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Home My WebLink About2005 Endicott Oil Pool bcc: Ken Huber Daryl Kleppin John Denis Madelyn Millholland John McMullen Dick Powell/TJ Barnes Working Interest Owners 2005 Reservoir Surveillance Report Endicott Oil Pool March 28, 2006 Waterflood Surveillance Program Key Well Pressure Monitoring Program GOC Monitoring Program 2005 Endicott Reservoir Surveillance Report Table of Contents Page 1 Waterflood Surveillance Program: Introduction Page 2 Project Status Summary Page 2 Injection Well Performance Page 4 Waterflood Tracer Page 4 Figure 1: Endicott Field Well Plat (highlighting injectors) Page 5 Table 1: Summary Of Pertinent Data Page 6 Table 2: Reservoir Balance For Waterflood Sands Page 7 Table 3: Injection Well Data Page 8 Figure 2: Waterflood Tracer Plat Page 9 Pressure Monitoring Program: Introduction Page 10 2005 Pressure Monitoring Program Page 10 2006 Pressure Monitoring Program Page 11 Figure 3: Endicott Field Well Plat (highlighting Key Wells) Page 12 Table 4: 2005 Key Well Pressure Monitoring Program Page 13 Table 5: 2005 Key Well Pressure Data Page 14 Table 6: 2006 Key Well Pressure Monitoring Program Page 15 GOC Monitoring Program: Introduction Page 16 2005 Gas-Oil Contact Monitoring Program Page 17 2006 GOC Monitoring Program Page 17 Appendices: 1. Production Rate vs. Time Plots 2. Cumulative Voidage vs. Time Plots 3. Injection Well Rate & Pressure vs. Time Plots 4. Historical Key Well Pressure Data 5. Reservoir Pressure vs. Time 6. Endicott Shut-in well list 2 Endicott Oil Field 2005 Waterflood Surveillance Program Introduction Conservation Order 202 Rule 12 approved a field wide waterflood project for the Endicott reservoir. The waterflood was to be implemented within two years of regular production and a waterflood plan submitted three months before actual water injection began. By letter, dated June 15, 1988, the plan to implement the field wide waterflood was approved and semi-annual pressure maintenance project reports stipulated. The Endicott Waterflood development was recognized as complete and fully operational by letter, dated January 11, 1991, and annual waterflood surveillance reporting was approved. This document constitutes the report for 2005. Project Status Summary Endicott Field production began in October 1987. From field start-up, produced gas has been reinjected back into the existing gas cap to provide pressure support. Water injection was initiated in February 1988, and a tertiary recovery process was initiated with the installation of a miscible injection compressor and commencement of miscible injection in March 1999. This report summarizes the cumulative effects of pressure maintenance since field start-up and details activities in 2005. The Endicott Field is generally described as having three areas. The three areas are fault blocks that are identified as the MPI (Main Production Island area), the SDI (Satellite Drilling Island area), and the NFB (Niakuk Fault Block). Vertically there are six subzones (3C, 3B, 3A, 2B, 2A, 1) that are the general geological subdivisions within the Kekiktuk formation. Initially produced gas was reinjected into the gas cap in the updip portion of MPI subzones 2A and 2B. Gas injection was extended into the MPI subzone 3A gas cap in May 1988, and into the subzone 3C gas cap in both the MPI and the SDI areas in 1993. Reservoir studies subsequently identified the SDI 3C area as a primary EOR target and supported the decision to halt immiscible gas injection in that subzone. As a result, SDI 3C gas injector 1- 15/P-25 was shut-in July 1998. In October 2000 well 1-15/P-25 was placed back on injection when gas injector 2-06/J-22 was shut in with annular communication. 