The Influx Management Envelope (IME) is a tool for operational decision making when managing influxes in Managed Pressure Drilling (MPD) operations. There have been numerous developments to the IME in recent years, and it is gaining traction over the MPD Operating Matrix (MOM). Calculation of the IME can be done in different ways. The original approach of calculating an IME described in (Culen et al. 2016), give less acceptable influx sizes than using multiphase simulations. Some of this can be attributed to the used Equation of State (EOS), and some to the distribution of gas in the wellbore. There is ongoing work for creating purpose-built tools for generating IME's that consider the gas as a single bubble, but with a real gas EOS, as well as considering gas distribution. In this work, the sensitivity to the model used when creating an IME is studied. This is done through comparing the single-bubble real-gas IME by (Berg et al. 2019) with IME's generated using Drillbench Dynamic Well Control as well as the commercial multiphase flow simulator Ledaflow for synthetic test wells. Discrepancies between the results are discussed and the differences in the underlying model and calculation procedure with respect to the end IME is elaborated.

In high pressure high temperature (HPHT) reservoirs and exploratory wells, especially in deep water, there is a higher degree of uncertainty, which can increase the operational costs due to non-productive time (NPT) and operational problems due to the unpredictable nature of these wells. For these challenging wells with narrow windows, Managed Pressure Drilling (MPD) techniques offer cost-effective tools to increase the odds for achieving well and cost objectives assurance. There are significant benefits from early implementation of MPD in the project life cycle. These benefits include from improving operational efficiency to risk mitigation and safety enhancement. However, there is an enormous potential that many operators have been missing. This is related to the incorporation of MPD as a driver in optimizing the well design, which could greatly increase the possibilities of reaching target depth, and potentially prepare to eliminate one or more casing strings. Current well design process hinges on the ability to manage uncertainties by company or regulatory requirements, such as kick tolerance and safety factors. This work addresses the value added from implementing MPD in early stages in the project life cycle through the analysis of case studies. The cost savings from the impact on the well design are also discussed. This work also presents a in depth discussion on the benefits, and enablers of this approach. Furthermore, it presents considerations by taking advantage of dynamic processes facilitated with MPD. Finally, new guiding criteria to aim to constitute a systematic and integrated approach to ensure well integrity and optimize well design while also considering the operational implications and integral cost benefits is proposed to the industry. This paper represents the initial phase of a compressive long-term project to integrate two main components of well design. These are MPD adaptive well design, and statistical analysis based on variations of load and/or strength.

The Spirit River Group in Western Canada has always been difficult to drill and complete due to the presence of natural faulting in shaley formations interbedded with coal. MPD techniques allow the successful drilling of these wells; however, completing these wells has been extremely challenging. On this well, getting liner to bottom without total losses should not have been possible.

To address this, a design that used a three mud system in combination with MPD was utilized. With a diversion sub placed at the heel, the wellbore fluid column consisted of a highly underbalanced drilling fluid in the lateral, a descending column of slightly underbalanced stripping fluid placed in the vertical section, and an overbalanced column of kill fluid backfilled into the annulus from surface.

During the liner run, this three-fluid system design smoothly reduces the hydrostatic pressure at proportional rates to the increase in liner surge. This balances the wellbore at the time the RCD is installed behind the liner. The combination of factors saw full returns to surface during the liner run and, once on bottom, allows the rig to break circulation for the final displacement to completions fluids.

With the successful implementation of this 3-fluid system, the operator was able to drill further, past 22,000’, as it is now possible to run and deploy the liner without expecting the loss of the wellbore's volume of fluid on these tight window wells.

The Austin Chalk is an upper Cretaceous geologic formation in the Gulf Coast region of the United States. For the purpose of this paper, this Austin chalk under consideration is in central Texas. The formation is known for having a wide range in pressure differential, making it difficult to predict the fracture and pore pressure limits on some of the wells. Due to this uncertainty, some operators tend to assume the well problems are related to ballooning/breathing. This assumption leads to drilling issues such as but not limited to stuck pipe, excessive mud losses, and tripping challenges.

