The drilling industry is an expensive part of the oil and gas sector, especially when drilling through a combination of low pressure and high pressure formations in exploration wells. When these zones are experienced while drilling, maintaining the BHP inside the drilling window is critical to ensure drilling fluid is not lost or formation fluids are not gained. Conventional solutions to help mitigate drilling through the troublesome formations include isolating thief zones, pumping LCM and cementing. These remedies could increase the overall project cost and add delays. One common problem associated with these solutions is how do you verify that the problem is corrected before drilling continues? From having analyzed a case study from the Duvernay wells in Western Canada, it demonstrates that Managed Pressure Drilling (MPD) was applied with lighter drilling fluids to help adjust the bottom-hole pressure (BHP) as desired before the problematic formations. Through the Winterburn formation, constant losses were recorded and LCM was squeezed by applying the required surface-back-pressure (SBP). A formation limit test for the Winterburn formation was recorded and the bottom-hole equivalent circulating density (BH ECD) at 1495 kg/m3, showed 283 liters losses. Due to continued losses into Winterburn Formation, 1.5 m3 of 1100 kg/m3 LCM pill was mixed, spotted into the annular and then squeezed on top of the formation. The LCM squeezing operation was started by applying 11,500 kPa static SBP which increased the BH ECD to 1700 kg/m3. After the LCM squeeze operation the well was reamed, and an extra 6 meters was drilled before performing a new formation integrity test (FIT). The second FIT was performed at the bottom of the formation and BH ECD had increased up to 1575 kg/m3 by applying 6,800 kPa SBP and the healing lost circulation zones were continued while drilling unconventionally through the MPD system. In the Beaverhill Lake formation, overpressured zones were encountered but drilling continued and dealt with both abnormal formation pressures. Lost circulation occurred in Winterburn formation with low pore pressure. The constant mud losses in this formation indicated that this problem was resulted from formation permeability, porosity and fractures that can be resolved by squeezing LCM. MPD brought value to the project by performing FIT in each formation, by monitoring and controlling precise LCM and cement squeeze operations. It also provided a solution for both types of abnormal formation problems as drilling continued and maintaining BHP inside the drilling window, increasing the overall safety of the project by detecting micro influxes and controlling them safely. According to the pressure profile window, this paper illustrates how MPD successfully drilled through an upper formation of low pore pressure, with lost circulation problem, and lower formation with abnormal higher pore pressure without setting a casing between them. It also discusses the effect an MPD-LCM squeeze has on the fracture gradient of a formation and how the drilling window can be increased and manipulated to the operator's advantage.
Narrow pore/stability pressure and fracture pressure margins (narrow operating window) can create severe complications during drilling operations. A slight change in the bottom hole pressure conditions can lead to significant Non-Productive Time (NPT) events like stuck pipe, fluid influx or lost circulation. In many cases, long wells with a narrow gap between pore/stability pressure and fracture pressure are impossible to drill with conventional practices because the annular friction pressure losses (difference between the dynamic and static pressure) are larger than the pore/fracture margin (Arnone & Vieira, 2009). Managed Pressure Drilling (MPD) enables operators to carefully balance between the pore and fracture pressure gradient by counteracting the lack of annular pressure losses (APL) when not circulating with the application of surface back pressure (SBP). MPD has the capability of providing a nearly constant bottomhole pressure with the proper compensation of pressure changes at surface. An accurate and real time determination of change in bottom hole pressure from dynamic effects is necessary to apply the correct SBP. This work investigates the accuracy of a novel approach in real-time MPD hydraulics modelling, which provides an alternative solution to the Pressure-While-Drilling (PWD) tool that measures the downhole annular pressure while drilling. The real-time hydraulics modelling proved to be accurate and allow for adjustments to be continuously made towards optimizing drilling efficiency, reliability, and safety without additional downhole tools.
Under-Balanced Drilling (UBD) practice is an optimized drilling approach, aiding in more reservoir recovery, too. Considering long-period production from some of Iranian oilfields and their correspondent pressure decline, it seems more necessary to replace UBD with the Conventional Overbalanced Drilling (OBD). Utilizing UBD in one of Iranian lowpressure fields named here "S" field however improves Productivity Index (PI) of the wells drilled besides minimizing drilling challenges and increasing Rate-of-Penetration (ROP) but extremely increasing risk of wellbore instability. This paper presents wellbore stability assessment of three layers of Mishrif reservoir using common reservoir data, correlated in-situ stress regimes and rock mechanics parameters based on its lithology & regional data. By employing a computer modeling software, stability limitations of the borehole as optimized Equivalent Circulating Density (ECD) were specified through the Finite Difference Method (FDM) and Mohr-Coulomb criteria. By applying the results of this modeling, about 6000 ft of 5 wells in "S" field was drilled with good hole condition and negligible instability problems while mentioned benefits of UBD was preserved.
