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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 (
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.
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.
Gonzalez Luis, Romar Alexandra (Blade Energy Partners) | Bedoya, Jorge (Blade Energy Partners) | Cenberlitas, Serkan (Blade Energy Partners) | Bacon, Will (Blade Energy Partners) | Gabaldon, Oscar (Blade Energy Partners) | Brand, Patrick R (Blade Energy Partners)
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.
Bermudez, Raul (TOTAL) | Ferro, Juan Jose (TOTAL) | Szakolczai, Cyril (TOTAL) | Birades, Christophe (TOTAL) | Conil, Luc (TOTAL) | Hernandez, Julian (Weatherford) | Brinkley, Ryan (Weatherford) | Arnone, Maurizio (Weatherford) | Carreño, Leonel (Weatherford) | Hollman, Landon (Blade) | Torres, Ivan (Halliburton)
The operation described in this paper is related an ultra-deep-water exploration well drilled in the Mexican waters of the Gulf of Mexico (GOM) and the first drilled by the operator in the area. From the onset of planning, the base case was to integrate a Managed Pressure Drilling (MPD) system into the drilling program to assist with pore pressure uncertainty, pressure ramp increase, and narrow Pore Pressure/Fracture Gradient (PP/FG) window operations including drilling, tripping, running casing and cementing, with the latter being a procedure that was not included in the initial stages of the project but discussed and implemented during the execution phase (
The well is located in a water depth of 3,276 m (10,748 ft). Given the exploratory nature of the well, there was an assumed pressure ramp that would demand an excessive number of casing strings with a conventional approach using an overbalanced Mud Weight (MW). During the drilling phase and taking advantage of the ability to adjust the bottom hole pressure instantaneously, dynamic pore pressure tests were performed to conclude that the pressure ramp was not as aggressive but lead to a narrow window that would not allow conventional cementing of the 13-3/8-in. casing.
Strong planning was required between the operator's engineering and operations teams, cementing services provider, MPD consultant, and MPD service provider team. The uncertainty about the actual size of the hole yielded an even more challenging Managed Pressure Cementing (MPC) engineering analysis (
The specific objective for the MPC application was to set 13-3/8-in. casing to isolate the critical formation and to safely continue drilling further stages of the well with an improved Leak-off Test (LOT) at the shoe.
This job represents the deepest water, and first from a drillship, for a managed pressure cementing job performed by both operator and MPD service provider. Additionally, a critical cementing operation was successfully performed using the Managed Pressure (MP) approach. The well construction objectives using MPD were also achieved while avoiding the use of a contingency liner which saved an additional USD3.5 MM from the planned AFE (
Gu, Qifan (The University of Texas at Austin) | Fallah, AmirHossein (The University of Texas at Austin) | Gul, Sercan (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | Chen, Dongmei (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | Moore, Dennis (Marathon Oil Corporation)
Non-aqueous drilling fluids used in deepwater drilling operations are conducive to the dissolution of formation gas during wellbore influx events, increasing the risk of gas kicks going unnoticed. This can lead to hazardous riser gas unloading events if kicks are allowed to pass the subsea BOPs and come out of solution at the bubble point at shallow riser depth. One possible solution to handle and even prevent these events is to generate enough backpressure using Managed Pressure Drilling (MPD) with a Rotating Control Device (RCD) to keep the dissolved gas in solution. However, for large kicks, the required backpressure may exceed riser pressure limits.
A novel kick handling procedure using a dilution control strategy (DCS) is proposed here to handle gas influxes and subsequent gas unloading events. The idea behind this DCS is to inject mud into the riser through the boost line while simultaneously slowing down the circulation rate through the drillstring as the dissolved kick passes the open subsea BOPs. The kick will then get diluted and will be distributed across a larger annular space leading to a significantly decreased gas concentration that can be more easily handled by the MPD system with lower backpressure.
The feasibility of the DCS is investigated in this paper using a multi-phase flow model which is validated against experimental data for a gas kick in oil-based mud. Simulation results for a demonstration case show that a kick entering the well at 18,500 ft with 2,250 kg gas can be thoroughly eliminated with a 3:1 dilution ratio (which is the ratio of riser boost rate to drillstring circulation rate) with approximately 620 psi backpressure when using an MPD system. To improve the applicability of the proposed DCS procedure in field practice, a data-driven approach is implemented using simulated data points to provide a fast estimation of the optimum dilution ratio (DR) to control the kick in real-time.
