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Gabaldon, Oscar (Blade Energy Partners, Ltd.) | Gonzalez Luis, Romar (Blade Energy Partners, Ltd.) | Brand, Patrick (Blade Energy Partners, Ltd.) | Saber, Sherif (Blade Energy Partners, Ltd.) | Kozlov, Anton (Blade Energy Partners, Ltd.) | Bacon, William (Blade Energy Partners, Ltd.)
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.
Parker, Martyn (Pruitt Tool & Supply Co.) | Seale, Marvin (Red Willow Production Company) | Nauduri, Sagar (Pruitt Tool & Supply Co.) | Abbey, James (Red Willow Production Company) | Seidel, Frank (Seidel Technologies, LLC) | Okeke, Ernest (Pruitt Tool & Supply Co.)
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.
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.
Kaldirim, Omer (Texas A&M University) | Kaldirim, Ebubekir (Louisiana State University) | Geresti, Cameron (Texas A&M University) | Manikonda, Kaushik (Texas A&M University) | Schubert, Jerome J. (Texas A&M University) | Hasan, Abu Rashid (Texas A&M University)
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.
Managed Pressure Drilling is one of several techniques gaining traction on critical wells with very tight pore and fracture pressure windows. In order to stay within these narrow mud weight windows it is critical to understand the bottom hole pressures. Some efforts have been made to combine surface modeling with downhole measurements during the actual drilling phase utilizing data sent to surface by mud pulse telemetry. However, during liner running and cementing operations this data is generally not available. Due to the narrow annular clearances around the liner and the heavier slurries used during cementing the chances of exceeding the fracture gradient are greatly magnified. To compound this during most cementing operations in managed pressure situations the surface measurements, and therefore the associated models based off them may bear no relationship to what is happening downhole, particularly as the cement can be effectively in freefall inside the pipe. Measurements can be, and are, compared both before and after the actual job, but during the critical time of the actual cement job and displacement there is often no indication of what is actually happening downhole.
As stated above the telemetry system most utilized during drilling is mud pulse telemetry. However, as these systems occupy the pipe bore, and require a full mud column inside the pipe with a flow rate above a minimum threshold, then they are not used during cementing and liner running operations. To overcome these limitations a distributed measurement and acoustic telemetry network was run incorporated in the drillstring. This network sends data including annular and bore pressures, both from directly above the liner-running tool, but also distributed back along the string to surface. Acoustic telemetry transmits through the steel wall of the drillstring and therefore is independent of flow or fluid and can send data whilst tripping as well. Additionally the tools are fully through bore allowing the passage of cement darts and slurries with no real restriction. As the network also supplies interval measurements, then the passage of the different stages of the cement job can be seen as they move both down the pipe and back along the annulus.
This paper will show, through actual field results, what is really happening downhole in the critical time of running the liner to bottom and during the managed pressure cement job. Results will be compared with traditional surface measurements. We will describe how we used downhole and interval calculations of friction factors and equivalent circulating densities to model what is happening in and around the liner during the cement job. We will discuss the application of the data, and the resultant algorithms and calculations derived from this to affect subsequent jobs and to improve decision-making and therefore the safety and efficiency of these critical cement jobs.
As can be imagined the techniques thus described are new to the industry for real-time applications and further work is anticipated in delivery and interpretation of the results to further enhance this type of solution. A view forward will also be given in the conclusions on where this technology has the potential to go.
Godhavn, John-Morten (Equinor) | Olorunju, Banzi (Equinor) | Gorski, Dmitri (Heavelock Solutions) | Kvernland, Martin (Heavelock Solutions) | Sant'Ana, Mateus (Heavelock Solutions) | Aamo, Ole Morten (Norwegian University of Science and Technology NTNU) | Sangesland, Sigbjørn (Norwegian University of Science and Technology NTNU)
This paper describes measured and simulated downhole pressure variations ("surge and swab") during drill pipe connections when drilling an ultra-deepwater well offshore Brazil on the Carcará field. Floating rig motion caused by waves and swell ("rig heave") induces surge and swab when the drill string is suspended in slips to make up or break a drill pipe connection and topside heave compensation is temporarily deactivated. This is a known issue in regions with harsh weather such as the North Sea, where pressure oscillations of up to 20 bar have been reported during connections. Recorded downhole drilling data from the Carcará field reveals significant pressure oscillations downhole (in the same order of magnitude as in the North Sea) each time the drill string was suspended in slips to make a connection in the sub-salt 8 ½" section of the well. Mud losses were experienced around the same well depth and they might have been caused by surge and swab.
Measured surge and swab pressure variations have been reproduced in an advanced proprietary surge and swab simulator that considers rig heave, drill pipe elasticity, well friction, non-Newtonian drilling mud, well trajectory and geometry. Moreover, findings in this paper suggest that surge and swab was in fact significantly higher than recorded by the MWD (Measurement While Drilling) tool. The true magnitude of surge and swab is not captured in the recorded MWD data due to low sampling frequency of the downhole pressure recording (one measurement every six seconds, a standard downhole pressure sampling rate used on many operations today).
This work shows that surge and swab during drill pipe connections on floaters may challenge the available pressure window for some wells even in regions with calm weather such as Brazil. Managed Pressure Drilling (MPD) is a technique that improves control of the downhole pressure. It is, however, not possible to compensate fast downhole pressure transients, such as heave-induced surge and swab, using MPD choke topside. This is due to the long distance between the choke and the bit, which translates into a time delay in the same order of magnitude as typical wave and heave periods. A downhole choke combined with continuous circulation is one of potential solutions.
Surge and swab during drill pipe connections can result in a loss or an influx and should be considered in the well planning phase when mud weight, section lengths, etc. are selected.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality. All three can lead to poor decisions regarding which work to undertake, what issues to focus on, and whether to forge ahead or walk away from a project. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets.