drilling Reports, Surveys 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~'~',/(" ~ Te,rie Hubble -.. _/~, , .... Title Technical Assistant III Date G-19A 199-103 Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Permit No. / Approval No. iNSTRUCTIONS GEN£R,~.: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1 .' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5.' Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). ITEM 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27'; Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. IT£rd 28: If no cores taken, indicate 'none'. RECEIVF_.D Form 10-407 Rev. 07-01-80 10 1999 AIi 'Oil & GaS Cons. Com n Well: G-19A Accept: 10/26/99 Field: Prudhoe Bay Spud: 10/29/99 APl: 50-029-21599-01 Release: 11/04/99 Permit: 199-103 CTD Unit: Nordic #1 10/26/99 1 Move Nordic Rig #1 from J Pad to G-19a. Accept rig on G-19A at 04:00 hrs, 10/26/99. Nipple up BOPE. 10/27/99 2 11253' Position green tank. M/U hardline. Tested BOPE. Fax'd Test report to AOGCC offices. Checked SITP: 1780 psi. Bullheaded 225 bbls SW to kill well. RIH with cementing BHA #1. Tag whipstock on depth. Pull up to 11130 ft. Circulate well. Batch 32 bbls, 15.8 PPG, "G" CMT. CMT at wt at 15:45 hrs. Safety Meeting. Press test cement line. Stage 32.2 bbls, 15.8 PPG, "G" CMT. Close Choke. Displace with Seawater. Squeezed 5 bbls CMT out and had 800 psi SQZ pressure. Laid in 14 bbls at 1.1 BPM. WCTOC at 10,750 ft. Pull to 10400 ft. Held 30 minute, 1500 psi Squeeze pressure test. Good Test. Bleed off WHP to zero. RIH circulating Biozan to nozzle. Cleanout cement to 20' above whipstock. POOH jetting cement to surface. LD cementing BHA. MU milling BHA. RIH with 3.80" dimple mill and motor. Mill XN nipple at 10267'. Drill firm cement from 11230-11253'. Attempt to mill window and made little progress. POOH to check BHA. 10/28/99 3 11253' POOH. Check BHA for leaks. None found. Change out motor and mill. RIH with BHA #3. Tag whipstock on depth. Start milling window. Flag CT at 11253.4 ft. Stacking wt with only a total of 2 stalls. Steady motor work but no progress. Circulate high viscosity sweep to clean hole. 400 psi motor work with 3.5K WOB. Slow stall, pick up, set down with only 80 psi motor work. POOH. Found Baker Lockable Swivel had parted. Top of fish is 3.125" OD. Fish = 81.4 ft long, setting on bottom. Rig up slickline unit and RIH with overshot and 3.125" grapple. Unable to get by sliding sleeve. POOH. LD WL unit. WO WL crew to rest while turning down overshot OD at Baker machine shop. 10/29/99 4 11259' Halco WL RIH with 3.78" OD overshot with 3.125" grapple on 0.125" wire. Safety Meeting. Bait fish. Shear off and-POOR. R/U braided line equipment. Held Safety Meeting with all personnel. RIH with BL fishing tools. Latch fish, jar up once, pull fish free and POOH with fish. Recover 100% of milling BHA. R/D wireline unit. Held rig evacuation drill. All personnel accounted for. M/U milling BHA #4 (3.80" dimple mill). RIH. Tag whipstock and correct depth to 11253.5 ft. Mill window from 11253.5-11259'. POOH. RIH with BHA #5 (3.625" formation mi11/3.80" string reamer). Dress window to 11259' and had no more progress. POOH to check BHA. Found formation mill cored due to prior run not cutting completely thru casing. RIH with BHA #6 (3.80" bullnose formation mi11/3.80" string reamer). RECEIVED 1999 G-19A, Coil Tubing Drilling Page 2 10/30/99 5 11376' RIH with 3.80" formation mill and string reamer. Tag TD. Correct depth to 11,259 ft. Mill window. Several stalls milling first foot. Mill to 11,262 ft. Stacking wt. Unable to mill further. Displace well to FIoPro. POOH. Lay out milling BHA. Formation mill was bald from milling formation. Cut off 13 ft. of CT. M/U DS CTC. Pull/press test. M/U MWD building assembly, with 2.9 Deg. motor and M-09 Bit #1. RIH. Shallow test MWD. RIH. Tag TD at 11,264 ft. Correct CTD to 11,262 ft. Orient TF to 30R. Drill formation to 11,301' and had high circ pressure. POOH. Found motor stator failure. Change motor. RIH with BHA #8. Drill from 11301-11376' building angle and turning right. Could not get non locking orientor to hold desired tool face. POOH for orientor. 10/31/99 6 11500' OOH. Change bit and orientor. RIH with BHA #9. Tag TD. Drill to 11384 ft. Pull to liner and orient. RIH. Drilled to 11402 ft. Pull to liner and orient. RIH. Drill to 11406 ft. POOH. Change out Sperry MWD. Increase motor bend to 3.2 deg. and change to Radius 30 deg. locking orientor. RIH and shallow test. RIH to TD. Drilled to 11439 ft. Pull to liner to orient. No luck. Pull into 9 5/8" liner and got 2 clicks. RIH to window and oriented OK. RIH to TD. Drill to 11447' and could not hold necessary TF or get reactive. POOH. Change back to Sperry orientor. Change motor to 1.6° short radius. RIH with BHA #11. Drill from 11447-500' getting planned build and turn. POOH. Adjust motor to 2.9°. RIH with BHA #12. Could not get TF needed to land. POOH. 11/01/99 7 12089' POOH to change BHA. M/U Radius Orientor [Locking, 30 deg.]. Function test Orientor - OK. Adjust short radius motor to 2.1 deg. bend. M/U Bit #3 [Smith, M-26]. RIH with BHA #13. Tag TD at 11500 ft and Orient TF. Drill build section from 11500 - 11560 ft. Landed well at 8926 ft TVDSS at 11555 ft BKB. Drilled horizontal section to 11,675 ft. Short trip to window. Tied-in with BHCS/GR of 6-20-86. No depth correction. RIH to TD. Drilled horizontal hole to 11,843 ft. POOH for less motor. LD drilling BHA. Cut off 300' CT. Change MWD and bit, adjust motor to 0.9°. RIH with BHA #14. Drill from 11843-12048' dropping angle as planned and continuing right turn. Wiper trip to window. Orient to left to maximize length in polygon. Drill ahead from 12048' (8928' TVD). 11/02/99 8 12750' Orient TF. Drill horizontal hole to 12,146 ft. Back ream 100 ft. Drill to 12,205 ft. Short trip to window. Overpull at 11,900 ft. Pull to window. Tied-in with BHCS/GR at 11,265 ft. Added 9 ft to CTD. RIH. Sat down at 11,880 ft. Ream thru tight interval. Back ream. RIH to TD. Drilled horizontal hole to 12,225 ft. Orient TF to left side. Drilled to 12,345 ft. Short trip to window. Minimal overpull. RIH to TD. Drilled to 12,390 ft. Orient TF. Overpull and stuck pipe while orienting 100 ft off bottom. Work stuck pipe a total of 9 times to max. pull. Circulate 30 BBLS of dead crude. Spot 10 bbls dead crude in open hole. Hold 50K up wt. CT popped free after 3 min. soak. Circulate out dead crude and discard. Made short trip to window. Tied-in with GR at 11,265 ft. Add 14.0'. Drill from 12390-509'. Wiper trip to window. Drill from 12509-641' Wiper trip to window. Drill from 12641-750'. At end of polygon. Wiper trip to window. G-19A, Coil Tubing Drilling Page 3 11/03/99 9 12758' POOH to run liner. Final corrected TD is 12,758 ft BKB. LD drilling BHA. Safety Meeting. Run 80 jts of 2-7/8", 6.16#, STL, L-80 Liner. M/U Baker 6 ft deployment sleeve and CTLRT. RIH with