Optimized Drilling by Improved Well Control Using MPD in Narrow Pressure Window

This paper presents a method used in combination with Managed Pressure Drilling (MPD) to determine real time pore pressures while drilling a deepwater exploration well. Not only was the pore pressure accurately determined but additional procedures were implemented to improve efficiency. This deepwater well was the first time MPD used on a semisubmersible rig in Myanmar by both operator and the drilling contractor. MPD was used on all the well sections below the surface casing with the main objectives for MPD listed as follows: Safe and efficient drilling of the well to planned TD. Elimination of contingency casing strings. Enhanced influx detection. Determination of pore and fracture pressure while drilling. The expected pore pressure based on seismic interpretation for the well was provided by the geoscience team. It was presented as minimum and maximum pore pressures. Fracture pressures were provided as sand fracture (minimum) and shale fracture pressures (maximum). A large uncertainty in pore pressures was expected. MPD was combined with real time pore pressure prediction to estimate pore pressures. MPD procedures were reviewed and amended as required to reflect the actual well architecture, actual equipment, and rig capabilities. Most MPD projects are designed to maintain a Constant Bottom Hole Pressure (CBHP) and not to determine pore pressures. Since a significant pore pressure ramp was expected as soon as drilling started below the surface casing a solution had to be found. Methods to make connections and dummy connections were reviewed and discussed to assist the determination of pore pressures using connection and background gas indicators. The devised procedure could be used for all drillstring connections including any dummy connections made throughout the entire well to provide the real time pore pressure team with consistent data. Additional procedures were developed to ensure that bottom hole circulating pressures were maintained using a combination of MPD choke pressures and increasing mud weights while drilling. The paper presents the procedures that were developed and implemented to successfully drill the exploration well to TD. These procedures have now been field tested and proven to be successful not only to accurately determine pore pressures but also to ensure mud weight management. The procedures will be used again on future wells to determine pore pressures and manage BHP to ensure that maximum benefits are derived from MPD operations on deepwater exploration wells.

Today, in search of oil resources, marginal wells with narrow pressure windows are frequently being drilled. This requires accurate and precise control to balance the bottom hole pressure (BHP) between the pore and fracture pressure of the reservoir. Managed pressure drilling (MPD) is a technique introduced to enable improved pressure control when drilling. This paper presents a cascaded control structure for BHP, choke pressure and choke position in MPD operations. Estimators for the unknown bottom hole flow and uncertain BHP are developed to improve pressure control performance. The presented method is evaluated with field operation data from drilling two 4000 m deep wells. The results show that the pressure is maintained within acceptable margins through a series of operations.

