Risk Assessment of Exploration Well Designs in the Oman Ara Salt

Field: Engineering (Physical Sciences)

Risk Assessment of Exploration Well Designs in the Oman Ara Salt A.G. Tallin; A.G. Tallin Det Norske Veritas Search for other works by this author on: This Site Google Scholar P.R. Paslay; P.R. Paslay Techaid Corporation Search for other works by this author on: This Site Google Scholar E.P. Cernocky; E.P. Cernocky Shell Search for other works by this author on: This Site Google Scholar M.A. Ratchinsky M.A. Ratchinsky Petroleum Development Oman Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 2000. Paper Number: SPE-63130-MS https://doi.org/10.2118/63130-MS Published: October 01 2000 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Tallin, A.G., Paslay, P.R., Cernocky, E.P., and M.A. Ratchinsky. "Risk Assessment of Exploration Well Designs in the Oman Ara Salt." Paper presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 2000. doi: https://doi.org/10.2118/63130-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Annual Technical Conference and Exhibition Search Advanced Search Abstract1. Business Driver for the WorkPetroleum Development Oman (PDO) proposed to eliminate the 7-inch intermediate casing set inside 9 5/8-inch casing in deep, high-pressure, gas exploratory wells within the Ara salt of southeastern Oman. The presence of the 7-inch casing has been driven by the limited burst capacity of the 9 5/8-inch casing under the historical design criteria of full evacuation to gas. The 7-inch casing could be eliminated and the BOP could be downsized if the burst design load could be limited to kicks of small volume. This design change had the potential to reduce dry hole costs of exploratory wells significantly by eliminating the sour 95 grade 7 in. casing string and its premium connections; reducing the rig time spent running that casing from the drilling phase; simplifying the wellhead; downsizing the BOP; and allowing a larger bit with higher ROP to be used to TD.A quantitative risk assessment was performed in order to quantify the risk of limited kick design and justify elimination of the 7 in. intermediate casing and downsizing of the BOP stack based on burst design with limited kick volume rather than with full evacuation to gas. A final design strategy is proposed here based on the risk of a limited volume kick and the option to bullhead down the casing annulus. Operational recommendations are presented concerning the criteria for kick detection, the procedure for circulating the gas kick out of the well, and the determination of when it is necessary to bullhead the well. The risk assessment incorporated measured properties obtained from offset wells in the area of interest, mathematical models, and statistical methods. Extensive use was made of the well control literature, References 1–76.The results of the risk-based design approach are:The estimated kick probably from the Carbonate Stringers in the Ara Salt is between 12% and 19% per well. The majority of these kicks will not involve an influx that is gas at the bottom of the hole.The probability of a kick influx being gas at reservoir conditions is very low. Based on an analysis of the available offset well data, it is less than 10–4 for typical stringer reservoirs in the Ara Salt.Even if there is a gas kick, the likelihood of a casing rupture is very low - about 10–3 for 20% worn casing because the shut-in kick volume is likely to be very small.Because of redundancies, the BOP system is expected to be very reliable. However, this observation depends on strong operational policies and good maintenance. PDO has a superior BOP maintenance program.While limited kicks are not expected to pressurize the BOP system near its rating, the greatest risk in moving to the new design is failing to maintain the BOP system reliability.The risk of catastrophic failures can be significantly reduced by a policy of bullheading large, intense kicks before they pressurize the casing.There is a significant probability that a circulated, limited kick will fracture the formation below the shoe. Even though this kick is safe to bring to the surface based on the casing loads, the salt below the shoe is on average significantly weaker than the casing. Based on several conservative assumptions, it is estimated that 30% of gas kicks will fracture the formation.This design change can and should be made: discard the 7 in. (drill) casing string inside the 9 5/8 in. casing, and drill to TD out of the 9 5/8 in. casing; also replace the 15,000 psi BOP stack with a 10,000 psi BOP stack; even consider the option of using a 5,000 psi BOP stack in conjunction with the bullhead criteria.Limit the 9 5/8 in. shoe to 3700 m if up to 20% wear is assumed and to 4800 m if no wear is assumed (historical maximum observed wear was 12% at shallow depths). Then, there is 10–4 probability of not being able to bullhead and fracture a kick into the formation without rupturing the casing. The well design can be used to drill reliably from the 9 5/8 in. shoe all the way to 7,500 m providing the hole remains stable. Keywords: circulation, intensity, influx, upstream oil & gas, reliability, risk assessment, fracture, pit gain, probability distribution, exploration well design Subjects: Pressure Management, Well control This content is only available via PDF. 2000. Society of Petroleum Engineers You can access this article if you purchase or spend a download.