liner on CT to TD. Release from liner. Displace FIo Pro mud to 2% KCI water. With KCI at shoe, saw losses of 1.0 BPM but slowed to 0.1 BPM. Held Safety Meeting with cementers. Mix and pump 23 bbls Class G cement. Bumped plug at correct displacement. Est 2 bbls cement lost to formation. Floats holding. Circulate at top of liner. POOH. LD liner running tools. MU 80 its of 1-1/4" CSH on nozzle. RIH. Wash to PBTD - clean. Full returns. POOH. 11/04/99 10 12758' Finish POOH with CT. Stand back 40 stands of CSH workstring. LD cleanout BHA. MU SWS memory GR/CNL. MU 40 stands CSH. RIH on CT. Log down and up pass at 30'/min from 11000'-PBD. Leave fresh FIo Pro mud in liner. POOH. LD memory CNLtools. Data showed near count malfunction. Call for perf guns. PT well to 1500 psi. Lost 100 psi in 30 min. Hold safety meeting with perf crew. MU and RIH with 2" HSD 2006 PJ, 4 SPF, 60 deg guns. Tag PBTD and correct depth. Drop ball and displace to seat. Pressure up to fire guns. Lost 4 bbls. POOH. Perf'ed intervals: 11619' - 11830', 11880' - 11970', 12005' - 12045', 12170' - 12400', 12440' - 12529', 12584' - 12642' 11/05/99 11 12758' Finish POOH with CT. Standback CSH workstring. LD perf guns, all shots fired. Load out perf guns. RIH with nozzle and freeze protect wellbore with 2000' with MeOH. Secure well. Blowdown CT with N2. Vac pits, slop tank. ND BOPE, NU tree cap and pressure test. Rig released at 1700 hrs, 11/04/99 (9 days, 13 hours). RECEIVED 1999 B.P. Explor Structure : Pad 6 We~l : 6-19A, 50-029-21599-0 Field : Prudhoe Bay Location : North Slope, Alaska <- West (feet) Date platted: 5-0ec-1999 Plot Reference is C-19A, Coordinotee are in feet reference G-fg. True Vertical Depths are reference RKB - MSL = 67,1 ft. Orij Potnis 267-6613 --- Baker Hugha~ INTEO --- 6500 6200 6100 6000 5900 5800 5700 5600 5500 5400 5500 5200 5100 5000 4900 4800 4700 I I I t I I I I t I I I I I t J I I I I I I I I I I I I I I I I I 8500- 8400 8500 -i.-- (D 8600 8700 ._ :>. 8800 I-- 8900 I V 1300 9000- _ 400 500 200 100 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 Vertical Section (feet) -> 'Azimuth 67.18 with reference 2025.44 S, 5722.31 W from G-19 1400 1500 RECEIVED ORIGINAL Ala,~ Oi! & Gas Cons. Com~ 2000 ~2100 2200 Projected to ID L C-lgA Cosel03 Plan J 1600 (./) 0 -..i- 1700 ~ 1800 ~D I 19oo V B.P. Exploration (True) Pad G G-19A Prudhoe Bay North Slope, Alaska SURVEY LISTING by Baker Hughes INTEQ Your ref : G-19A Our ref : svy247 License : 50-029-21599-01 Date printed : 3-Dec-1999 Date created : il-Nov-1999 Last revised : 3-Dec-1999 Field is centred on 708179.340,5930615.440,999.00000,N Structure is centred on 655005.320,5966300.878,999.00000,N Slot location is n70 19 8.343,w148 43 30.766 Slot Grid coordinates are N 5967882.960, E 657247.670 Slot local coordinates are 1535.56 N 2274.70 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North RECEIVED Oil & Gas Cons. Com Anchorage REC tV D B.~. ~.xplorat±on (?rue) Pad G, G- 19A Prudhoe Bay,North Slope, Ala~s~~'''~-:' - '' Measured Inclin Azimuth Subsea R E C T A N G U L A R Depth Degrees Degrees Depth C 0 0 R D I N A T E S SURVEY LISTING Page 1 Your ref : G-19A Last revised : 3-Dec-1999 Dogleg Vert G R I D C 0 0 R D S' Deg/100ft Sect Easting Northing 11200.00 46.20 253.00 8765.87 2025.44S 5722.31W 1.56 0.00 651568.81 5965739.97 11250.00 46.90 252.54 8800.26 2036.20S 5756.98W 1.55 -36.13 651534.37 5965728.50 11280.95 55.86 262.91 8819.59 2041.19S 5780.55W 38.97 -59.79 651510.91 5965723.03 11328.80 61.26 276.49 8844.62 2041.26S 582!.22W 26.68 -97.30 651470.26 5965722.11 11342.23 61.92 279.86 8851.01 2039.58S 5832.90W 22.61 -107.42 651458.54 5965723.55 11375.33 61.52 289.53 8866.72 2032.20S 5861.05W 25.75 -130.51 651430.24 5965730.35 11425.61 64.16 312.74 8889.92 2009.21S 5898.91W 41.34 -156.48 651391.92 5965752.55 11460.11 66.27 324.86 8904.43 1985.68S 5919.47W 32.46 -166.31 651370.88 5965775.65 11490.58 71.37 333.30 8915.45 1961.32S 5934.02W 30.76 -170.27 651355.84 5965799.70 11518.08 79.50 336.67 8922.36 1937.22S 5945.25W 31.85 -171.27 651344.11 5965823.56 1155~.26 87.45 340.16 8926.02 1907.52S 5956.99W 26.95 -170.58 651331.76 5965853.01 11587.88 94.57 353.01 8925.35 1871.03S 5965.70W 39.03 -164.45 651322.30 5965889.31 11622.08 94.92 3.54 8922.52 1837.01S 5966.72W 30.70 -152.20 651320.57 5965923.30 11648.38 92.55 11.62 8920.80 1811.02S 5963.26W 31.95 -138.93 651323.50 5965949.35 11685.01 88.07 25.16 8920.60 1776.35S 5951.74W 38.93 -114.86 651334.31 5965984.25 11727.01 88.33 37.46 8921.93 1740.56S 5929.96W 29.28 -80.91 651355.33 5966020.49 11755.79 86.22 46.60 8923.30 1719.23S 5910.74W 32.56 -54.92 651374.11 5966042.21 11804.48 91.76 61.90 8924.16 1690.88S 5871.36W 33.40 -7.63 651412.90 5966071.36 11839.61 94.75 69.28 8922.16 1676.40S 5839.45W 22.63 27.40 651444.50 5966086.50 11881.56 88.59 74.20 8920.94 1663.27S 5799.66W 18.79 69.17 651484.01 5966100.44 11911.06 88.68 77.72 8921.64 1656.12S 5771.05W 11.93 98.31 651512.46 5966108.18 11950.21 87.80 84.92 8922.85 1650.22S 5732.39W 18.52 136.23 651550,98 5966114.88 11986.71 85.34 91.78 8925.03 1649.16S 5696.00W 19.93 170.18 651587,34 5966116.68 12024.21 85.25 99.86 8928.11 1652.95S 5658.85W 21.48 202.96 651624,56 5966113.66 12062.71 84.73 104.08 8931.48 1660.90S 5621.34W 11.00 234.45 651662.22 5966106.49 12095.86 85.17 98.28 8934.40 1667.30S 5588.96W 17.48 261.81 651694.73 5966100.76 12123.63 86.92 95.65 8936.31 1670.66S 5561.46W 11.36 285.85 651722.29 5966097.97 12149.58 86.75 89.32 8937.75 1671.78S 5535.59W 24.36 309.27 651748.17 5966097.38 12188.78 86.04 85.27 8940.21 1669.94S 5496.52W 10.47 345.99 651787.20 5966100.03 12226.56 89.47 77.36 8941.70 1664.24S 5459.24W 22.80 382.57 651824.35 5966106.50 12266.08 91.76 80.53 8941.27 1656.66S 5420.46W 9.89 421.25 651862.96 5966114.87 12296.58 90.97 84.75 8940.55 1652.76S 5390.23W 14.07 450.63 651893.10 5966119.40 12327.48 89.03 91.43 8940.55 1651.73S 5359.36W 22.51 479.48 651923.94 5966121.07 12357.48 89.12 96.35 8941.03 1653.76S 5329.44W 16.40 506.26 651953.89 5966119.65 12389.66 87.71 101.97 8941.92 1658.88S 5297.70W 18.00 533.54 651985.73 5966115.19 12422.18 87.36 107.60 8943.32 1667.17S 5266.30W 17.33 559.27 652017.29 5966107.55 12455.61 86.48 112.17 8945.12 1678.52S 5234.92W 13.90 583.79 652048.90 5966096.85 12485.86 90.44 114.63 8945.93 1690.53S 5207.17W 15.41 604.71 652076.88 5966085.42 12532.36 91.32 123.42 8945.21 1713.06S 5166.56W 19.00 633.40 652117.95 5966063.73 12571.48 94.48 131.86 8943.23 1736.90S 5135.65W 23.01 652.65 652149.34 5966040.54 12602.78 92.90 138.18 8941.22 1758.98S 5113.58W 20.77 664.42 652171.86 5966018.92 12632.33 90.35 144.34 8940.38 1782.01S 5095.11W 22.55 672.52 652190.80 5965996.28 12650.83 90.18 146.27 8940.29 1797.22S 5084.58W 10.47 676.33 652201.64 5965981.30 12684.83 90.00 152.07 8940.24 1826.40S 5067.16W 17.07 '681.06 652219.66 5965952.48 12716.33 89.21 156.11 8940.46 1854.73S 5053.40W 13.07 682.76 652234.00 5965924.45 12758.00 89.21 156.11 8941.03 1892.82S 5036.53W 0.00 683.54 652251.66 5965886.71 Ail data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from G-19 and SSTVD from RKB - MSL = 67.1 ft. Bottom hole distance is 5380.46 on azimuth 249.40 degrees from wellhead. Vertical section is from tie at S 2025.44 W 5722.31 on azimuth 67.18 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ B.P. Exploration True) Pad G, G- 19A Prudhoe Bay,North Slope, Alaska MD SSTVD Rectangular Coords. 