With more wells drilled into hydrocarbon bearing formations, operators are forced to drill into challenging plays with narrow pressure margins. Successful drilling in depleted zones with isolated, high-pressured fractures is difficult and requires managed pressure drilling (MPD). Once the well is drilled, the operator should achieve zonal isolation by pumping cement across the zones of concern without inducing lost circulation or gains. Managed pressure cementing (MPC) pumps cement in a hydrostatically underbalanced environment with pressure applied at surface using an automated choke system (ACS) to maintain a target equivalent circulating density (ECD) between the highest pore pressure (PP) and the lowest fracture gradient (FG) of the well. Communication between cementing operations and MPD software allows automatic system adjustment without manual input. The MPD hydraulic model tracks multiple fluids with different densities, rates, and rheological properties throughout the wellbore. A rig pump diverter (RPD) allows for constant bottomhole pressure (BHP) by manipulating the surface choke pressure if unplanned shutdowns occur. Successful MPC operations have been conducted using the ACS in the Paradox Basin with narrow pressure windows and in the Piceance Basin with high reservoir pressure zones. The nature of cement operations can be unpredictable, but through the automatic managed pressure cementing (AMPC) process, a target ECD can be identified and constant BHP maintained to design and deliver dependable barriers tailored to minimize risk and maximize production.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194536, “Managed Pressure Cementing (MPC) Within a Narrow Pressure Window, Deepwater Gulf of Mexico Application,” by Michael Teoh, Sharief Moghazy, SPE, Keith Smelker, and Roger Van Noort, SPE, Shell, and Juan C. Valecillos, Julian Hernandez, and Maurizio Arnone, Weatherford, prepared for the 2019 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Amsterdam, 9–10 April. The paper has not been peer reviewed. Managed-pressure cementing (MPC) is an important technique for primary cementing operations in wells with narrow pressure margins between the pore and fracture gradients. This paper presents the design considerations, methodology, and results of two deepwater MPC operations conducted to cement production casing strings within a target operating window of approximately three-tenths of a pound.•Modern transient hydraulic modeling software permits the calculation of adequate surface pressure levels to control the annular pressure profile during the different stages of a cementing operation. On the basis of a•predetermined annular pressure target, different variables can•be designed to produce surface and•downhole pressures within existing limits of a particular operation. This capability, combined with modern managed-pressure-drilling (MPD) systems, enables accurate control of the annular pressure profile during cementing and makes it possible to obtain near-constant bottomhole pressure (BHP) throughout the cement•placement operation while using statically underbalanced mud columns. Introduction Preventing fluid losses during slurry placement generally is necessary in achieving the goals of a cementing operation. Effective zonal isolation behind the casing or liner wall is related intimately to preventing losses toward, and flow from, the formation during and after the cement circulation. When cementing a casing or liner string within limited openhole pressure margins, maintaining the bottomhole circulating pressure below the fracture gradient is not feasible in most cases when using conventional methods. Cementing fluid dynamics are generally more complex than the fluid dynamics observed during the drilling phase. Additionally, multiple fluids with diverse properties and with generally higher viscosities are pumped at different rates. All of these factors, combined with high cement-slurry densities, contribute to equivalent circulating density (ECD) levels at the well bottom during cementing that are not observed while drilling. In many cases, these ECD levels lead to losses or even fracturing of the formation. The inability to measure downhole pressures during the operation adds to the complexity of the cementing job. In recent years, MPD systems, with their ability to control precisely the well pressure profile, have emerged as an alternative solution to the problem of cementing efficiently within tight margins in deepwater wells. Used together with advanced hydraulic modeling software that can predict fluid properties accurately downhole under dynamic and static conditions, the latest MPD systems are enabling drilling engineers to manipulate variables that in the past were out of reach during the drilling and cementing-job planning. The two wells discussed in the complete paper were drilled in the Gulf of Mexico (GOM) in approximately 8,500 ft of water from rig kelly bushing to mudline. The paper provides definitions related to the MPC subject, an overview of the applications, a summary of the engineering approach and calculations, and the results obtained during these cementing operations.