3 Well 1-15/P-25 was shut in during July 2001 upon completion of a workover to return 2- 06/J-22 to gas injection. Well 1-15/P-25 continues to be used on a short term basis whenever wellwork and maintenance needs to be performed on the other gas injectors. Water injection is occurring in peripherally placed injectors in all subzones in all areas of the field with the exception of Zone 1, which is on primary depletion. Endicott’s EOR project began in March of 1999. The original EOR Phase I implementation plan consisted of 8 water-alternating-gas (WAG) injection wells, with two wells being on MI at any given time. This plan was based on an MI compressor design rate of 45 mmscfpd. From January 1, 2005 through May 19, 2005, there was no MI injection as the turbine driving the MI compressor had failed. On May 20, 2005, the MI turbine and compressor were restored to service. The average MI injection since re-start has been 15.0 mmscfd, with peak rates near ~18 mmscfd. In 2005, miscible gas injection had occurred in 1 well; SDI 3C injector 4-04/T-26. Produced gas samples are routinely collected in all of the producers offset from these injection wells to provide a baseline for use in monitoring MI breakthrough. Figure 1 shows a map of the field with well statuses as of December 31, 2005 including the existing water injectors, gas injectors and oil producers. No well service additions or changes have occurred since the last report date. Table 1 summarizes total production, injection, and well count (wells online during December 2005) data for the entire pool through December 2005. Table 2 details the reservoir balances by area and subzone through December 2005. The NFB is included in with the MPI on Table 2 for simplicity. Appendix 1 provides a graph of Production and Gas/Oil Ratio versus Time by area and subzone. Appendix 2 provides graphs of Cumulative Voidage versus Time by area and subzone. Appendix 6 lists the wells in the participating area that were shut in for the entire year of 2005. 4 Injection Well Performance Table 3 provides an overview of the performance of each of the pressure maintenance injectors. Included in this exhibit are the start-up dates and cumulative injection volumes. Appendix 3 provides graphs of the injection rates, injectivity index, and wellhead pressure versus time for each of the active injectors. Waterflood Tracer The waterflood tracer program was started in 1988. A total of 19 water injectors have been traced: 3 in 1988, 8 in 1989, 6 in 1991, and 3 in 1996 (well 2-44/R-12 was traced with two different tracers). The program has been very successful in identifying the progress of the waterflood as depletion matures. Numerous interventions have been implemented on producers and injectors to improve ultimate recovery. Beginning in 2006, there will not be a regimented sampling program for the tracer program that began in 1988. Instead, samples will be taken on an as-needed basis. In addition, samples of produced gas will continue to be obtained in the production wells that offset the EOR injection wells to monitor MI movement. Figure 2 is an Endicott well plat showing the dates and types of tracers injected and the producing locations where the tracer has appeared. A new, limited scope, tracer program was initiated in November of 2005. This tracer program consists