11200.00 8765.87 2025.44S 5722.31W 12758.00 8941.03 1892.82S 5036.53W SURVEY LISTING Page 2 Your ref : G-19A Last revised : 3-Dec-1999 Comments in wellpath Comment Tie-in Point Projected to TD NO Targets associated with this wellpath RECEIVED 1999 All CXl&Gas , n North Slope Alaska Alaska State Plane 4 PBU WOA G Pad G-19A Surveyed: 2 November, 1999 ORIGINAL SURVEY REPORT RECEIVED ~': :'"' 10 1999 8 December, 1999 '" Alaska 0il & Gas Cons. Comm~ An~or~e Your Fleh API-5OO2g£1$gg01 Surfece ¢oordinetes: 5g~7883.57 N, ~57£47.1~ E (70° lg' 08.3492' N, 148° 43' 30.7807" W) Kelly Bushing: ~7.0~t ebove Mean See Level DRILLING SERVICES Survey Ref: svy9494 A IIAI.I,IBI~I~TObl COMPANY Sperry-Sun Drilling Services Survey Report for G- 19A Your Ref: API-500292159901 Surveyed: 2 November, 1999 North Slope Alaska Measured Depth (ft) Incl. Sub-Sea Depth (ft) Vertical Local Coordinates Depth Northings Eastings (ft) (ft) (ft) 11200.00 46.200 253,007 8765.91 8832.97 11250.00 46.900 252.560 8800.30 8867.36 11280.95 55.860 262.930 8819.63 8886.69 11328.80 61.260 276.510 8844.66 8911.72' 11342.23 61.920 279.880 8851.05 8918.11 11375.33 61.520 289.550 8866.76 8933.82 11425.61 64.160 312.760 8889.96 8957.02 11460.11 66.270 324.880 8904.47 8971.53 11490.58 71.370 333.320 8915.49 8982.55 11518.08 79.500 336.690 8922.40 8989.46 11550.26 87.450 340.180 8926.06 8993.12 11587.88 94.570 353.010 8925.39 8992.45 11622.08 94.920 3.560 8922.56 8989.62 11648.38 92.550 11.640 8920.84 8987.90 11685.01 88.070 25.180 8920.64 8987.70 11727.01 88.330 37.480 8921.97 8989.03 11755.79 86.220 46.620 8923.34 8990.40 11804.48 91.760 61.920 8924.20 8991.26 11839.61 94.750 69.300 8922.20 8989.26 11881.56 88.590 74.220 8920.98 8988.04 11911.06 88.680 77.740 8921.68 8988.74 11950.21 87.800 84.940 8922.89 8989.95 11986.71 85.340 91.800 8925.07 8992.13 12024.21 85.250 99.880 8928.15 8995.21 12062.71 84.730 104.100 8931.52 8998.58 2024.70 S 5722.57W 2035.45 S 5757.24W 2040.43 S 5780.82W 2040.49 S 5821.48W 2038.80 S 5833.17W 2031.42 S 5861.32W 2008.41 S 5899.17W 1984.88 S 5919.72W 1960.51S 5934.26W 1936.41S 5945.48W 1906.70 S 5957.21W 1870.21 S , 5965.91W 1836.19 S 5966.93W 1810.20 S 5963.46W 1775.54 S 5951.92W 1739.75 S 5930.14W 1718.43 S 5910.90W 1690.10 S 5871.51W 1675.62 S 5839.60W 1662.51S 5799.80W 1655.37 S 5771.19W 1649.48 S 5732.54W 1648.44 S 5696.14W 1652.24 S 5658.99W 1660.20 S 5621.48W Alaska State Plane 4 PBU_WOA G Pad Global Coordinates Northings Eastings (ft) (ft) Dogleg Vertical Rate Section (°/100ft) (ft) Comment 5965739.43 N 651568.26 E 6069.06 5965727.96 N 651533.82 E 1.543 6105.29 5965722.49 N 5965721.58 N 5965723.O2 N 5965729.81N 5965752.02 N 5965775.12 N 5965799.17 N 5965823.O4 N 5965852.49 N 5965888.79 N 5965922.78 N 5965948.84 N 5965983.74 N 5966O19.97 N 5966041.70 N 5966O70.84 N 5966085.98 N 5966099.93 N 5966107.67 N 5966114.36 N 5966116.17 N 5966113.14 N 5966105.97 N 651510.35 E 38.969 6129.12 651469.70 E 26.683 6167.20 651457.98 E 22.611 6177.55 651429.68 E 25.749 6201.30 651391.36 E 41.341 6228.64 651370.32 E 32.462 6239.60 651355.27 E 30.765 6244.64 651343.55 E 31.850 6246.67 651331.20 E 26.949 6247.21 651321.73 E 38.980 6242.52 651320.00 E 30.759 6231.51 651322.93 E 31.952 6219.12 651333.74 E 38.926 6196.13 651354.77 E 29.278 6163.14 651373.55 E 32.557 6137,64 651412.34 E 33.404 6090.81 651443.94 E 22.633 6055.84 651483.45 E 18.786 6013.97 651511.91E 11.933 5984.68 651550.43 E 18.519 5946.42 651586.80 E 19.933 5911.99 651624.02 E 21.475 5878.55 651661.68 E 11.002 5846.24 RECEIVED r-=-£ 30 ]999 Tie-On Survey Window Point (top of Whipstock) . MWD Magnedc Continued... 8 December, 1999 - 7:31 -2- ~ 011 & Gas Cons. Commission /~0rage DrillQuest Sperry-Sun Drilling Services Survey Report for G- 19A Your Ref: API-500292159901 Surveyed: 2 November, 1999 North Slope Alaska Measured Depth (ft) Incl. Azim. Sub-Sea Depth (ft) Vertical Local Coordinates Global Coordinates Depth Northings Eastings Northings Eastings (ft) (ft) (ft) (ft) (ft) 12095.86 85.170 98.300 8934,44 9001.50 12123.63 86.920 95.670 8936.35 9003.41 12149.58 86.750 89.340 8937,79 9004.85 12188.78 86.040 85.290 8940.25 9007.31 12226.56 89.470 77.380 8941,74 9008.80 12266.08 91.760 80.550 8941,31 9008.37 12296.58 90.970 84.770 8940,59 9007.65 12327.48 89.030 91.450 8940.59 9007.65 12357.48 89.120 96.370 8941.07 9008.13 12389.66 87.710 101.990 8941.96 9009.02 12422.18 87.360 107.620 8943.36 9010.42 12455.61 86.480 112.190 8945.16 9012.22 12485.86 90.440 114.650 8945.97 9013.03 12532.36 91.320 123.440 8945.25 9012.31 12571.48 94.480 131.880 8943.27 9010.33 12602.78 92.900 138,200 8941.26 9008.32 12632.33 90.350 144.360 8940.42 9007.48 12650.83 90.180 146.290 8940.33 9007.39 12684.83 90.000 152,090 8940.28 9007.34 12716.33 89.210 156.130 8940.50 9007.56 12758.00 89.210 156,133 8941.07 9008.13 1666.61S 5589.11W 1669.98 S 5561.61W 1671.11S 5535.74W 1669.28 S 5496.67W 1663.60 S 5459.38W 1656.03 S 5420.60W 1652.14 S 5390.37W 1651.12 S 5359.50W 1653.17 S 5329.59W 1658.30, S 5297.85W 1666.59 S 5266.45W 1677.96 S 5235.07W 1689.97 S 5207.33W 1712.52 S 5166.72W 1736.37 S 5135.82W 1758.46 S' 5113.76W 1781.49 S 5095.30W 1796.70 S 5084.77W 1825.89 S 5067.37W 1854.22 S 5053.61W 1892.33 S 5036.76W Dogleg Rate (°/100ft) Alaska State Plane 4 PBU_WOA G Pad Vertical Section (ft) 5966100.24 N 651694.19 E 17.479 5818.18 5966097~45 N 651721.75 E 11.357 5793.63 5966096.86 N 651747.64 E 24.365 5769.81 5966099.51N 651786.66 E 10.469 5732.59 5966105.97 N 651823.82 E 22.803 5695.69 5966114.34 N 651862.43 E 9.895 5656.72 5966118.87 N 651892.58 E 14.072 5627.05 5966120.54 N 651923.42 E 22.510 5597.80 5966119.12 N 651953.37 E 16.401 5570.51 5966114.65 N 651985.21 E 17.999 5542.60 5966107.02 N 652016.78 E 17.330 5516.13 5966096.31N 652048.39 E 13.902 5490.75 5966084.88 N 652076.37 E 15.409 5469.01 5966063.19 N 652117.44 E 18.995 5438.93 5966040.00 N 652148.84 E 23.009 5418.39 5966018.37 N 652171.35 E 20.772 5405.51 5965995.73 N 652190.30 E 22.552 5396.32 5965980.74 N 652201.14 E 10.473 5391.82 5965951.92 N 652219.15 E 17.067 5385.79 5965923.89 N 652233.49 E 13.068 5382.88 5965886.14 N 652251.15 E 0.007 5380.50 Comment Projected Survey RECEIVED ?',~-."~ 30 1999 Oil & Gas Cons. Continued... 