Increased global energy demand has forced the oil and gas industry to search for hydrocarbons in increasingly challenging locations such as high temperature, high pressure (HTHP) reservoirs. This paper presents the field performance of a new fit-for-purpose synthetic-based mud (SBM) used to drill an ultra-HTHP deep gas exploration well offshore Malaysia. The well was drilled to a total depth (TD) of 14, 380 ft (4, 383 m) and reached the highest recorded bottomhole temperature (BHT) of 488°F (253°C) in Southeast Asia. To overcome the anticipated drilling challenges in the extreme environments, the operator and service company collaborated to identify a thermally stable, high-density drilling fluid that met the operator's needs. The drilling fluid was formulated for a maximum density of 18 lb per gallon (ppg), but reached the Southeast Asia record of 19.1 ppg mud weight at TD. The use of dual weighting materials (barite and manganese tetraoxide) yielded lower plastic viscosity (PV) for the high-density mud, leading to improved hydraulics and lower equivalent circulating density (ECD). The drilling fluid encompassed excellent temperature stability with no weighting agent sag and no high-temperature gelation observed after remaining static for five days at BHT during wireline logging. In this respect, it eliminated the rig time spent for additional circulating or conditioning of drilling muds and fluid treatment cost. Moreover, the fluid also provided good wellbore stability with no non-productive time (NPT) from drilling fluid performance. Comparison of field data and laboratory results highlighted the benefits of competent drilling fluid design and testing. As a result of thorough planning and comprehensive laboratory testing, desirable drilling fluid properties were maintained despite extreme HTHP conditions, minimizing trips and operational costs.
Ultrahigh-pressure/high temperature (UHP/HT) wells are very challenging because of the narrow drilling margins, which can cause either losses or an influx. In a field in Malaysia, the pore pressure and fracture gradient were too close to allow conventional drilling, so the managed pressure drilling (MPD) technique was used to drill these wells.Cementing under MPD is a new technique in this area. A technical assessment revealed that there is limitation in the currently used cementing placement simulator in that it cannot simulate the real-time MPD cementing placement. The current hydraulic simulator does not account for automated real-time annulus choking to apply the backpressure and safely place the cement in the annulus. In addition, it does not take into account the downhole viscosity change due to pressure and temperature effects and which is not imposed by the testing protocols from API. To check the effect of the downhole conditions on the fluid viscosities, which will have an effect on the friction pressure in the annulus during the placement, and to reduce the risk during the cementing job, two in-house hydraulic simulators were identified and used to benchmark the currently used simulator results; the design workflow was changed to account for the additional simulations, and the new technique was implemented successfully to cement under MPD conditions.
This paper discusses the experiences and good practices established from successfully executing two managed pressure cementing (MPC) jobs within an ultra high-pressure/high-temperature (HP/HT) well in offshore Malaysia. The risks associated with cementing in sections with narrow margins between pore pressure and fracture gradient can often limit the length of each cased section, hence limiting the final total depth (TD) of the well. A new cementing technique using managed pressure drilling (MPD) equipment and processes allows the wellbore to be displaced with a hydrostatically underbalanced mud after the casing string has landed and then cemented with a hydrostatically underbalanced spacer and cement slurry. This technique was used to successfully cement an 11 3/4-in. intermediate liner and a 9 7/8-in. production liner, which, in turn, enabled the operator to reach the target depth. The 11 3/4-in. liner was cemented successfully without losses or gains, despite only a 0.2-lbm/gal window (15.6 to 15.8 lbm/gal), with bottomhole static temperature (BHST) of 133°C. This job was executed with a 15.0-lbm/gal mud, a 15.0-lbm/gal spacer, a 15.0-lbm/gal cement slurry, and up to 400 psi surface backpressure (SBP). The 9 7/8-in. liner was also cemented successfully without losses or gains with a 0.9-lbm/gal window (17.4 to 18.3 lbm/gal) with BHST of 163°C. This job was executed with a 17.0-lbm/gal mud, a 17.0-lbm/gal spacer, a 17.0-lbm/gal cement slurry, and up to 600 psi SBP. A cement bond log (CBL) was run for the 9 7/8-in. production liner and the results showed good bonding across the entire openhole section, including the critical target zones. The prejob engineering and execution involved extensive hydraulic modeling, closely coordinated with the MPD service provider, and comprehensive risk analysis and mitigation plans.
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