An unconventional shale gas drilling project in the Rincon de la Ceniza onshore field is being developed to reach the Vaca Muerta formation, which is overlaid by the shallower and troublesome Quintuco formation. This formation is composed of two over-pressurized layers located in the middle and near the bottom of the formation. The Lower Quintuco formation may also be naturally fractured, containing oil and gas, trapped in an over-pressurized regime, creating an operational drilling hazard. Pore pressure prediction has a high degree of uncertainty, making the proper mud density selection a difficult task. Offset wells drilled conventionally have incurred significant Non Productive Time (NPT) due to well control events, where accurate kill mud weight definition has been challenging due to the presence of natural fractures. The objective for the drilling campaign was to define an optimal and reliable drilling method that would address the challenges of pore pressure uncertainty in a safe and cost-effective way. The first step was to implement Managed Pressure Drilling (MPD) to control over-pressurized zones and determine the more suitable mud density to control the well. The previous vertical wells were drilled conventionally having Quintuco and Vaca Muerta formations isolated from each other with two different casing strings. The drilling strategy was redefined and implemented in three horizontal wells, but in this time both formations were drilled together in one hole section. The intention was to enable drilling with the minimum mud weight possible, allowing higher Rate of Penetration (ROP) consequently. This was possible to achieve by maintaining constant bottom hole pressure conditions at variable Anchor Point depths along the open hole while drilling Quintuco formation. Before drilling the horizontal section in Vaca Muerta formation, a small and controlled constant underbalanced condition was created and fixed at the deepest Anchor Point depth which was as close as possible to the transition zone between both formations. This successful strategy allowed improving drilling performance, by reducing drilling time from 123.4 to 51.7 days per well and reducing NPT from 30.5% to 7.5% by managing well control events, eliminating one casing string and improving drilling efficiency to increase the ROP. Consequently, the cost of the well was reduced 5.5 MM USD/well when compared with the last well of the campaign without any Health Safety and Environment (HSE) issues. This paper presents the drilling strategy followed to overcome well control events and associated NPT when drilling an unconventional shale gas play with highly uncertain pore pressure profile. Planning, implementation and results from the project are presented.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194097, “Real-Time MPD Optimization in Challenging Scenarios,” by Guilherme Siqueira Vanni, SPE, André Alonso Fernandes, Gleber Tacio Teixeira, Antonio Carlos Vieira Martins Lage, André Leibsohn Martins, SPE, and Felipe de Souza Terra, Petrobras, and Marcelo de Souza Cruz, Fabio Rodrigues G. da Silva, and Cristiano édio Dannenhauer, Engineering Simulation and Scientific Software, prepared for the 2019 SPE/IADC International Drilling Conference and Exhibition, The Hague, 5–7 March. The paper has not been peer reviewed. This work focuses on the development of specific methodologies to support managed-pressure-drilling (MPD) operations implemented on real-time diagnostic software. The developed methodology proposes as output ideal operating parameters, such as choke pressure, pump-flow rate, or adjustments related to drilling-fluid properties. The methodology considers the best approach to meet the restrictions imposed by the operational window. The real-time optimization procedures proposed are a further step to ensure reliability of MPD operations in challenging scenarios. Real-Time MPD Optimization Specific modules were developed from a drilling-problem diagnostic software to provide real-time support for MPD operations. The primary advance represented by these modules is the consolidation, in a computational tool, of MPD best practices. The tool, which uses real-time drilling data as input, will propose and enable immediate action in the event of anomalous situations or ones not predicted in project planning. Dynamic Pore-Pressure Test (DPPT) and Dynamic Formation Integrity (DFIT) Procedures. These procedures allow a more-accurate estimate of values for pore and fracture pressures, respectively. These procedures are suited particularly for drilling in narrow operating window scenario, because they allow correction of geological-profile data obtained previously with current field geopressure. Thus, the probability of gain and loss events becomes smaller in an MPD operation when compared with a conventional drilling scenario. During these tests, in each pressure step performed in the choke, the software calculates the volume balance related to the compression or decompression of the fluid in the well. The software calculates the volume that decreased from the active tank (DFIT) or increased in the active tank (DPPT). The software also calculates the volume balance related to the compression (DFIT) or decompression (DPPT) of the fluid in the well. These calculations determine whether these volume variations, both real and expected, follow the same magnitude. The difference between them is the criterion used to stop both procedures (DPPT and DFIT). In Petrobras’ drilling operations, this proposed limit normally is set to 2 bbl. This preset threshold is a minimum acceptable value to consider that a gain or loss is occurring. If this difference surpasses the limit value, the module triggers a message warning the rig crew. After these procedures, the simulator updates the operating window, using real downhole data [effective circulating density (ECD)] in a conservative way. The logic adopted for updating is to use the largest value between the DPPT and the value of the pore gradient present on the project. For the fracture gradient, inverse logic is adopted; the lowest value between the DFIT and the fracture gradient obtained on the project is used. Fig. 1 illustrates the pore-gradient update.