8 December, 1999- 7:31 - 3 - ~tJ~(~O~(~ OrillQuest Sperry-Sun Drilling Services Survey Report for G-19A Your Ref: A PI-500292159901 Surveyed: 2 November, 1999 North Slope Alaska Alaska State Plane 4 PBU_WOA G Pad All data is in feet unless otherwise stated. Directions and coordinates are relative to True North. Vertical depths are relative to Well Reference. Northings and Eastings are relative to Well Reference. The Dogleg Severity is in Degrees per 100ft. Vertical Section is from Well Reference and calculated along an Azimuth of 249.409° (True). Based upon Minimum Curvature type calculations, at a Measured Depth of 12758.00ft., The Bottom Hole Displacement is 5380.50ft., in the Direction of 249.409° (True). Comments Measured Station Coordinates Depth TVD Northings Eastings Comment (ft) (ft) (ft) (ft) 11200.00 8832.97 2024.70 S 5722.57 w Tie-On Survey 11250.00 8867.36 2035.45 S 5757.24 W Window Point (top of Whipstock) 12758.00 9008.13 1892.33 S 5036.76 W Projected Survey RECEIVED 10 1999 Continued... 8 December, 1999 - 7:31 - 4 - DrillQuest Sperry-Sun Drilling Services Survey Report for G- 19A Your Ref: A PI-500292159901 Surveyed: 2 November, 1999 North Slope Alaska Alaska State Plane 4 PBU_WOA G Pad Survey tool program From Measured Vertical Depth Depth (ft) (ft) 0.00 0.00 11250.00 8867.,36 To Measured Depth (ft) 11250.00 12758.00 Vertical Depth (ft) 8867.36 9008.13 Survey Tool Description AK-1 BP_HG - BP High Accuracy Gyro MWD Magnetic RECEIVED [',::~ 10 i999 8 December, 1999 - 7:31 - 5- DrillQuest G-19A Permit to Drill Rush ~-"~. ~ . Subject: G-19A Permit to Drill Rush Date: Mon, 25 Oct 1999 13:37:57 -0400 From: "Hubble, Terrie L (NANA)" <HubbleTL~BP.com> To: "'Diana (AOGCC) Fleck'" <Diana Fleck~admin.state.ak.us> Hi Diana, We need to get this Permit to Drill approved as soon as possible. The work on the well Nordic 1 is currently on (J-17A) went better than expected and will be finished today. Unfortunately, this means that if the Permit to today or tomorro~, the rig will have to go Drillto standby, for G-19A is not received~0~2 We are sorry for the inconvenience that this may cause, but need to request whatever expediting services you can employ. Thank you. Additionally, this also means that the well scheduled after G-19A will also need to be pushed forward. N-liB was scheduled to spud on 11/10/99, but the 4th of November seems a more likely spud date at this time. 1 of 1 10/_25/99 9:44 AM TONY KNOWLES, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 October 26. 1999 Ted Stagg CT Drilling Engineer BP Exploration (Alaska) Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bav Unit G- 19A BP Exploration (Alaska) Inc. Permit No: 199-103 Sur Loc: 1535'NSL. 2276'EWL. Scc. 12. Tl lN. RI3E. UM Btmholc Loc. 201'SNL. 2767'WEL. Sec. 14. T11N. R13E. UM Dear Mr. Stagg: Enclosed is thc approved application for permit to rcdrill thc above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention cquipmcnt (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a represcntative of thc Commission to witness a test of BOPE installed prior to drilling new hole. Notice mav be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Robert N. Christenson. P. E. Chairman BY ORDER OF THE COMMISSION dlffEnclosurcs CC: Department of Fish & Game. Habitat Section ~v/o encl. Department of Environmental Conservation w/o cncl. STATE OF ALASKA ALASK/- ~L AND GAS CONSERVATION COM. $SION /'"'-' ~'~ PERMIT TO DRILL 20 AAC 25.005 la. Type of work [] Drill [] Redrill Ilb. Type of well [] Exploratory [] Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenI [] Service [] Development Gas [] Single Zone [] Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. KBE = 67.06' AMSL Prudhoe Bay Field / Prudhoe 3. Address 6. Property Designation Bay Pool P.O. Box 196612, Anchorage, Alaska 99519-6612 ADL 028285 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (See 20 AAC 25.025) 1535' NSL, 2276' EWL, SEC. 12, T11N, R13E, UM Prudhoe Bay Unit At top of productive interval 8. Well Number Number 2S100302630-277 410' SNL, 2133' EWL, SEC. 14, T11N, R13E, UM G-19A At total depth 9. Approximate spud date Amount $200,000.00 201' SNL, 2767' WEL, SEC. 14, T11N, R13E, UM 11/01/99 12. Distance to nearest property line 113. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL 028280, 201' MDI No Close Approach 2560 12695' MD / 8955' TVDss 16. To be completed for deviated wells 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Kick Off Depth 11255' MD Maximum Hole Angle 88° Maximum surface 3300 psig, At total depth (TVD) 8800' / 4390 psig 18. Casing Program Specifications Setting Depth Size Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 3-3/4" 2-7/8" 6.16# L-80 ST-L 2455' 10240' 8041' 12695' 8955' 107 cuft Class'G' FEi tcr 19. To be completed for Redrill, Re-entry, and Deepen Operations. ~ '~ I' I,. I,,, ! V L Present well condition summary Total depth: measured 11600 feet Plugs (measured) OCT 1 9 1999 true vertical 9093 feet Effective depth: measured 11400 feet Junk (measured) Fill at 11400' MD (06/~ 0ii & Gas Cofl8.60fftiftlS$10r~ true vertical 8967 feet Al'lChol'ag8 Casing Length Size Cemented MD TVD Structural Conductor 110' 20" 8 cu yds concrete 137' 137' Surface 2676' 13-3/8" 3808 cu ft Permafrost 2703' 2641' Intermediate 10568' 9-5/8" 575 cu ft Class 'G' 10595' 8387' Production Liner 1259' 7" 448 cu ft Class 'G' 10341' - 11600' 8188' - 9094' ORIC ..,. Perforation depth: measured Open: 11386'- 11406', 11416'- 11448', 11458'- 11476' / ~,, i Sqzd: 11180'-11185', 11328'-11348', 11362'-11386' ~L true vertical 8819' - 9017' (six intervals) / I V ! 20. Attachments [] Filing Fee [] Property Plat [] BOP Sketch [] Diverter Sketch [] Drilling Program [] Drilling Fluid Program []Time vs Depth Pict [] Refraction Analysis [] Seabed Report [] 20 AAC 25.050 Requirements Contact Engineer Name/Number: Ted Stagg, 564-4694 Prepared By Name/Number: Terrie Hubble, 564-4628 21. I hereby certify that the foregoing is true and correct to the best of my knowledge TedStagg Title CT Drilling Engineer Date / ~'~/ Commission Use Only Permit Number I APl Number I '~Rprov'v'~l/Date/' ¢ I See cover letter /'¢9 "'-/'O~ 50-029-21599-01 /' ~""C;~'" ~' for other requirements Conditions of Approval: Samples Required [] Yes _,~.N.o Mud Log Required [] Yes [~'No Hydrogen Sulfide Measures ~'f'es [] No Directional Survey Required l~Yes [] No Required Working Pressure for'BOPE I-I 2K; ['-I 3K; ~,4K; I-I 5K; I--I 10K; I--I 15K Other: by order of ORIGINAL SIGNED-BY Commissioner the commission Date/'~ Approved By Robert N. ~hr!sten~.-. Form 10-401 Rev. 12-01-85 Submit In Triplicate BPX G-19a Sidetrack Summary of Operations: G-19 is currently shut in due to high GOR. The sidetrack, G-19a, will target Zone 1, 14P reserves. This sidetrack will be conducted in two phases. Phase 1: Set Whipstock: Planned for Oct. 27, 1999. · A Casing Integrity Test was successful on 9/20/99. · The whipstock drift and Kinley caliper have been run. · A mechanical whipstock will be set on e-line at approx. 