With reference to this SPE paper, An operator had encountered some of the mentioned issues above in their previous wells and was looking for a CBHP MPD solution, capable of bridging their internal knowledge gap to becoming MPD aware. MPD was rigged up prior to drilling the horizontal production hole at ±13,000 ft MD. The initial mud weight was 10.5 ppg with MPD maintaining an 11.4 ppge. Later a high-pressure zone was encountered at ±13,500 ft MD requiring 11.6 ppge to control the formation fluid. Drilling continued until ±16,000 ft MD where an 11.5 ppge loss zone was encountered. Therefore this well had no drilling window.

The window stabilized after circulating a few bottoms up with backpressure and lost circulation material. MPD minimized mud losses/gains and helped reach TD safely. At TD, a bigger challenge was how to trip out without swabbing. The Tripping was achieved by placing a heavy pill above the high-pressure gas zone and avoiding the loss zone. When tripping pipe and casing, proper fill was achieved by circulating kill weight mud across the well with MPD. The casing and cementing operation was subsequently conducted and was successfully completed with the utilization of MPD.

Horizontal drilling in the Fruitland Formation, a Coalbed Methane (CBM) play located in the San Juan Basin (SJB), found across the states of Colorado and New Mexico can present a number of drilling and production challenges. Examples of these challenges include wellbore instability, severe fluid losses, high mud costs, formation damage, and post-well production issues.

Clear fluid brine systems such as Calcium Chloride (CaCl₂) and Calcium Bromide (CaBr₂) are usually preferred because of their compatibility with coals and their ability to minimize formation damage. However, these brines can instigate fluid losses, cause fluid handling issues, and create long-term production challenges. Coal instability in the horizontal play has historically led to events such as wellbore collapse, stuck pipe, lost Bottomhole Assemblies (BHAs), and challenges such as getting the pipe out of the hole at Total Depth (TD) and subsequently running completions. Ultimately, these problems led to sidetracks, incurring additional costs, time, and resources.

In May 2019, the Constant Bottomhole Pressure (CBHP) technique of Managed Pressure Drilling (MPD) was introduced to mitigate these challenges. Two wells with eight laterals and combined horizontal footage of ±46,000 ft were drilled using CBHP, maintaining 11.4 ±0.1 pound per gallon (ppg) Equivalent Circulating Density (ECD) and Equivalent Static Density (ESD) in the lateral at ±2800 ft True Vertical Depth (TVD). With a focus on safety and training, the mud weight was staged down from 10.8 ppg on the first lateral to 9.8 ppg on the second. The final six laterals were drilled with 8.6 ±0.2 ppg produced water. This paper will detail the planning, training and staged implementation of CBHP MPD with produced water. It will briefly discuss improvement in wellbore stability, cost reduction for drilling laterals, and enhanced production after switching to produced water.

Implementation of Managed Pressures Drilling (MPD) techniques provide substantial advantages for addressing difficulties in challenging wells. These benefits include not only the early influx and loss detection, but also Dynamic Influx Management. MPD provides the ability to circulate out an influx at drilling circulation rates while remaining within the primary well control barrier. Dynamic influx management is a trending topic within the industry, with its importance capturing the attention of planning and operational teams, regulatory bodies, and industry interest groups tasked with the development of recommended practices. Evolving from conventional kick tolerance to MPD kick tolerance has enabled dynamic influx management milestones, such as the adoption of the MPD operational matrix. More recently, the novel approach of the Influx Management Envelope (IME) has been increasingly adopted by the industry. This paper presents the state-of-the-art engineering analysis and operational considerations for dynamic influx management during MPD operations. As part of an integrated approach, this work considers three main aspects; 1) MPD kick tolerance, including concepts and its variables of interest, 2) IME generation and parameter sensitivity analysis, 3) generation of an MPD operational matrix. In addition, the advantages and disadvantages of various approaches to determining the limits of dynamic influx circulation are discussed.

When drilling challenging formations such as very thick highly fractured sour reservoirs or carbonate/karst formations, a lost-circulation zone can be encountered. This causes mud to be lost and gas kick to take place, making the drilling process uncontrollable. Blocking or plugging wide fractures is impossible in many cases, which results in severe safety issues associated with toxic gases.

This study investigates an application of mud cap drilling by injecting foam mixture into the annulus for well control in such harsh conditions. An annular fluid column with foam mixture can be used to prevent kicks and push the toxic gas back into the formation down along the annulus. This foam-assisted mud cap drilling process has been proved to reduce non-productive time and fluid expenses.