Well control is one of the most crucial sectors in drilling engineering. Human lives and safety depend on the correct execution of the engineering design. Managed Pressure Drilling (MPD) is a new technology that has recently emerged in the oil and gas industry. It has special well control abilities supported by the RCD to continue drilling or carry operations that involve pipe rotation, while circulating out a gas kick. This thesis examines the effect of pipe rotation on casing pressure profiles within MPD kick circulation application. The analysis was carried on real scale kick experiments. These experiments were carried in a controlled environment that mimicked downhole conditions with a gas influx entering the wellbore. Both water based mud and oil based mud were evaluated. Then, the real scale tests analysis was coupled with the effect of pipe rotation through the application of correlations. The correlations estimate the change in frictional pressure loss in the annuls for non-Newtonian fluids with pipe rotation. A study of the effect of a larger size gas bubble breakage into smaller size bubbles on the maximum anticipated casing pressure is also included in this research. The thesis was divided into three models: (1) dissolved gas model in OBM. (2) single bubble model in WBM. (3) dispersed bubble model in WBM. The first two models studied the effect of frictional pressure changes on the anticipated casing pressure. The dispersed bubble model studies the effect of breaking the gas bubble into many very small bubbles. The practical outcome is to further the precision of the estimation of downhole pressure limits since MPD address narrow fracture-pore pressure window and to find if casing pressure changes would have any effect on the RCD rating selection and if the rotation can be safely conducted.

Due to the impact of the geological nature of the Tengiz field, which is dominated by high fracture areas and has associated drilling challenges such as lost circulation, a first development trial well named as a "High-Pressure Lower Slope Development" (HPLSD) project well was initiated. The well was designed by the engineering team of Tengizchevroil to be horizontal producer with the longest lateral section in Kazakhstan. This paper describes Managed Pressure Drilling (MPD) and Managed Pressure Cementing (MPC) aspects of the HPLSD project. MPD was utilized on 12 ¼ × 13 ½", 8 ½", and 6" sections to improve drilling performance. The system was used to control bottom hole pressure and manage background gas, it was further applied to minimize loss/gain scenarios and allow drilling through the "narrow" margin between pore and fracture pressures, along with decreasing the wellbore instability and differential sticking risks. Constant Bottom Hole Pressure (CBHP) technique helped to successfully cement the 7 ¼" liner avoiding any losses of cementing fluid into the wellbore. The primary cementing of the 8 ½" hole section compiled of reservoir embedded with the layers of anhydrite and limestone has been associated with the risks of losing the cement slug, and therefore creating the risk of not achieving adequate cementation. The MPD system helped to successfully run in hole the 7 ¼" liner, cement it and finalize the 6" hole section running the Lower Completion in constant bottom hole pressure mode. MPD results examined in this paper provide the proof that MPD system is as reliable tool not only for drilling, but also for managed pressure cementing, compensation of swab effect, managing small volumes of influx, and circulating associated gas while drilling. The additional capabilities offered by MPD technology in effectively controlling wellbore pressure profiles has led to MPD tools becoming a commonplace in Tengiz drilling operations.

Carbonate formation is widely distributed in China, mainly showing the sensitivity of the target formation and the development of fracture and cavity types and narrow pressure window. Drilling complicated conditions such as formation leakage or bottom hole pressure less than formation pressure due to gas entering wellbore occur from time to time. To solve these problems, calculating the bottom hole pressure accurately and conducting managed pressure drilling (MPD) for fractured carbonate formation are necessary. In this study, the single-phase hydraulic model based on H-B rheological model is calculated. According to the characteristics of fractured carbonate formation, the drilling fluid leakage model is obtained. By coupling the leakage model with the single-phase wellbore hydraulic model, the bottom hole pressure calculation method is suitable for fractured carbonate formation, which can provide reference for managed pressure control drilling technology. Such a technology is verified by Bozhong X well through the above calculation method of bottom hole pressure. The model is used to simulate the leakage behavior of transverse and longitudinal fractures. Moreover, the variation characteristics of the leakage rate and cumulative leakage amount of the drilling fluid in the fracture are investigated. By comparing the loss control with conventional drilling and MPD, the advantages of controlled pressure drilling operation in the loss control are described.