11,245' MD. Phase 2: Cement perfs, mill window and drill sidetrack: Planned for Nov. 1, 1999. Directional drilling coiled tubing equipment will be rigged up and utilized to cement perforations, mill the window and drill the sidetrack to a planned TD of 12,695' MD (8,955' TVDss). Mud Program: · Phase 2: Seawater and FIo-Pro (8.6 - 8.7 ppg) Disposal: - No annular injection on this well. - All drilling and completion fluids and all other Class II wastes will go to Grind & Inject. - All Class I wastes will go to Pad 3 for disposal. Casing Program: - 2 7/8", 6.16#, L-80, ST-L liner will be run from TD to approx. 10,240' MD and cemented with approx. 19 bbls. cement to bring cement 200 ft above the window. The well will then be perforated with coiled tubing conveyed guns. Well Control: - BOP diagram is attached. - Pipe rams, blind rams and the CT pack off will be pressure tested to 400 psi and to 4000 psi. - The annular preventer will be tested to 400 psi and 2000 psi. Directional - See attachments. - Kick Off: 11,255' MD (8,803' TVD ss) - TD: 12,695' MD (8,955' TVD ss) - Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. Logging · A Gamma Ray log will be run over all of the open hole section. · Memory CNL log will be run at TD. TREE: CAMERON 4" WELLHEAD: McEVOY G-19a Proposed Completion KB. ELEV = 67.06 BF. ELEV = 40.41 ^f"TI I^T/'ID, ^VEl 9-5/8" FOCI 2,661 13 3/8" 72# I I KOP: 1800 MAX ANGLE: 51 ° 4-1/2" 12.6# L-80 BTRS TUBING ID: 3.958" CAPACITY: 0.01522 BBL/FT NSCC Thread I 4,7591 from surfacce 4-1/2 SSSV LANDING NIPPLE (OTIS) (3.813" ID) I 2'0701 GAS LIFT MANDRELS ( OTIS W/RA LATCH) N-~ MD(BKB) TVDss Dev 5 3,094 3,008 4 4,546 4,201 3 6,947 5,895 2 9,385 7,587 1 9,572 7,718 4-1/2" SLIDING SLEEVEI 1110'1071 (OTIS XA)(3.813" ID) SEAL ASSY. i10,168 J (SBR) Top of 2 7/8" liner approx 10,240' ~ 9-5/8" PACKER 110,1831 ~ '"~'"""'""~'"'~ (TIW) ("ID) 4-1/2", 12.6#/ft, L-80 TAILPIPE 4-1/2 .... X" NIPPLE 110,225 I (OTIS) (3.813" ID) Top of 7" Liner 10,340 9-5/8", 47#/ft, L-80, BTRS I10,595 2 7/8" Liner cemented to approx. 200 ft above window 4-1/2 .... XN" NIPPLE (OTIS) (3.725" ID) 4-1/2" TBG TAIL (ELMD) 0,258 0,302 Whipstock approx. 11245' PERFORATION SUMMARY REF. LOG: BHCS 6-20-86 Size SPF Interval Open/Sqzed 3-3/8" 12 11,180- 11,185 Sqzd 4/20/96 3-3/8" -7 11,328- 11,348 Sqzd 4/20/96 3-1/8" 4 11,362 - 11,386 Sqzd 4/20/96 3-3/8" 4 11,386 - 11,406 Open 5/7/90 3-3/8" 4 11,416 - 11,448 Open 5/7/90 3-3/8" 4 11,458 - 11,476 Open 5/7/90 7" 26# L-80 u4s 111,600 Cement downsqueezed past whipstock -6,500 G-19 I I ~ -5E~-1- -6,000 -5, 500 -5,000 -4, 500 -1,000 8925ss -1,500 -2,500 X distance from Sfc Loc -3,000 iWell Name G- 19 I CLOSURE IDistance 5,332 ft Az 250 de~l NEW HOLE E/W (X) N/S (Y) Kick Off -5,717 -2,158 TD -5,004 - 1,840 State Plane 652,243 5,966,043 Surface Loc 657,248 5, 967,883 DLS de~l/100 Tool Face Length Curve 1 6 0 ~0 Curve 2 35 50 29 Curve 3 35 71 275 Curve 4 35 90 119 Curve 5 10 90 839 Curve 6 10 -90 149 1,441 Drawn: ######## 11:57 Plan Name: Case 103 G-19 Vertical Section 0 8300 8350 8400 8450 8500 8550 8600 ~8650 8700 8750 8800 885O 8900 8950 9000 500 Path Distance (Feet) 1,000 1,500 2,000 2,500 3,000 Angle @ K.O.= 47 deg MD:11255 I8955ss Tot Drld:1440 ~ 12695TD Marker Depths ~)ri~l Wellbore TZ2c I 8,6701ft TVD 8,9251 8,9251rt TVD TSAD I 8,4401fl TVD IKick Off I 8,8031ft TVD 11,2551fl MD IDeprtr @KO 6,125 ft I MD KO Pt 11,255I MD New Hole 1440I I Total MD 12,695I TVD TD 8,9551 DLS de~l/100 Tool Face Len~lth Curve 1 ' 6 0 ~30 Curve 2 35 50 29 ,Curve 3 35 71 275 Curve 4 35 90 1 19 Curve 5 10 90 839 Curve 6 10 -90 149 1,441 Drawn: ######## 11:57 Plan Name: Case 103 CT Drilling & Completion BOP _z 22.5" · 2 3/8" CT ~ I I I I 10,000 psi Pack-Off Lubricator t I 7 1/16" Annular I I Blind/Shear 7 1/16" Pipe/Slip 2 3/8" Slips -" --- 2 7/8" 7 1/16" Pipe ~-- 2 3/8" SWAB OR MASTER VALVE I I STATE OF ALASKA ALASK )IL AND GAS CONSERVATION C ~IMISSlON APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: [] Abandon [] Suspend [] Plugging [] Time Extension [] Perforate [] Alter Casing [] Repair Well ~ Pull Tubing [] Variance ..~ Other ~ Change Approved Program [] Operation Shutdown ~ Re-Enter Suspended Well [] Stimulate Plug Back for Sidetrack ~2. Name of Operator 5. Type of well: 6. Datum Elevation (DF or KB) BP Exploration (Alaska) Inc. [~ Development KBE = 67.06' AMSL [~ Exploratory 7. Unit or Property Name 3. Address [] Stratigraphic Prudhoe Bay Unit P.O. Box 196612, Anchorage, Alaska 99519-6612 [~]Service , 4. Location of well at surface 8. Well Number G-19 1535' NSL, 2276' EWL, SEC. 12, T11N, R13E, UM 9. Permit Number At top of productive interval 86-100 410' SNL,' 2133' EWL, SEC. 14, T11N, R13E, UM 10. APl Numl~er At effective depth 50- 029-21599 536' SNL, 1692' EWL, SEC. 14, T11N, R13E, UM 11. Field and Pool At total depth Prudhoe Bay Field / Prudhoe Bay 587' SNL, 1547' EWL, SEC. 14, T11N, R13E, UM Pool 12. Present well condition summary Total depth: measured 11600 feet Plugs (measured) true vertical 9093 feet Effective depth: measured 11400 feet Junk (measured) Fill at 11400' MD (06/89) true vertical 8967 feet Casing Length Size Cemented MD TVD Structural Conductor 110' 20" 8 cu yds concrete A 137' 137' Surface 2676' 13-3/8" 3808 cu ft Permafrost//\ 2703' 2641' Intermediate 10568' 9-5/8" 575 cuft Class~'G',, / \ 10595' 8387' Production ~ / 'k ~/ Liner 1259' 7" 4¢8 c'~,~/~s "~r ~ 10341'- 11600 8188'-9094' Pefforationdepth: measured Open: 11386'7/1140'~',~1416'-11448, 11458'-~1476 Sqzd: 1,~,1.~0'/z 11185'~ ~1328'- 11348', 11362'- 1~386' ~% I, ~ I[., true vertical 8819' - ~(six inter~s) ....\\ ,OCT '/9 1999 Tubing (size, grade, and measured deCh) 4-1/~', 12.6#, ~0 to10183 with4-1/2 tailpipe to10291 [ ~ ,, '~ , ,, ~S~ 0~i¢ GasOons Commission Packers and SSS~~nd measure~9-5/8 TIW packer at 10183;4-1/2 SSSV Nipp e at 20 13. A~achmen~s ~ Description summa~ of proposal ~ Detailed operations program ~ BOP sketch 4. Estimated date f~r commencing operation 15. Status of well classifications as: .... ~ October 27, 1~99 ~~ Oil ~ Gas ~ Suspended 16, If proposal was venally appro~ Se~ice Name of approver Date approved Contact Engineer Nam~umbe~ Ted Stagg, 564~694 Prepared By Name~umber: Terse Hubb/e, 5~628 {'7. I hereby ce~i~ that the fo~gping is true and correct to the best of my knowledge Signed ~~ Ted Stag Title CT Drilling Engineer Date / Commission Use Only Conditions of Approval: Noti~ Commission so representative may witness ~ Approval No. Plug integri~ ~ BOP Test~ Location clearance ~ I Mechanical Integri~ Test Subsequent form required 10- Approved by order of the Commission Commissioner Date Form 10-403 Rev. 06/15/88 Submit In Triplicate H 1 56551 VENDOR ~LASKAST 14 O0 DATE INVOICE / CREI~IT MEMO DESCRIPTION GROSS DISCOUNT NET 091&c)9 CKO91&99A ' '100. O0 100. O0 HANDL :NG INST: s/h Terri Hubble ×46~8 'HE A~rACHED CHECK IS I" PAYMENT FOR ITEMS DESCRIBED ABOVE. --[e]ll,_l~ ~ 1 .OO. OO 1 OO. OO :,'BP EXPLORATION (ALASKA), INC. ...::. ;::: ;:[,: ,:, ..;: RO.' BOX 196612 ,~", ANOHORAGE,::ALASKA: 99519-6612 FIRST NATIONAL· BANK OF ASHLAND i: i:: :,. ::::'.'i: ;AN'AFFILIATE OF NAI:iONA~'C~TY.S~K '?I '. CLEVELAND OHiO :,L"' ' '.