of injecting tracer into 2 water injectors (1-23/O-15 and 3-37/L-35) with samples being taken on offset producers in 2006. The primary purpose of the new tracer program is to gain further understanding of fluid movements in the K2A and K2B of the SDI region of the field. Reservoir pressure and gas and water movement will continue to be closely monitored through logging, mechanical isolations, and well testing. Changing pressure maintenance needs will continue to be met by evaluating new well drilling locations, converting producers to injectors, profile modification of existing injectors, and target injection rate control. Offtake will continue to be optimized by evaluating new well drilling locations, remedial work on existing producers, and production rate control. 5 Figure 1. 2005 Well Status – Endicott Field, Alaska BP Exploration, Alaska Inc . 6 TABLE 1 ENDICOTT OIL POOL SUMMARY OF PERTINENT DATA (as of December 31, 2005) Water Injection Start-up: February 29, 1988 Miscible Gas Injection Start-up: March 24, 1999 Endicott Production since Field Start-Up: Black Oil and Condensate (MMSTB) 433.2 NGL's (MMSTB) 21.3 Gas (BSCF) 1963.0 Water (MMB) 806.1 Endicott Injection since Field Start-Up: Gas (BSCF) 1756.5 Miscible Injectant (BSCF) 23.5 Water (MMB) 1187.5* Wells in Operation as of 12/31/05: Oil Producers 56 Gas Injectors 4 Water Injectors 22 Water-Alternating-Gas Injectors 0 Waste Water Disposal 1 ** Total 83 * Water injection volumes do not include Cretaceous injection ** Cretaceous injector not shown in Figure 1 7 MPI REGION by SUBZONE Produced Volume 3C 3B 3A 2B 2A 1 MPI TOTAL Oil 26.49 40.89 33.83 76.99 158.61 4.73 341.54 Free Gas 69.16 83.42 109.97 171.86 381.43 7.76 823.60 Water 21.30 44.25 73.73 127.88 138.52 1.77 407.46 Total 116.95 168.56 217.52 376.74 678.56 14.26 1,572.59 Injected Volumes Gas 153.76 98.20 21.61 412.00 422.26 0.00 1,107.83 MI 0.00 1.37 0.88 0.00 0.00 0.00 2.25 Water 35.81 93.54 64.80 157.74 207.03 0.00 558.91 Total 189.56 193.11 87.28 569.74 629.29 0.00 1,668.99 Net Voidage Volumes Total 72.61 24.55 -130.24 193.01 -49.27 -14.26 96.40 SDI REGION by SUBZONE Produced Volume 3C 3B 3A 2B 2A 1 SDI TOTAL Oil 56.80 17.84 33.82 94.88 40.18 0.26 243.78 Free Gas 134.59 24.77 9.78 79.60 51.01 0.16 299.90 Water 99.58 26.63 64.18 182.59 49.84 0.05 422.87 Total 290.97 69.24 107.78 357.07 141.02 0.46 966.55 Injected Volumes Gas 86.51 5.89 0.00 0.00 0.00 0.00 92.40 MI 11.69 2.09 0.00 0.00 0.00 0.00 13.78 Water 118.73 68.53 58.36 313.05 105.51 0.00 664.19 Total 216.92 76.52 58.36 313.05 105.51 0.00 770.37 Net Voidage Volumes Total -74.05 7.27 -49.42 -44.02 -35.51 -0.46 -196.18 FIELD TOTALS by SUBZONE 3C 3B 3A 2B 2A 1 FIELD TOTAL Produced Volume Oil 83.29 58.74 67.65 171.87 198.79 4.99 585 Produced Gas 203.75 108.19 119.75 251.46 432.43 7.92 1,123 Water 120.89 70.87 137.91 310.48 188.36 1.82 830 Total 407.92 237.80 325.31 733.80 819.58 14.73 2,539.14 Injected Volumes Gas 240.26 104.09 21.61 412.00 422.26 0.00 1,200 MI 11.69 3.46 0.88 0.00 0.00 0.00 16 Water 154.54 162.07 123.16 470.79 312.54 0.00 1,223 Total 406.48 269.63 145.65 882.80 734.81 0.00 2,439 Net Voidage Volumes Total -1.44 31.83 -179.66 148.99 -84.78 -14.73 -99.78 NOTE: Water injection volumes do not include Cretaceous injection NOTE: Voidage is calculated as Injected Volumes minus Produced Volumes TABLE 2 ENDICOTT OIL POOL RESERVOIR BALANCE FOR WATERFLOOD SANDS Through12/31/2005 (Values in MMRB) 8 MPI Reservoir Area Cumulative Cumulative Cumulative Water Gas MI Start-Up Well Name MMBW BSCFG BSCFG Date 1-05/O-20 