1. Abstract As exploring for oil and gas traps becomes more extreme in term of depths, the companies start to search for modern technologies and equipment for drilling under HPHT conditions. One of the challenges of HPHT deep water well is narrow margin between the fracture pressure gradient and pore pressure gradient, therefore prediction and control of well hydraulics is indeed vital. The solution for the HPHT deep water challenges is a technology of Managed Pressure Drilling (MPD). Riser less drilling is one of the types of MPD. It uses two different annular pressure gradients for maintaining required bottom hole pressure to drill a well This study presents a new approach for accurate determination and optimization of well hydraulics for MPD (Riser less drilling) under HPHT conditions. This approach depends on accurate prediction and determination of borehole temperature, mud density and pressure, mud rheology and hydraulics profiles inside wellbore under HPHT conditions. This work shows the comparison between well hydraulics that calculated by constant fluid properties (i.e independent on pressure and temperature conditions) and well hydraulics that calculated by taking into account the effect of pressure and temperature on fluid properties. This paper also shows the effect of drill pipe tool-joint, drilled cutting, annular eccentricity and drill string rotation pressure losses on well hydraulics for MPD. The objectives were achieved by designing computer simulator called ‘’HPHT MAT’’. A case study by using ‘’HPHT MAT’’ simulator to show the correct procedure for optimization the well hydraulics of MPD is introduced. The results show that accurate prediction and determination of temperature and mud rheology modelling is highly required for accurate planning and designing of MPD hydraulics. The pressure difference between the drill pipe and annulus in Riser less drilling must be taken into consideration during the calculation of the density, plastic viscosity, yield point and ECD profiles inside wellbore. Neglecting the effect of pressure and temperature on mud properties in the well hydraulics calculation will lead to erroneous results which may lead to a kick or a loss of circulation. Pressure losses due to drill pipe tool-joint, drilled cutting, annular eccentricity and drill string rotation have significant effect on well hydraulics of MPD. New technique for calculating the well hydraulics of MPD by using finite difference calculation is developed. 2. Keywords: <span style=font-size: 10.0pt;font-family: times= new= roman,serif=>Dual Gradient Drilling; High Pressure and High Temperature Condition; Managed Pressure Drilling; Riser Less Drilling

When drilling from a deepwater semisubmersible rig, the operator encountered wells problems, including lost circulation, influxes, and ballooning, in the 14 3/4-in. hole section. Managed Pressure Drilling (MPD) equipment that helped to mitigate these issues specifically, when stripping in the hole with the bottom hole assembly through the Rotating Control Device (RCD) bearing assembly while managing surge and swab pressures, monitoring the well while displacing heavy mud into the open hole, conditioning the contaminated mud, removing gas from the well, and fingerprinting the flow back to verify ballooning against influxes, and finally stripping out of the hole. The operator experienced a total loss of circulation at the 16-in. liner shoe at 1,633m while drilling the 14 3/4-in. hole section. Several lost-circulation material (LCM) pills of different weights were pumped to cure the losses without success. Then the well was flow-checked, the gain was noted, and the well shut-in. Having the MPD chokes and the Coriolis flowmeter in place made it possible to adjust the surface back pressure (SBP) accordingly within a small operating window. As a result, the operator could achieve the key objectives of stripping the drillstring in the hole, stripping out of the hole, and rolling over to spot 1.88SG heavy mud on the bottom using the pump and pull method. After LCM was pumped and a hesitation squeeze performed, well operations were stabilized, and the casing was run to a 2,111m measured depth. Advanced flow monitoring enabled the MPD to determine the required SBP for balancing the well. MPD applied 60psi of SBP and noted a gain of 8.3bbl/hr from the flowmeter. Next, MPD applied 65psi SBP and the well was static. Then, MPD applied 70psi SBP, and the well took losses at a rate of 19bbl/hr. MPD allowed to successfully strip the BHA in the hole through the RCD bearing assembly to the shoe. Correct string displacement observed via the MPD Virtual Trip Tank, achieved by adjusting the SBP from 62psi to 125psi. The closed-loop circulating system enabled safely circulating and conditioning contaminated gas-cut mud in the hole back to homogeneous mud. MPD reduced SBP incrementally and fingerprinted flow back at every step to give assurance that well ballooning, and not influxes, caused the flow back. Dynamically adjusting SBP, coupled with advanced monitoring of the returns flow using the Coriolis flowmeter, enabled balancing the well despite the challenges of a mixed mud gradient in the annulus and a narrow operational window. The MPD riser consisted of an RCD below-tension-ring (BTR)-s, flow spool, and top and bottom crossovers. Rig modifications involved fabricating the fixed piping to allow integrating MPD equipment with the rig system.