~' 56.389 . ., :: ::,. 412 No. H ,! 56:551 CONSOL!D~ lED CoMMERcIAL ACCOUNT 0015~551 PAY To Th ei~:. . ; , ,ALASKA STATE DEPT OF REVENUE '.300'1 · , DATE ~AMOUNT NOT:VALID AFTER 120 DAYS ANCHORAQE AK 99501-3120 V/ serv wellbore seg WELL PERMIT CHECKLIST FIELD & POOL INIT CLASS WELL NAME f.~ G -/?'~ PROGRAM: exp /- ~i L_ GEOL AREA ADMINISTRATION _~~. DATE COMPANY 1. Permit fee attached ....................... 2. Lease number appropriate ................... 3. Unique well name and number .................. 4. Well located in a defined pool .................. 5. Well located proper distance from drilling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in drilling unit ............ 8. If deviated, is wellbore plat included ............... 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit can be issued without administrative approval'. ..... 13. Can permit be approved before 15-day wait ........... GEOLOGY 14. Conductor string provided . .. ................. 15. Surface casing protects all known USDWs ........... 16. CMT vol adequate to circulate on conductor & surf csg ..... 17. CMT vol adequate to tie-in long string to surf csg ........ 18. CMT will cover all known productive horizons .......... 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. 21. If a re-drill, has a 10-403 for abandonment been approved. 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling fluid program schematic & equip list adequate ..... 25. BOPEs, do they meet regulation ................ 26. BOPE press rating appropriate; test to ~~-~ psig. 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Work will occur without operation shutdown ........... 29. Is presence of H2S gas probable ................. 30. Permit can be issued w/o hydrogen sulfide measures ..... 31. Data presented on potential overpressure zones ....... 32. Seismic analysis of shallow gas zones ............. )N N ,N N ~N N day redrll ann. disposal para req UNIT# ('~//~_:~ ~'~-~.~'") ON/OFF SHORE (~/ Y N /,/,~1 Y N,x/~ DATE ANNULAR DISPOSAL APPR DATE 33. Seabed condition survey (if off-shore) ............. :~Y N ,,'t/~ 34. Contact name/phone for weekly progress reports [exploratory only~_~ N 35. With proper cementing records, this plan t,~ ~ ~,-,~\~.~-- (A) will contain ~able receiving zone; ....... Y N''~._~,.,.~.~-~.._¢j // (B) will no_t c/orftaminate freshw-w-'a't~cause drilling waste... Y N ./' to s~ce; '~ (C)/w'll~ntegrity ofthe-"w~used for disposal; Y N 7 ~'i°ll°~°atnddamage pr°ducing formation or impair~ a Y~ GE__q_L .q._G_y: ENGINEERING: U lC/.A_n_~ COMMISSION: co ..... Comments/Instructions: rtl Z c:\msoffice\wordian\diana\checklist (rev. 09/27/99) Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIX.' .. No special'effort has been made to chronologically organize this category of information. Sperry-Sun Drilling Services LIS Scan Utility SRevision: 3 $ LisLib SRevision: 4 $ Sat Feb 17 15:57:41 2001 Reel Header Service name ............. LISTPE Date ..................... 01/02/17 Origin ................... STS Reel Name ................ UNKNOWN Continuation Number ...... 01 Previous Reel Name ....... UNKNOWN Comments ................. STS LIS Writing Library. Scientific Technical Services Tape Header Service name ............. LISTPE Date ..................... 01/02/17 Origin ................... STS Tape Name ................ UNKNOWN Continuation Number ...... 01 Previous Tape Name ....... UNKNOWN Comments ................. STS LIS Writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER PRUDHOE BAY UNIT MWD/MAD LOGS WELL NAME: API NUMBER: OPEP~ATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPEP~ATOR WITNESS: MWD RUN 1 AK-MW-90175 B. JA_HN WHITLOW/SEVC G-19A 500292159901 BP EXPLORATION (ALASKA), INC. Sperry Sun 12-FEB-01 MWD RUN 2 AK-MW-90175 B. JAI{N WHITLOW/SEVC MWD RUN 3 AK-MW-90175 B. JAHN WHITLOW/SEVC JOB NIIMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RLIN 4 AK-MW-90175 B. JAHN WHITLOW/SEVC MWD RUN 5 AK-MW- 90175 B. JAHN WHITLOW/SEVC MWD RUN 7 AK-MW- 90175 B. JAHN WHITLOW/SEVC JOB NUMBER: LOGGING ENGINEER: MWD RUN 8 AK-MW-90175 B. JAHN OPER3~TOR WITNESS: SURFACE LOCATION SECTION: TOWNSHIP: RIANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: WELL CAS lNG RECORD 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING WHITLOW/SEVC REMARKS: 12 liN 13E 1535 2276 67.06 .00 39.16 OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 9.625 10595.0 7.000 11250.0 4.500 10302.0 1. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE NOTED. 2. MWD RUNS 1 - 8 ARE DIRECTIONAL WITH NATURAL GAMMA PROBE (NGP) UTILIZING A SCINTILLATION DETECTOR. 3. NO FOOTAGE DRILLED ON MWD RUN 6 AND IS NOT PRESENTED. 4. DIGITAL DATA ONLY IS DEPTH CORRECTED TO THE PUC LOG OF 11/3/99 (CCNL GR) WITH A KBE OF 67.06' AMSL. THIS WELL KICKS OFF FROM G-19 AT 11250' MD, 8800' SSTVD (TOP OF WHIPSTOCK) ALL MWD LOG HEADER DATA RETAINS THE ORIGINAL DRILLER'S DEPTH REFERENCES. 5. MWD RUNS 1 - 5, 7 & 8 REPRESENT WELL G-19A WITH API ~ 50-029-21599-01. THIS WELL REACHED A TOTAL DEPTH OF 12763' MD, 8941' SSTVD. SGRD = SMOOTHED GAMMA RAY SROP = SMOOTHED P~ATE OF PENETP~ATION $ File Header Service name ............. STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.000 Comment Record FILE HEADER FILE NIIMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH GR 11235.5 12733.0 ROP 11269.5 12763.5 $ BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) BASELINE DEPTH 11235 5 11242 5 11248 5 11259 5 11266 0 11269 0 11285 0 11291 5 11295 5 11301 5 11314 0 11325 5 11330.0 11341 0 11344 5 11352 0 11355 0 11360 5 11364 0 11366 5 11368 0 11369 5 11376 5 11390 5 11400 5 11405 5 11409 5 11416 0 11419 5 11428 0 11437 0 11440 5 11447 0 11450 5 11460 0 11471 0 11475 0 11479 0 GR 11236 5 11243 5 11249 5 11257 5 11264 5 11267 5 11282 5 11289 0 11292 5 11298 0 11311 0 11321 0 11327 0 11338 5 11341 0 11350 5 11355 0 11360 5 11363 5 11366 5 11369 0 11371 0 11375 5 11389 0 11399 5 11404 0 11406 5 11413 5 11416 0 11425 0 11433 5 11437 0 11444 5 11450 0 11459 0 11471 0 11475 0 11479 5 EQUIVALENT UNSHIFTED DEPTH 11482 11490 11494 11500 11505 11515 11517 11520 11522 11524 11526 11529 11533 11535 11542 11549 11560 11567 11573 11579 11591 11593 11594 11598 11601 11604 11608 11628 11632 11638 11652 11670 11675 11682 11697 11699 11708 11711 11722 11725 11732 11735 11744 11749 11755 11759 11766 11777 11782 11788 11791 11798 11818 11834 11839 11844 11846 11481 11490 11494 11501 11505 11515 11517 11519 11521 11522 11526 11529 11533 11536 11542 11546 11557 11566 11572 11578 11591 11595 11596 11598 11600 11603 11608 11629 11634 11638 11649 11668 11674 11682 11694 11696 11702 11707 11718 11720 11726 11729 11740 11746 11751 11754 11762 11771 11776 11787 11792 11795 11813 11830 11836 11839 11842 11854 11861 11864 11866 11870 11879 