The service companies plan to co-market an emerging well control system that can integrate with established managed-pressure-drilling components to enhance well construction safety and efficiency. The next step is to move toward optimization, then automation. An intelligent drilling optimization application performs as an adaptive autodriller. In the Marcellus Shale, ROP improved 61% and 39% and drilling performance, measured as hours on bottom, improved 25%. A real-time deep-learning model is proposed to classify the volume of cuttings from a shale shaker on an offshore drilling rig by analyzing the real-time monitoring video stream.
This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet the drilling challenges faced in 5 consecutive wells drilled in South Texas, USA. This innovative solution integrates a state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as well control events, simultaneous kick-loss, and stuck pipe were mitigated, and an improved drilling performance with a reduction of NPT as compared to other directional drilling systems.
The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol are crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the Operator to tackle drilling hazards without compromising the directional drilling requirements.
This paper will summarize the 5 wells operations, the drilling optimization results, and the lessons learned from an integrated services point of view in terms of deliverables that made the difference on this project and allowed the Operator to achieve their objectives. In particular, the effective communication protocol between the directional drilling services, MPD services, and rig contractors to ensure safe operational alignment.
Krivolapov, Dmitry Sergeevich (Schlumberger) | Magda, Andrey Vladimirovich (Schlumberger) | Soroka, Taras Bogdanovich (Schlumberger) | Dobrokhleb, Pavel Yurievich (Schlumberger) | Evdokimov, Stanislav Aleksandrovich (Schlumberger) | Gagloyev, Georgy Georgievich (Schlumberger) | Novoselov, Aleksandr Vadimovich (Schlumberger) | Ramazanov, Aynur Ravisovich (Schlumberger) | Attia, Mohamed Samir (Schlumberger) | Zvyagin, Vasiliy Fedorovich (Lukoil Nizhnevolzhskneft) | Nabiullin, Renat Ildusovich (Lukoil Nizhnevolzhskneft) | Khamidullin, Denis Radikovich (Lukoil Nizhnevolzhskneft)
Managed Pressure Drilling technology became popular and widespread in Western countries in the early 2000s and has long been successfully used for drilling complex wells onshore and offshore projects (for example in the North Sea, Gulf of Mexico and etc.) In Russia this technology has found its application relatively recently and still has never been used for offshore drilling.
This article describes the results of the first MPD offshore application in Russia for drilling an HTHP exploration well in the Caspian Sea. A fully automated MPD set with early kick detection system (EKD) and back pressure pump (BPP) was applied, allowing to control pressure and drilling fluid outflow besides drilling, during connections. The drilling conducted using reduced mud weight in «near balanced» conditions, which compared to conventional strategy sufficiently reduced formation overbalance and losses risk as well.
Specialized MPD tests used to determine formation and fracturing pressure limit in uncertainty geological conditions, optimizing core sampling drilling and mud roll-over strategy.
The influx-management envelope (IME), Culen et al. (2016), is a decision-making tool for how to deal with an influx during managed-pressure-drilling (MPD) operations that offers a substantial improvement over the traditional MPD well-control matrix (WCM). However, in the case study by Gabaldon et al. (2017), it has been found that the simplified analytical solution introduced by Culen et al. (2016) makes the IME inaccurate for many real-world applications. This paper extends the original IME that considers the gas migration in the annulus as a single bubble, without making the simplifying assumptions that are required to make the equations explicit and analytically solvable. The underlying equations that are required to develop the IME are derived from first principles, and it is shown that using realistic equations of state (EOSs) for gas, and a single-bubble-type model, the equations for the IME can be numerically solved yielding less conservative limits. The proposed approach is significantly faster than constructing the IME through high-fidelity simulations. The proposed method allows for the calculation of a peak circulating pressure at the surface and the maximum weak-point pressure for a given kick size and initial shut-in pressure, as well as a kick envelope with respect to formation limits. This makes the contributions of this paper also relevant for traditional well-control situations. The effect of considering various simplifying assumptions on the resulting IME is studied, and different scenarios that compare the results of the proposed approach with that of the original single-bubble equation for the IME (Culen et al. 2016) are presented.