Re:The Application of Union Oil Company of ) Conservation Order No. 335 California (Unocal) requesting temporary ) waiver of 20 AAC 25.265(a)(2) to allow ) Middle Ground Shoal Oil Field production of MGS 17595 No. 28 well. ) MGS 17595 No. 28 well. April 29, 1994IT APPEARING THAT
1. By letter dated April 4, 1994, Union Oil Company of California (Unocal) requested temporary waiver of 20 AAC 25.265(a)(2) to allow production of MGS 17595 No. 28 well.
2. A notice of opportunity for public hearing was published in the Anchorage Daily News on April 6, 1994.
3. No protests were filed with the Commission.
1. A well with an offshore location must be equipped with a Commission approved fail safe automatic surface control subsurface safety valve (SSSV) system, unless another type of subsurface valve is approved by the Commission; this valve must be in the tubing string and located below the mud line, permafrost, or at some other depth as may be required; the valve must be capable of preventing an uncontrolled flow. 20 AAC 25.265(a)(2).
2. The MGS 17595 No. 28 well was completed with a dual 3.5 inch tubing string, a Kobe bottom hole assembly (BHA) and a hydraulic pump located at 8436 feet MD. The well is not equipped with a packer.
3. The MGS 17595 No. 28 well is completed in a similar manner to other recently completed or recompleted Middle Ground Shoal wells, which are not capable of flow to the surface without assist from artificial lift. Unocal anticipated that the MGS 17595 No. 28 well would not be capable of unassisted flow to the surface.
4. Initial testing of MGS 17595 No. 28 well shows the well is capable of unassisted flow to the surface from perforations in the 'A', 'B, C, D' and 'E, F, G.' pools. The well appears to have been completed in at least one oil zone with sufficient pressure and associated gas to flow to the surface.
5. The MGS 17595 No. 28 well has been shut-in since April 1, 1994 following initial testing.
6. Unocal proposes to install a Baker "XVE" valve in the Kobe BHA. The Baker "XVE" valve is a standard flapper-type SSSV that allows well fluid to travel up the flow string when the flapper is held open by energizing pressure in the power oil string and prevents flow if energizing pressure is removed. The Baker "XVE" valve can be installed without removing the tubing string.
7. Installation of a packer in the MGS 17595 No. 28 well would require killing the well and pulling the existing completion.
8. MGS wells show a history of formation damage by completion and workover fluids.
9. Without a packer, flow up the MGS 17595 No. 28 well annulus is possible in the event of a catastrophic failure or loss of wellhead or surface safety equipment.
10. Installation of a packer would reduce the efficiency of the artificial lift system by forcing gas production through the pump and tubing instead of allowing venting up the annulus. With a packer in the well, production rates would be restricted, reducing ultimate recovery of oil and gas from the MGS field.
11. Unocal expects the MGS 17595 No. 28 well to experience rapid pressure decline and anticipates the flowing condition of the well to be of short duration.
12. The Middle Ground Shoal oil field was discovered in 1962; production began in the 'A' pool in 1967 and in the 'E, F, G' and 'B, C, D' pools in 1965.
13. Initial pressure was 2485 psig at 5500 feet TVD SS for the 'A' pool, 2793 psig at 6000 feet TVD SS for the 'B, C, D' pool and 3975 psig at 9200 feet TVD SS for the 'E, F, G' pool.
14. Before initiation of waterflood, pressure decline in each pool was rapid. By 1969, pressure had declined to 1600 psig in the 'A' pool (Well No. 11) and 1618 psig in the 'B, C, D' pool (Well No. 6).
15. Waterflood operations appear to have restored pressure to near original pressure in each pool. Pressure surveys for the 'A' pool taken in wells No. 17 and No. 6 during 1993 show pressure of 2502 psig and 2161 psig, respectively. Pressure survey for the 'B, C, D' pool taken in wells No. 16 and No. 17 during 1991 show pressures of 2925 psig and 1870 psig, respectively, and 4593 psig and 4843 psig for the 'E, F, G' pool in wells No. 15RD and No. 11.
16. The injection of large volumes of water into each pool results in water cut ratios too high to allow previously completed wells in each pool to flow to the surface unaided by artificial lift.
17. Waterflood operations have been discontinued in the 'A' pool.
18. A pressures gradient survey run in MGS 17595 No. 28 well on April 17, 1994 measured 2462 psig at 5178 feet TVD SS, which extrapolates to 2481 psig at the top of the 'A' pool perforations at 5406 feet TVD SS.
19. Initial well testing of MGS 17595 No. 28 well shows a higher than normal gas-oil ratio, GOR was estimated to range between 2200 scf/bbl and 4500 scf/bbl.
20. Unocal estimates the production potential of the MGS 17595 No. 28 well to be approximately 1000 to 1800 bbl of oil per day.
21. Original GOR was 1000 scf/bbl for the 'A' pool , 650 scf/bbl for the 'B, C, D' pool, and 381 scf/bbl for the 'E, F, G' pool.
22. Unocal proposes to monitor pressure decline during the term of any waiver granted in response to its request, and states that six months of production and pressure data should be sufficient to determine the length of any extension of the waiver, if necessary.
23. If the waiver is approved, Unocal proposes to produce the well through its own automatic surface shut-in valve and separation and testing equipment with high and low pressure and level shut-down capability. Standard Hi-Low pressure shut-in valves will be installed at the wellhead on both the tubing and annulus. The Hi-Low tubing safety valve will be set at 600 psi and 300 psi, respectively, and the annulus valve at 3000 psi and 300 psi.
1. The Baker "XVE" valve serves as a secondary safety system to prevent accidental flow up the tubing in the event the surface safety valve fails, but does not satisfy the requirements of 20 AAC 25.265(a)(2) unless a packer is installed in the well to prevent flow up the annulus.
2. The MGS 17595 No. 28 well cannot be produced without modification to its current completion unless the requirements of 20 AAC 25.265(a)(2) are temporarily waived.
3. Installation of a packer will require killing the well, which may jeopardize well productivity and ultimate recovery from MGS.
4. Producing the MGS 17595 No. 28 well for six (6) months should be sufficient to acquire production and pressure data to accurately assess the flow potential of the well.
5. The high GOR of the MGS 17595 No. 28 well is not representative of MGS wells, and is likely the result of encountering a gas leg in the 'A' pool. The high level of associated gas may be responsible for the well's capacity for unassisted flow to the surface. The gas leg is expected to deplete rapidly once production begins.
6. Based upon performance of past MGS wells and limited pressure maintenance, rapid pressure decline is expected for the MGS 17595 No. 28 well.
7. Installation of surface and downhole safety equipment as proposed by Unocal is a reasonable and prudent alternative to the requirements of 20 AAC 25.265(a)(2) and is consistent with sound engineering practices.
8. With the additional safety precautions, temporary waiver of 20 AAC 25.265(a)(2) for a period of six (6) months should not cause waste nor jeopardize ultimate recovery.
NOW, THEREFORE, IT IS ORDERED THAT the requirements of 20 AAC 25.265(a)(2) are temporarily waived for a six months period for the MGS 17595 No. 28 well. This waiver may be extended by Administrative Approval for an additional six month period upon proper showing to the Commission that pressure is declining in the well and that in all likelihood the well will no longer be capable of flow to the surface prior to expiration of the extension or to allow installation of equipment sufficient to meet the requirements of 20 AAC 25.265(a)(2).
The operator shall check and record tubing, power oil and casing pressures at least twice each day. Copies of pressure records and pressure surveys shall be submitted to the Commission monthly during the waiver period.
The flow line on the tubing-casing annulus will be equipped with a locked valve to prevent inadvertent flow from the annulus.
DONE at Anchorage, Alaska and dated April 29, 1994.
David W. Johnston, Chairman
Russell A. Douglass, Commissioner