11884 11889 11891 11894 11896 11900 11913 11918 11929 11942 11957 11983 11987 11997 12003 12005 12007 12012 12019 12025 12044 12049 12053 12057 12060 12066 12079 12085 12095 12112 12118 12123 12134 12142 12146 12156 12169 12176 12189 12205 12210 12220 12232 12241 12254 12256 12263 12276 12287 12291 12297 11850 11857 11861 11863 11865 11874 11878 11885 11888 11892 11895 11898 11911 11917 11929 11939 11956 11980 11985 11995 12001 12002 12003 12009 12017 12022 12039 12045 12050 12053 12056 12062 12077 12083 12094 12111 12118 12123 12131 12137 12143 12152 12164 12174 12187 12204 12208 12216 12228 12238 12250 12252 12261 12274 12286 12290 12297 12307 0 12313 0 12320 0 12330 0 12338 0 12343 0 12348 0 12349 5 12352 0 12368 0 12378 0 12379 0 12382 0 12383 5 12386 5 12392 0 12397 0 12405 0 12407 0 12412 5 12416.0 12437.5 12448 5 12460 5 12479 0 12483 0 12489 5 12497 5 12500 5 12504 5 12514 5 12523 0 12529 0 12533 0 12536 5 12547 5 12555 0 12558 0 12562 5 12567 5 12570 5 12577 0 12579 0 12585 5 12594 0 12633 0 12646 5 12660 5 12666 5 12733 0 $ MERGED DATA PBU TOOL MWD MWD MWD SOURCE CODE 12308 12316 12323 12336 12347 12352 12356 12357 12359 12370 12378 12379 12383 12384 12385 12390 12397 12405 12408 12413 12419 12439 12450 12462 12478 12483 12490 12498 12500 12504 12515 12523 12530 12536 12539 12550 12556 12560 12564 12571 12573 12581 12583 12590 12601 12633 12645 12660 12666 12732 BIT 1 2 3 RUN NO MERGE TOP 11236.5 11304.5 11376.5 MERGE BASE 11304.0 11376.0 11409.0 MWD MWD MWD MWD $ REMARKS: 4 11409.5 11447.0 5 11447.5 11499.5 7 11500.0 11843.0 8 11843.5 12763.0 MERGED MAIN PASS. $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .liN Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11235.5 12763.5 11999.5 3057 ROP MWD FT/H 0.06 1336.25 122.756 2989 GR MWD API 16.86 771.35 53.0173 2996 First Reading 11235.5 11269.5 11235.5 Last Reading 12763.5 12763.5 12733 First Reading For Entire File .......... 11235.5 Last Reading For Entire File ........... 12763.5 File Trailer Service name ............. STSLIB.001 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.002 Physical EOF File Header Service name ............. STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 ttAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 11236.5 11273.0 ROP 11268.0 11304.0 $ LOG HEADER DATA DATE LOGGED: 29-0CT-99 SOFTWARE SURFACE SOFTWARE VERSION: Insite 3.2 DOWNHOLE SOFTWARE VERSION: 7.74 DATA TYPE (MEMORY OR REA3~-TIME): Memory TD DRILLER (FT) : 11304.0 TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: 55.9 MAXIMUM ANGLE: 55.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ TOOL NUMBER 002 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT) 3 .750 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPER3tTURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPEtlATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: FLOPRO 8.70 .0 9.2 22000 7.0 .000 .000 .000 .000 .0 141.7 .0 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ) : REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .liN Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD010 FT/H 4 1 68 4 2 GR MWD010 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11236.5 11304 11270.3 136 ROP MWD010 FT/H 11.46 98.14 73.0344 73 GR MWD010 API 16.86 771.35 57.3638 74 First Reading 11236.5 11268 11236.5 Last Reading 11304 11304 11273 First Reading For Entire File .......... 11236.5 Last Reading For Entire File ........... 11304 File Trailer Service name ............. STSLIB.002 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.003 Physical EOF File Header Service name ............. STSLIB.003 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.002 Comment Record FILE HEADER FILE NUMBER: 3 P~AW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 11273.5 11345.5 ROP 11304.5 11376.0 $ LOG HEADER DATA DATE LOGGED: 30-0CT-99 SOFTWARE SURFACE SOFTWARE VERSION: Insite 3.2 DOWNHOLE SOFTWARE VERSION: 7.74 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT) : 11376.0 TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: 61.3 MAXIMUM ANGLE: 61.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ TOOL NUMBER 002 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT) : 3.750 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPEP~ATURE (DEGF) MI/D AT MEASURED TEMPEttATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: FLOPRO 8.70 .0 9.2 22000 '7.0 .000 .000 .000 .000 .0 141.7 .0 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN) : EWR FREQUENCY (HZ) : REMARKS: Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .liN Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11273.5 11376 11324.8 206 ROP MWD020 FT/H 5.4 142.6 67.3835 144 GR MWD020 API 17.5 45.72 27.9343 145 First Reading 11273.5 11304.5 11273.5 Last Reading 11376 11376 11345.5 First Reading For Entire File .......... 11273.5 Last Reading For Entire File ........... 11376 File Trailer Service name ............. STSLIB.003 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.004 Physical EOF File Header Service name ............. STSLIB.004 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.003 Comment Record FILE HEADER FILE NUMBER: 4 P_AW MWD Curves and log header data for each bit run in separate files. BIT RUN NIIMBER: 3 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 11346.0 11378.0 ROP 11376.5 11409.0 $ LOG HEADER DATA DATE LOGGED: 30-0CT-99 SOFTWARE SURFACE SOFTWARE VERSION: Insite 3.2 DOWNHOLE SOFTWARE VERSION: 7.74 DATA TYPE (MEMORY OR REA_L-TIME): Memory TD DRILLER (FT) : 11409.0 TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: 61.5 MAXIMU74 ANGLE: 61.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATUR3AL GAMMA PROBE $ TOOL NUMBER 002 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER' S CASING DEPTH (FT) : 3 .750 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT M3LX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: FLOPRO 8.7O .0 9.2 22000 7.0 .000 .000 .000 .000 .0 158.6 .0 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN) : EWR FREQUENCY (HZ) : REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .lin Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD030 FT/H 4 1 68 4 2 GR MWD030 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11346 11409 11377.5 127 ROP MWD030 FT/H 0.06 122.9 70.4664 66 GR MWD030 API 25.65 113.54 40.906 65 First Reading 11346 11376.5 11346 Last Reading 11409 11409 11378 First Reading For Entire File .......... 11346 Last Reading For Entire File ........... 11409 File Trailer Service name ............. STSLIB.004 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.005 Physical EOF File Header Service name ............. STSLIB.005 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.004 Comment Record FILE HEADER FILE NUMBER: 5 PJtW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 4 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 11378.5 11415.5 ROP 11409.5 11447.0 $ LOG HEADER DATA DATE LOGGED: 30-0CT-99 SOFTWARE SI/RFACE SOFTWARE VERSION: Insite 3.2 DOWNHOLE SOFTWARE VERSION: 7.74 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT) : 11447.0 TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: 61.9 MAXIMUM ANGLE: 61.