419.6 May-88 1-23/O-15 67.6 Mar-95 1-37/P-24 31.0 Dec-87 1-41/O-23 53.1 Dec-95 2-06/J-22 521.8 Oct-87 2-12/Q-16 225.0 Apr-93 2-16/M-16 79.0 Mar-89 2-22/L-14 53.6 3.3 May-89 2-24/M-12 4.8 Mar-95 2-34/P-14 74.0 Nov-89 *2-44/R-12 20.8 Mar-89 2-54/Q-12 71.7 Jan-92 2-64/U-10 7.2 Dec-90 2-70/U-15 22.2 Jul-89 5-01/SD-07 451.7 Oct-87 5-02/SD-10 58.5 Jan-88 SDI Reservoir Area Cumulative Cumulative Cumulative Water Gas MI Start-Up Well Name MMBW BSCFG BSCFG Date 1-15/P-25 115.1 Jun-93 1-43/P-26 140.5 Apr-89 1-51/V-20 13.6 Apr-93 1-67/T-20 22.1 2.1 May-99 1-69/V-19 19.3 Dec-90 **3-07/N-28 47.6 Apr-89 3-37/L-35 35.4 Aug-98 3-41/K-39 124.4 Apr-89 3-45/M-39 56.1 Sep-88 3-47/Q-35 19.4 4.8 Mar-95 3-49A/M-40 15.6 0.2 Apr-99 + 4-02/Q-28 8.5 May-88 4-04/T-26 36.7 13.1 Mar-90 4-08/P-27 48.4 May-93 4-14/R-34 38.1 Oct-89 4-40/P-43 7.1 Oct-92 ++ 4-48/K-43 12.2 Dec-90 Total 1188.5 1733.2 23.4 Note: Water injection volumes do not include Cretaceous injection. * Sidetracked in 9/97 ** Converted to production in 8/98 + Converted to production in 4/96 ++ SI since 4/97 Table 3 Endicott Oil Pool Injection Well Data Through 12/31/2005 9 10 Endicott Oil Field 2005 Pressure Monitoring Key Well Program Introduction A pressure monitoring key well program was submitted to and approved by the AOGCC in Administrative Approval No. 202.5. This program supersedes the requirements of Conservation Order 202, Rule 6(c), and complies with Conservation Order 202, Rule 6(d). The pressure monitoring program key wells were chosen to provide a real coverage of reservoir pressure in each of the major subzones in the two production areas of the reservoir. Historically, the Key Well Program has included at least two points of pressure measurement for each of the producing subzones, one from each MPI and SDI area, to ensure that a valid picture of reservoir pressure behavior can be drawn. Sixteen wells were identified as key wells to track pressure variation within the five major subzones in each of the two main producing areas of the reservoir. In order to provide representative data, changes have been made throughout time as both the reservoir and well characteristics have changed. Much more reservoir pressure data, other than the key well data, is gathered to address specific well and reservoir surveillance needs. Figure 3 is an Endicott well plot showing the location of the sixteen 2005 Key Well reservoir pressures. 2005 Pressure Monitoring Program Table 4 summarizes the wells included in the proposed 2005 Key Well Program, which consisted of sixteen wells. Table 5 summarizes the key well pressure data gathered in 2005. Appendix 4 lists all current and former key wells with the reservoir pressures obtained since field start-up. These pressures are adjusted to a datum depth of 10,000 feet TVDSS, as is customary in our state pressure reporting. Appendix 5 plots, by subzone and area, key well reservoir pressures along with all other reservoir pressure surveys. Generally speaking there is good agreement between the key well reservoir pressures and other pressure gathered around the field. There are a few 11 exceptions where wells are in small pressure isolated regions. 