Managed-Pressure Drilling Used Successfully for Offshore HP/HT Exploration Wells
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The South China YQ Basin, with its 15 trillion m3 of natural gas, is typical of ultrahigh-pressure/high-temperature (ultra-HP/HT) plays, with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142 MPa, and an extremely narrow pressure window. Predictably, drilling challenges in these plays are numerous. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs.
Overview of the YQ Basin
In recent years, approximately 27% of major oil and gas discoveries have come from HP/HT fields. The South China YQ Basin is one of the three major offshore HP/HT regions in the world and is located at the intersection of the Eurasian, Pacific, and Indo-Australian plates and has a complex geological structure.
The drilling in this basin, as is the case in any HP/HT area, faces various technical challenges, including the following:
- The temperature and pressure gradient is very high. The highest temperature gradient is 5.51°C/100 m. The formation-pressure transition zone is short, and the formation pressure rises rapidly.
- The safety drilling-fluid-density window between pore pressure and fracture pressure is extremely narrow, and the safety factor is very small.
- Formation pressure is hard to predict accurately, and the associated error is greater than 20% in some complex wells.
- Formation drillability is bad because the main targeted layer is over 5000 m. As a result, the rate of penetration (ROP) is very low, which leads to longer drilling cycles and more-frequent downhole accidents and issues such as casing wear.
- The natural environment is harsh (i.e., frequent typhoons in summer).
Operational Design of MPD
The operational design of MPD consists of three parts: the precise calculation of drilling-fluid equivalent circulating density (ECD), the optimization of operational parameters, and well control.
Calculation of ECD. This process includes four models:
- Wellbore-temperature field model
- Drilling-fluid equivalent-static-density (ESD) model
- Drilling-fluid rheological-property model
- A model representing the effect of cuttings concentration on ECD
The process involves the following four steps:
- Establish the instantaneous wellbore-temperature model on the basis of the convection and thermal conductivity theory by dividing the wellbore into five areas.
- Establish the ESD model by considering the elastic compression effect of high pressure and the thermal expansion effect of high temperature.
- Establish the drilling-fluid rheological property model on the basis of the Herschel-Bulkley model by considering the effect of ultra-HP/HT on dynamic shear force, consistency coefficient, and liquidity index.
- Consider the effects of cuttings concentration on ECD on the basis of the solid/liquid two-phase flow.
The ECD model is then established on the basis of the previously mentioned models.
Optimization of Operational Parameters. This step involves the determination of the two key operational parameters: the mud weight (MW) and the surface backpressure (SBP). It includes the following two steps:
- Determine the MW on the basis of the critical pressure constraint principle through the operational-window simulation of different well depths and fluid volumes.
- Determine the SBP of pump-on and pump-off by considering the rated operating pressure of the equipment, the calculated pressure loss, and the BHP as compared with formation pressure.
The principle of micro-overbalance and microleakage is applied to operational designs of MPD in offshore ultra-HP/HT exploration wells through the following criteria:
- BHP must be within the safe drilling-fluid-density window in the open hole, which prevents downhole accidents such as kicks, collapses, and leakages.
- Maximum SBP must be within the rated working pressure of the rotating control device (RCD), and conventional well-control technology must be used to control BHP if the RCD fails.
- Wellbore annulus pressure must be less than 80% of casing internal-pressure resistance.
- Operational design must meet the principle of annulus flow control; the ideal gas/liquid two-phase flow pattern near the wellbore is bubble flow.
The following steps describe the process of operational design of MPD on the basis of the design principles provided previously.
- The MW of each spud is determined on the basis of the critical pressure-constraint principle by the operational window simulation of different well depths and fluid volumes.
- Pressure loss is calculated before MPD begins.
- BHP is 1 to 2 MPa higher than formation pressure.
- SBP is determined on the basis of the idea that SBP is 0 to 3 MPa during drilling and 2 to 8 MPa during pipe connection. The maximum SBP is 5 MPa considering a 30% safety margin.
Well Control. This process considers plans for three cases: downhole accidents, equipment failures, and termination conditions for MPD. It includes the following three steps:
- Establish emergency measures against downhole accidents by means of a well-control matrix.
- Establish emergency measures against the failure of equipment such as the RCD.
- Determine MPD termination conditions.
MPD should be terminated immediately when the following conditions occur:
- Well leakage is serious when drilling big cracks, which causes MPD failure.
- MPD equipment cannot meet requirements.
- Downhole complex accidents, causing MPD failure, occur frequently.
- Borehole conditions cannot meet MPD requirements.
MPD is successfully applied to the X gas field featuring offshore ultra-HP/HT conditions. The casing structure is optimized from seven or eight layers to five layers, and the well is drilled in a micropressure window of 0.01 to 0.02 sg without accidents.
Field Installation of MPD Equipment. The following steps describe the process of equipment installation (shown in Fig. 1):
- MPD equipment is installed offline, and the platform, logging, and cementing are remodeled.
- MPD equipment is installed online during dismantling of the fourth wellhead.
- The operational process is tested, and the pressure is qualified to meet operational requirements.
Field Application of MPD Equipment. MPD is used during the fifth spud. First, a wellbore dynamic pressure test is completed in order to allow accurate control of BHP. The ECD is dynamically increased to comply with the test by adjusting the opening of the throttle valve to control the SBP; fluctuations of BHP are within 1 psi.
Next, the SBP is applied during tripping out to avoid the kicks caused by swabbing pressure. In addition, time of tripping out is reduced to lessen the risk of sticking during pipe connection. The SBP is controlled to 120 psi during tripping out, which is equivalent to an ECD increase of 0.02 sg.
Effect of MPD Application. As previously mentioned, the casing structure is optimized from seven or eight layers to five layers. Also, drilling operation speed is increased significantly. In Well X-1, for example, the planned time was 90 days but the actual time saved was 26.37 days. Additionally, nonproductive time (NPT) decreases by 60% and the well cost is obviously reduced.
With increasing difficulty in exploration and development come more-frequent complex downhole accidents and higher drilling costs. Consequently, MPD will be more widely used because of its positive effect on NPT and expense, particularly in extreme narrow-pressure-window conditions, especially those involving volcanic rocks, carbonate rocks, faults, unconformities, fracture zones, piedmont structures, push structures, unusually high and low pressures, and severe leaks. MPD will be used extensively in deepwater drilling and will be applied to the development of gas hydrates. Generally, MPD in these environments yields time and cost savings.
For a limited time, the complete paper SPE 191060 is free to SPE members.
Managed-Pressure Drilling Used Successfully for Offshore HP/HT Exploration Wells
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