This study presents how to model and simulate the process with accurate foam characteristics when foams are used to suppress gas kicks under certain well and fluid conditions. More specifically, this study deals with three scenarios: Base Scenario with a relatively short response time such that the injected foams do not contact the formation gas, and Scenario 1 and 2 with a relatively long response time such that the injected foams interact with the gas, with and without foam coalescence respectively, at the foam/gas interface. The results show how mud-cap drilling parameters (such as pressure, foam density (or, equivalent mud weight), foam velocity, and foam quality) change at different operating conditions and scenarios. Non-Newtonian foam rheology, depending on bubble size and bubble size distribution as modeled by Wang et al. (2017), lies at the heart of this simulation study.

The objective of the paper is to present a case where a Managed Pressure Drilling (MPD) and an MPD Well Design process was used to design and drill a deepwater exploration well with an expected pressure ramp and narrow drilling margins while acquiring valuable subsurface data. The expected pressure ramp and narrow drilling margins combined with the uncertainty of subsurface data presented significant challenges to the well design team. Based on previous experience in the region, reaching well TD safely and efficiently using conventional drilling methods was predicted to be challenging. The MPD Well Design process enabled MPD techniques, including constant bottom hole pressure and dynamic influx management, to be integrated into well design process. MPD was also identified as a critical tool to collect dynamic pressure data and help reduce overpressure uncertainty. The drilling program, rig specific operations, and contingency procedures were developed accordingly. MPD was used to successfully drill through a pore pressure ramp and address a well control event in conjunction with conventional methods. MPD was also an enabler to optimize the location of the casing/liner shoes by identifying the pressure profile based on real-time pore pressure data. This feature was a key advantage to drilling deeper than planned and resulted in effectively saving one casing string. The proposed well design included five casing/liners, with potential for two contingencies. With the implementation of MPD, the actual well was drilled with four casings/liners to a deeper TD and met all evaluation objectives under budget. This paper presents a case for using MPD and the MPD Well Design process and its full capabilities to optimize all aspects of a well delivery process, including well design, safety, and subsurface data acquisition.

During the second half of 2018, an operator faced significant downhole issues during exploration drilling on a semisubmersible rig in ultra-deepwater Nova Scotia. While these challenges would have made this well a candidate for the use of traditional surface backpressure managed pressure drilling (MPD) technology, the predrill forecast did not indicate the need for MPD, and during execution, it was not practical to install MPD because of the required time and detailed engineering to retrofit the rig.

During the original attempt to drill this well, the operator was forced to abandon the 12 1/4- × 14 1/2-in. hole section after mud losses, followed by wellbore breathing and associated gas events from the mud flowback. The well was undrillable with conventional methods, and the wellbore was plugged back and sidetracked. On the sidetrack, continuous circulation technology was implemented to help maintain a more constant bottomhole pressure, navigate the narrow drilling margin between pore pressure and fracture gradient, and help prevent wellbore breathing and associated gas on connections.

The planning and execution of this technology that allowed the operator to successfully drill through previously difficult targets are discussed, along with lessons learned for future wells. Overall, more than 30 connections were performed, with an average of 600-gal/min connection flow rate with synthetic oil-based mud over the two hole sections.

Limited studies are available for modeling gas migration in risers. Outdated and small-scale models provide insufficient reliability, and a thorough mechanistic description of the problem is still not available. A significant part of the problem concerns understanding how pressure, temperature, liquid properties, and gas-liquid dynamics effect gas expansion during migration.

This paper provides information on Computational Fluid Dynamics (CFD) simulations performed on gas injections in three static and dynamic vertical fluid columns, with and without back pressure measuring 27-ft. and 330-ft. tall with 6, 12, 19.5 in. diameter. These CFD simulations analyzed the recorded gas expansion, change in pressure and temperature, and the volume fraction of the gas throughout the riser. In addition, these simulations also analyzed the change in flow rate, velocity, and the unloading effect at the inlet and outlet.

The 330-ft. pipe simulation demonstrated explosive unloading behavior with maximum discharge velocity and flow rate of over 2.8-ft./sec. and 6617.5-gpm., while the shorter pipes demonstrated relatively slower overflow. The case with a 330-ft. pipe also recorded a rapid change in temperature close to the top. Back pressure application at the surface minimized the effects of unloading and slowed down expansion.