In the continual search for Oil and Gas, more and more exploration wells are being drilled in High Pressure-High Temperature (HPHT) environments. Pore and Fracture pressure prediction and understanding the true drilling window in HPHT exploration wells poses significant challenges. Once the pressure profile is ascertained, then the next challenge is to drill and cement the well within those limits to avoid kicks, losses and maintain the integrity of the well. There are special challenges in cementing HPHT wells. These wells typically have a narrow drilling window which could make it very difficult to manage the bottom hole pressure correctly while cementing the open hole section. In any stage of cementing in this type of wells, hydrostatic, dynamic and circulating effects should be considered. These tight windows in HPHT wells, combined with the effect of temperature and pressure on mud density possess significant risks for cementing operation. Also physical and chemical behavior of cement changes in high pressure and temperature. This paper details the advantages of applying advanced Managed Pressure Drilling (MPD) technology during coiled tubing cementing operations in a case study HPHT well. This advanced technique not only allows for maintaining a Constant Bottom Hole Pressure (CBHP) but also reduces the additional costs associated with cement weight and additives. Furthermore, real time flow monitoring eliminates the down hole fluid losses which in conjunction with CBHP reduce formation damage. A precise managed pressure coiled tubing cementing program was analyzed and planned inclusive of operational procedures and risks management. The well was displaced to a lighter drilling fluid through coiled tubing, while keeping bottom hole pressure (BHP) constant slightly over the formation pressure by applying surface back pressure (SBP). Four different densities of cement slurries were pumped in the hole through coiled tubing and held bottom hole pressure constant during the entire cementing operation within 30 kg/m3 (0.25 ppg) pore pressure and fracture pressure window. Held annular pressure constant with the help of SBP during the eight hours of cement setting time to ensure that hydrostatic pressure would remain in place. This document demonstrates the successful application of managed pressure coiled tubing cementing operation. It also elaborates the recommended operational procedures, integrated MPD and Coiled tubing equipment setup, along with real-time graphs and data from the case study well.
The narrow drilling window of a High Pressure-High Temperature (HPHT) formation creates challenges in managing bottom hole pressure (BHP) during drilling and tripping operations. Managed Pressure Drilling (MPD) techniques have proven effective in accurately controlling downhole pressure, especially in HPHT environments. This study evaluates the capability of automated Managed Pressure Tripping (MPT) techniques in the Haynesville shale gas. The results show that this approach effectively controls the BHP while tripping, resulting in significantly improved operational efficiency, cost, and safety. MPD hydraulics are developed primarily based on the well profile, mud properties, and drill string dimensions. It uses analytical formulation to compute annular pressure losses along the wellbore every second. Subsequently, the required mud volume, pumping schedule, and applicable surface back pressures (SBP) for the displacement of the heavy pill are simulated to accurately follow the narrow drilling margin. This technique is provided to the field as guidance, and the heavy pill is displaced in multiple stages while maintaining constant bottom-hole pressure through MPD. This method is fully automated, given accurate drilling parameters, and can be controlled remotely from a remote operations center (ROC). Drilling the deepest HPHT Haynesville wells with a narrow drilling window was successful by using MPD techniques with a mud weight of 16.0 ppg. The pore pressure / stability limit of 17.0 ppg was less than 2% of the formation integrity test (FIT) limit of 17.3 ppg. The MPD hydraulics simulator enables real-time BHP calculations, coupled with a pre-engineered mud schedule, which improves overall tripping efficiency. The heavy pill was displaced in multiple stages during casing and drilling BHA runs based on FIT results. This method resulted in smooth tripping procedures with no reported wellbore stability issues or fluid loss concerns. In comparison to conventional tripping, managing adequate SBP along with a mud pumping schedule allows tripping execution within such a narrow margin. There were no reported observations of wellbore stability issues nor any significant fluid loss concerns. In this case study, the well was drilled to a total depth of 24,100ft MD, and the production casing was successfully run to the planned depth using a multi-stage displacement technique.
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