2006 Pressure Monitoring Program The Endicott Key Well Pressure Monitoring Program has been successful in establishing and monitoring pressure trends within each of the major subzones. Changes in well service and configuration occasionally necessitate changes to the pressure monitoring program in order to obtain representative data. As in previous years BPX plans to combine the MPI 3B and MPI 3C into a single pressure monitoring region. Only one well is completed in only the MPI 3B interval and historic pressure data indicated reservoir pressures in the two intervals share a similar performance. Table 6 summarizes the 2006 Endicott key well pressure monitoring program proposal consisting of 16 wells. As in past years, the amount of static pressure data obtained annually will likely exceed the sixteen wells included in the proposed 2006 Key Well Pressure Monitoring Program. At the operator’s discretion, representative reservoir pressures gathered in other wells during 2006 may be substituted for the proposed key wells to minimize production impacts or for operational necessity. As the field matures, we will be increasingly challenged with managing this need for additional pressure data while minimizing the cost and associated production impacts. 12 Figure 3. 2005 Key Well Reservoir Pressure Data – Endicott, Alaska 4531 13 Well Area Subzone(s)Comments 1-25A/K-22 MPI Z1 1-01/J-19 Niakuk 2A, 2B 1-19/I-18 Niakuk 2B 2-18/L-16 Niakuk 3A 2-26/N-14 Niakuk 3B/3C Commingled pressure 3-25B/L-27 MPI 2A 1-61/Q-20 MPI 2B 1-39/P-17 MPI 3A Lower 3A monitor point 2-52/S-14 MPI 3B/3C Commingled pressure 2-58/S-09 MPI 3C 3-39A/I-37 SDI 2A 3-29/J-32 SDI 2A/2B/3A Commingled pressure 3-35/L-36 SDI 3A Upper 3A monitor point 4-32/K-38 SDI 3A Lower 3A monitor point 4-28/N-37 SDI 3B/3C Eastern area - commingled 4-18/S-30 SDI 3C Central area 2-40/S-22 SDI 3B/3C Western area -commingled Change from the 2004 proposed program: 1-19/I-18 as key well for Niakuk 2B 1-61/Q-20 as key well for MPI 2B 3-29/J-32 as key well for SDI 2B 2-40/S-22 as key well for SDI 3C 2005 KEY WELL PRESSURE MONITORING PROGRAM PROPOSAL ENDICOTT FIELD TABLE 4 14 Well Area Subzone(s)Pressure 1-25A/K-22 MPI Z1 2156 1-01/J-19 Niakuk 2A, 2B 4282 1-19/I-18 Niakuk 2B 4129 2-18/L-16 Niakuk 3A 3684 2-26/N-14 Niakuk 3B/3C 3939 3-25B/L-27 MPI 2A 4195 1-61/Q-20 MPI 2B 4375 1-39/P-17 MPI 3A 4581 2-52/S-14 MPI 3B/3C 4764 2-58/S-09 MPI 3C 2709 3-39A/I-37 SDI 2A 4318 3-29/J-32 SDI 2A/2B/3A 4278 3-35/L-36 SDI 3A 4367 4-32/K-38 SDI 3A 4577 4-28/N-37 SDI 3B/3C 4546 4-18/S-30 SDI 3C 3994 2-40/S-22 SDI 3B/3C 4531 DATUM: 10000' TVDss 2005 KEY WELL PRESSURE MONITORING PROGRAM PROPOSAL ENDICOTT FIELD TABLE 5 15 Well Area Subzone(s)Comments 1-25A/K-22 MPI Z1 1-01/J-19 Niakuk 2A, 2B 1-19/I-18 Niakuk 2B 2-18/L-16 Niakuk 3A 2-26/N-14 Niakuk 3B/3C Commingled pressure 3-25B/L-27 MPI 2A 1-61/Q-20 MPI 2B 1-39/P-17 MPI 3A Lower 3A monitor point 2-52/S-14 MPI 3B/3C Commingled pressure 2-58/S-09 MPI 3C 3-39A/I-37 SDI 2A 3-29/J-32 SDI 2A/2B/3A Commingled pressure 3-35/L-36 SDI 3A Upper 3A monitor point 4-32/K-38 SDI 3A Lower 3A monitor point 4-28/N-37 SDI 3B/3C Eastern area - commingled 4-18/S-30 SDI 3C Central area 2-40/S-22 SDI 3B/3C Western area -commingled 2006 KEY WELL PRESSURE MONITORING PROGRAM PROPOSAL ENDICOTT FIELD TABLE 6 16 Endicott Oil Field 2005 GOC Monitoring Program Introduction A Gas - Oil Contact (GOC) Monitoring Key Well Program was submitted for the Endicott Field in October 1988, one year after field start-up in accordance with AOGCC Conservation Order 202, 9(c). At that time, BP Exploration sought, and received a waiver (Administrative Approval Order 202.5) from the State of Alaska, to initiate the key well program for Endicott on a subzone basis for each of the three distinct reservoir development areas of the field. Administrative Order No. 232.1 provided an exemption for key well GOC monitoring in Sections 1, 3, 7, 9, 10, and 35 of the field as being outside a real gas cap limits of the reservoir. The initial GOC Monitoring Key Well Program consisted of six wells: 1-01/J-19, 1-09/J-18, 1-27/P-20, 1-29/M-25, 2-04/M-19, 3-01/N-29. Conservation Order No. 462, rule 9 (b) revoked the Key Well Monitoring Program and allowed the operator to submit modifications to the Gas Oil Monitoring Program for Commission approval. The details of the 2005 GOC Monitoring Program as submitted by the operator are listed in the section below. The GOC monitoring program for Endicott is based on the understanding of a limited ability to monitor field-wide gas cap movement. A scarcity of wells and limited lateral offset from gas severely restricts the use of time lapse cased-hole logging as a viable tool to predict gas movements at Endicott. It is recognized that narrow hydrocarbon corridors caused by a relatively steep 6 degree structural dip combined with sands separated by thick laterally continuous shales promotes under-running as a common gas movement mechanism. In addition to the continuous shales that separate the reservoir into six vertically isolated subzones, major east-west trending fault offsets provide either lateral hydraulic isolation or partial pressure communication between the three main Endicott development areas. The more massive high quality sands of the 3A and 2B subzones are where more regional GOC effects are more easily noted. Monitoring region gas movement in the 2A subzone is more tenuous due to the close proximity to gas and likelihood of localized gas coning and under runs. Monitoring gas movement in the 3B, and 3C subzones is not practical due to complex stratigraphy (shaliness). 17 2005 GOC Monitoring Program During 2005, a total of 2 cased - hole pulsed and compensated neutron logs (PNL / CNL) were acquired. These logs are routinely used for reservoir surveillance and diagnosing well problems in order to develop reservoir management plans and remedial interventions. Following is a list of the wells from which neutron logs were acquired during 2005: Well Location Well Location 1-31/M-21 MPI 4-10A/L-28 MPI In addition to the cased hole logging, a total of 5 production logs were acquired in the same AOI as the initial GOC Key Well Monitoring Program. These logs are routinely used to understand changes in zonal performance and consequently the need for remedial intervention. Following is a list of wells from which production logs were acquired during 2005. Well Location Well Location 1-29/M-25 MPI 1-49/P-21 MPI 2-14/O-16 MPI 2-36/O-14 MPI 3-35/L-36 SDI The 2005 GOC monitoring program focused on the understanding the location of gas in the 2A and 3A subzones in the MPI fault block (1-29/M-25, 1-31/M-21, 1-49/P-21, 2-14/O-16, 2-36/O-14, and 4-10A/L-28) and SDI fault block (3-35/L-36). 2006 GOC Monitoring Program BPX proposes a 2006 GOC Monitoring Program that consists of a notional five well program focusing on the 2A, 2B, and 3A intervals and to a lesser extent the 3B and 3C intervals. Gas movement in these intervals is the most active. The 2A, 2B, and 3A intervals have the highest potential for monitoring depletion and improving recovery through effective reservoir management and the identification of potential infill drill locations. Production logging and down-hole mechanical isolation of gas prone intervals also provide a means to monitor gas influx. Together, these tools constitute an effective means to monitor gas movement at Endicott and will be a part of future GOC Monitoring Programs.