Conventional open-to-atmosphere mud returns systems present a challenge when attempting to obtain energy resources that have previously been deemed economically or technically impossible to drill due to narrow drilling windows. A narrow drilling window significantly reduces the possibility of drilling to targeted depth effectively and efficiently from cost and safety perspectives. However, it is not always the pore pressure and fracture pressure gradients that define the drilling window, as has been observed in a field in East[MA(1] Java Province, Indonesia. In this instance, the actual drilling window lay between the wellbore instability and mud losses pressure gradients. Having the bottom hole pressure lower than the wellbore instability pressure would risk collapse of the wellbore, resulting in stuck pipe, or worse, a fishing job and requirement to sidetrack the well. Thus, a steady bottom hole pressure within that window was deemed critical to successfully drill to the section target depth. The application of Managed Pressure Drilling (MPD) was selected to drill the narrow drilling window and has resulted in being able to successfully drill to the targeted depth without wellbore collapse. Data acquired from system-recorded drilling parameters enabled analysis of the wellbore condition and adjustment of parameters leading to a successful operation. Calculated friction pressure, ECD trend line, flow behavior and most importantly surface back pressure were compared as analysis subjects. The utilization of MPD equipment, including Rotating Control Device (RCD) and Automated MPD Choke Manifold, enables surface back pressure to be applied to create the required bottom hole pressure sufficient to maintain wellbore stability within the narrow drilling window. With real-time results being applied on site, as described further in this paper, drilling hazards related to wellbore instability were significantly minimized, if not completely eliminated.

A unique problem of drilling oil and gas wells in deepwater is the narrow window between the formation pore pressure and fracture pressure. The current drilling practice with constant-gradient of drilling fluid requires excessive casing programs and larger, more expensive rigs to drill the formations. Although different techniques, such as dual-gradient drilling, have been used to ease the problem, they are limited to certain geological conditions. This study investigated the possibility of using heavy foam as the drilling fluid to solve the problem. The heavy-foams studied include brine-base foams and barite-water-base foams. We found that the brine-base foams have lower foam stability, density, and quality index. But they have better flow properties. The barite-water-base foams have higher foam stability, density, and quality index. But their flow properties are not as good as the brine-base foams. We conclude that heavy foams can be made to have properties suitable for drilling deepwater wells to reduce casing programs. Use of the heavy foams will create larger boreholes for oil/gas production with much lower cost of well construction. Tremendous savings in the deepwater development are expected with this new technology. Introduction Since the geological evolution in the deepwater is thought to be similar to that in the continental shelf, huge hydrocarbon reservoirs are expected in situ. However prospecting for oil and gas has considerable risks and expenses. One of the major problems encountered is the narrow window between the pore pressure and fracture pressure gradients which occurs with increasing water depth. Typically, in deepwater environments, an increase in depth is accompanied by an increase in undercompaction of sediments, which causes a rise in pore pressures with decreases in both the vertical and horizontal stress gradients, so resulting in a closure of the pore pressure - fracture gradient window. This margin can be so close that a slight decrease in borehole pressure can lead to fluid influx, whilst a slight increase in borehole pressure can result in a loss of circulation (Sangesland, 2006). An excessive number of casings, i.e. 4 - 6 or even more casing strings, may be needed to reach the desired depths, resulting in grossly insufficient borehole sizes making the wells economically impractical. The use of heavy foams as a drilling fluid is investigated to suggest a methodology for drilling in deepwater that minimizes the well control challenges and the limitations that are currently experienced in deepwater operations that allow for drilling longer hole-sections not considered possible with conventional drilling fluids. The purpose of using heavy foams as the drilling fluid would be to control any rapid increase in pressure gradient which could fracture shallower formations especially as experienced in the shallower formations in deepwater. The heavy foam would in essence operate on a similar principle to the dual gradient managed pressure drilling concept, with the higher foam density at the point of drilling and the lower densities further up the wellbore. The dual gradient method involves lightening of the drilling fluid by diversion of the returning fluid to the surface via a separate riser rather than the casing annulus. This diversion seperates the heavy mud above the sea bed from the wellbore, blocking it from exerting its influence on the exposed formation in the well. The hydrostatic head below the mudline is therefore made equivalent to its expected value with the rig at the ocean floor while maintaining sufficiently high drilling fluid density to contain formation pressures. The heavy foam profile would be similar to that of the dual gradient fluid except that it maintains a varying gradient and so drilling can be carried out in a tight operating window between the fracture pressure and the pore pressure to deeper depths before the need to set casing. The main objective of this study is to investigate the possibility of generating heavy foams useful for deepwater drilling. Heavy brine and barite were used for weighting up the drilling fluid in this study. Several foaming agents and several other chemicals were used to form foams in brine with nitrogen gas.