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ TOOL NUMBER 0O3 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT) : 3.750 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPEP~ATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPER3tTURE: MUD FILTRATE AT MT: MUD CAKE AT MT: FLOPR0 8.70 .0 9.2 22000 7.0 .000 .000 .000 .000 .0 141.7 .0 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ) : # REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .liN Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD040 FT/H 4 1 68 4 2 OR MWD040 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11378.5 11447 11412.8 138 ROP MWD040 FT/H 7.18 1079.14 140.495 76 GR MWD040 API 20.86 123.73 35.7871 75 First Reading 11378.5 11409.5 11378.5 Last Reading 11447 11447 11415.5 First Reading For Entire File .......... 11378.5 Last Reading For Entire File ........... 11447 File Trailer Service name ............. STSLIB.005 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.006 Physical EOF File Header Service name ............. STSLIB.006 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................. LO Previous File Name ....... STSLIB.005 Comment Record FILE HEADER FILE NUMBER: 6 P~AW MWD Curves and log header data for each bit run in separate files. BIT RUN NIYMBER: 5 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 11416.0 11469.0 ROP 11447 . 5 11499 . 5 $ LOG HEADER DATA DATE LOGGED: 31-0CT-99 SOFTWARE SURFACE SOFTWARE VERSION: Insite 3.2 DOWNHOLE SOFTWARE VERSION: 7.74 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT) : 11500.0 TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: 64.2 MAXIMUM ANGLE: 66.3 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NAT~ GAMMA PROBE $ TOOL NUMBER 003 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT) : 3 .750 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPEP~ATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: FLOPRO 8.70 .0 9.2 22000 6.8 .000 .000 .000 .000 .0 145.9 .0 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN) : EWR FREQUENCY (HZ) : REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .liN Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD050 FT/H 4 1 68 4 2 GR MWD050 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11416 11499.5 11457.8 168 ROP MWD050 FT/H 18.03 163.11 109.823 105 GR MWD050 API 25.67 48.96 35.0798 107 First Reading 11416 11447.5 11416 Last Reading 11499.5 11499.5 11469 First Reading For Entire File .......... 11416 Last Reading For Entire File ........... 11499.5 File Trailer Service name ............. STSLIB.006 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.007 Physical EOF File Header Service name ............. STSLIB.007 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.006 Comment Record FILE HEADER FILE NUMBER: 7 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NIIMBER: 7 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 11469.5 ROP 11500.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: STOP DEPTH 11810.0 11843.0 31-0CT-99 Insite 3.2 7.74 Memory 11843.0 71.4 94.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ TOOL NUMBER 003 BOREHOLE ~ CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER' S CASING DEPTH (FT) : 3.750 BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPEP~ATURE (DEGF) MUD AT MEASURED TEMPEP_ATURE (MT): MUD AT M_AX CIRCULATING TERMPEP~ATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: FLOPRO 8.7O .0 9.2 22000 6.8 .000 .000 .000 .000 .0 141.7 .0 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .lin Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD070 FT/H 4 1 68 4 2 GR MWD070 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11469.5 11843 11656.3 748 ROP MWD070 FT/H 12.52 1336.25 125.612 687 GR MWD070 API 25.26 188.56 44.0487 682 First Reading 11469.5 11500 11469.5 Last Reading 11843 11843 11810 First Reading For Entire File .......... 11469.5 Last Reading For Entire File ........... 11843 File Trailer Service name ............. STSLIB.007 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.008 Physical EOF File Header Service name ............. STSLIB.008 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Previous File Name ....... STSLIB.007 Comment Record FILE HEADER FILE NUMBER: 8 RAW MWD Curves and log header data for each bit run in separate files. BIT RIIN NUMBER: 8 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 11810.5 ROP 11843.5 $ LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWN-HOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: STOP DEPTH 12732.5 12763.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE NGP NATURAL GAMMA PROBE $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT) : BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3) : RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ) : REMARKS: 02-NOV-99 Insite 3.2 7.74 Memory 12763.0 85.2 94.8 TOOL NUMBER 002 3.750 FLOPRO 8.70 .0 9.2 22500 7.0 .000 .000 .000 .000 .0 154.3 .0 .0 $ Data Format Specification Record Data Record Type .................. 0 Data Specification Block Type ..... 0 Logging Direction ................. Down Optical log depth units ........... Feet Data Reference Point .............. Undefined Frame Spacing ..................... 60 .liN Max frames per record ............. Undefined Absent value ...................... -999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD080 FT/H 4 1 68 4 2 GR MWD080 API 4 1 68 8 3 Name Service Unit Min Max Mean Nsam DEPT FT 11810.5 12763 12286.8 1906 ROP MWD080 FT/H 9.5 1122.29 129.74 1840 GR MWD080 API 19.91 312.72 60.1618 1845 First Last Reading Reading 11810.5 12763 11843.5 12763 11810.5 12732.5 First Reading For Entire File .......... 11810.5 Last Reading For Entire File ........... 12763 File Trailer Service name ............. STSLIB.008 Service Sub Level Name... Version Number ........... 1.0.0 Date of Generation ....... 01/02/17 Maximum Physical Record..65535 File Type ................ LO Next File Name ........... STSLIB.009 Physical EOF Tape Trailer Service name ............. LISTPE Date ..................... 01/02/17 Origin ................... STS Tape Name ................ UNKNOWN Continuation Number ...... 01 Next Tape Name ........... UNKNOWN Comments ................. STS LIS Writing Library. Reel Trailer Service name ............. LISTPE Date ..................... 01/02/17 Scientific Technical Services Origin ................... STS Reel Name ................ UNKNOWN Continuation Number ...... 01 Next Reel Name ........... UNKNOWN Comments ................. STS LIS Writing Library. Scientific Technical Services Physical EOF Physical EOF End Of LIS File