Experience is presented from 20 years of formation- pressure-while-drilling (FPWD) to capture best practices, dispel common misconceptions and demonstrate unique techniques when faced with specific well and formation scenarios to enable efficient, fit for purpose data capture. Challenges, after all, are the main driver behind innovation and progress. A historical review of more than 10,000 FPWD tool runs has been conducted, salient data summarized, analyzed, and presented to gain insights. Examination of all stuck pipe &amp; lost in hole (LIH) events with an FPWD tool present in the bottom hole assembly (BHA) was performed to understand the sticking mechanism and root cause and, if any relationship with formation pressure acquisition was present. Specific acquisition challenges resulting in a wide range of upgrades in tool specifications or capability are explored and detailed. Early use of FPWD was primarily used for pore pressure calibration, to navigate narrow mud windows and to optimize drilling fluid density, particularly sub-salt. The ever-present supercharging phenomenon more pronounced in a while drilling environment curbed the use of FPWD measurements for detailed pressure characterization. This has now evolved with robust operational practices, better understanding of supercharging magnitude and operators challenging wireline conveyed logging on both time and risk incurred for extensive pressure surveys in a full range of environments in terms of overbalance, mobility and well geometry. Evolution of FPWD capabilities to operate in high overbalance environments and pretest performance techniques, coupled with managed pressure drilling (MPD) capabilities in ultra deep-water wells, have acted as enablers for operational success. Custom digitally enabled acquisition workflows that are tailored for specific formation conditions have also significantly aided in seal and pretest success rates. Collectively, these advancements assist operators to optimize drilling operations, minimize uncertainties, and successfully accomplish well and data objectives. With deepwater drilling trending towards tighter drilling margins, addition of newer micronized mud systems and substantial depletion, the environment has become more complex. The relentless focus on efficiency and reduction in Non-Productive Time (NPT) continues, while at the same time operator experience has diminished.

Drilling wells in depleted reservoirs is often characterised by a narrow operating window between formation pore pressure and fracture pressure. Drilling High Pressure High Temperature (HPHT) wells into a narrow margin reservoir is even more challenging, and Managed Pressure Drilling (MPD) techniques may be required in order to operate within safe limits. Managing the annular pressure profile during MPD operations requires a robust and reliable drilling control system. The presented work treats some challenges and possibilities regarding a MPD choke control system under evaluation for a planned HPHT well in the Kvitebjørn Field in the North Sea. Here pressure management is to be achieved by regulating the choke opening and thereby compensating for downhole pressure variations. Methodologies for automatic choke control during the drilling operation are assessed. A dynamic fluid flow model is used to calculate well pressures for application in the choke control algorithms, and to simulate pressure response in the well. The performance of choke control during drilling operations is evaluated and results from simulations are presented.