MANAG MASTER OF IN INDIA

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1 MANAG ED PRESSUREE DRILLING: Experimental and Modeling Based Investigation DISSERTATION SUBMITTED IN PARTIAL FULFILMENT OF THE REQUIREMENT FOR THE AWARD OF THE DEGREEE OF MASTER OF TECHNOLOGY IN PETROLEUM ENGINEERING By DINESH KUMAR Roll No. 08MT1003 SCHOOL OF PETROLEUM TECHNOLOGY PANDIT DEEND DAYAL PETROLEUM UNIVERSITY GANDHINAGAR, GUJARAT, INDIA 18 th January 2010

2 MANAGED PRESSURE DRILLING: Experimental and Modeling Based Investigation DISSERTATION SUBMITTED IN PARTIAL FULFILMENT OF THE REQUIREMENT FOR THE AWARD OF THE DEGREE OF MASTER OF TECHNOLOGY IN PETROLEUM ENGINEERING By DINESH KUMAR Roll No. 08MT1003 Under the supervision of Dr. Ajit Kumar Shukla & Dr. Abhay Sharma SCHOOL OF PETROLEUM TECHNOLOGY PANDIT DEENDAYAL PETROLEUM UNIVERSITY GANDHINAGAR, GUJARAT, INDIA 18 th January 2010 i

3 Certificate to be printed on the letterhead of the School Date CERTIFICATE This is to certify that the dissertation entitled Managed Pressure Drilling: Experimental and Modeling based Investigation submitted by Dinesh Kumar (Roll No: 08MT1003) in partial fulfillment of the requirements for the award of the degree of Master of Technology in Petroleum Engineering, from School of Petroleum Technology, Pandit Deendayal Petroleum University, Gandhinagar was carried out under my guidance and supervision. No part of this dissertation has been submitted for the award of any degree or otherwise elsewhere to the best of my knowledge. Signature of the Supervisor 2, if any (Dr. Abhay Sharma) School of Petroleum Technology, Gandhinagar Signature of the Supervisor 1 (Dr. Ajit Kumar N. Shukla) School of Petroleum Technology, Gandhinagar Forwarded by: Signature of the PG Coordinator/Academic Coordinator (Prof. Shrikant Wagh) School of Petroleum Technology, Gandhinagar ii

4 Dedication This thesis is dedicated to my parents and all my family members for all their support and encouragement throughout the years. iii

5 Acknowledgements I would like to sincerely thank Dr. Ajit Kumar N. Shukla and Dr. Abhay Sharma for their valuable guidance, motivation and moral support throughout this project work. I am thankful to them for giving their ideas and proper time for pointing out the right direction for completing this project work. I am also thankful to Mr. V.P. Mahavar (Head of CMT, ONGC) and Mr. Ajay Dixit (Chief Engineer, Drilling, ONGC) for giving me their knowledge and experience in Managed Pressure Drilling. I would like to thank also Drilling fluid lab coordinator Dr. V. K. Srivastava and Fabrication Laboratory Incharge for giving me permission for utilizing their lab Instruments for my Project experimental work. I would like to thanks Mr. S.P.S. Chauhan (Head of Drilling Dept., GSPC) for providing me Drilling fluid material for my Experimental work of project. I would also like to express my sincere thanks to all of the faculty members and my fellow students of School of Petroleum Technology (PDPU) for their support and encouragement. Signature of the Student (Dinesh Kumar) iv

6 Abstract Managed pressure drilling is an innovative technique to precisely manage wellbore pressure. It is particularly applicable for reducing the risk of a kick or lost returns when drilling with a narrow window between pore pressure and fracture pressure. The constant bottomhole pressure method of managed pressure drilling uses annular frictional pressure and choke pressure in addition to mud hydrostatic pressure to achieve precise wellbore pressure control. Managed Pressure Drilling is a new drilling process so research is continuously reported. Experimental and mathematical modeling based investigation in Managed Pressure Drilling could not be revealed and rarely been reported. This dissertation work discussed experimental and modeling based investigation of Managed Pressure Drilling. Experimental and modeling based investigation contains selection of best drilling fluid model, annular flow modeling, annular pressure loss modeling, equivalent circulation density (ECD) calculation and Kinematics Modeling of drilling parameters by dimensional analysis. Annular pressure loss and equivalent circulation density is very important for hydraulics calculation of managed pressure drilling. Bottom hole pressure can be precisely controlled by annular pressure loss, ECD and provided back pressure. The determination of hydraulics is very important for controlling precisely bottomhole pressure. Then experimental and modeling based investigation played an important role in Managed Pressure Drilling. This study presents a simplified and accurate procedure for selecting the rheological model which best fits the rheological properties of a given non-newtonian fluid. The project assumes that the model which gives the lowest absolute average percent error (EAAP) between the measured and calculated shear stresses is the best one for a given non-newtonian fluid. The experimental work presents drilling fluid flow behavior through annulus. This study also presents behavior chart of annular pressure loss and friction factor with respect to Reynolds number of drilling fluid flow through annulus. MPD improves the economics of drilling wells by reducing drilling problems. Further economic studies are necessary to determine exactly how much cost savings MPD can provide in certain situation. Further research is also necessary on the various MPD techniques to increase their effectiveness. v

7 CONTENTS Certificate ii Dedication iii Acknowledgements iv Abstract v List of tables ix List of figures x List of Plates xi Abbreviations Used xii Chapter 1 Introduction Drilling Conventional Drilling Underbalanced Drilling Managed Pressure Drilling Comparison between UBD/MPD Pressure-Gradient Windows Hydraulics of MPD Bottomhole Pressure How Managed Pressure Drilling Works Methods of MPD Reactive MPD Proactive MPD Variations of MPD Constant Bottomhole Pressure Pressurized Mud Cap Method Dual Gradient Method ECD Reduction Method Continuous circulation system Equipments used in MPD Rotating Control Device Non-return Valve vi

8 1.8.3 Drilling Choke Manifold Back pressure pump Coriolis type flowmeter Mud Gas separator Chapter 2 Literature Review Past studies in Managed Pressure Drilling Research publications in MPD Classification of research publications Conclusion of literature review Objective of the research Problem identification Chapter 3 Rheology model Gel Strength Plastic Viscosity Yield Point Drilling Mud Selection of Mud Type Additives Preparation of drilling mud Rheology Data Procedure for selecting the best Rheological models Newtonian Model Bingham Plastic Model Power Law Model Herschel-Bulkley Model Chapter 4 Drilling fluid flow model Newtonian fluid flow model Laminar Pipe Flow Laminar Annular Flow Power Law fluid model Laminar Pipe Flow modeling vii

9 4.2.2 Laminar Annular Flow modeling Experimental Work Description of experimental setup Procedure of the Experiment Experimental reading of fluid flow through annular pipe Pressure Drop Annular pressure loss modeling Friction Factor Equivalent Circulating Density Kinematics modeling of MPD Dimensional analysis Methods of dimensional analysis Development of dimensional analysis model Buckingham s π theorem Chapter 5 Results and Discussion Selection of drilling fluid model Drilling fluid flow modeling Flow Rate vs. Reynolds Number Velocity vs. Reynolds number Annular Pressure Loss vs. Reynolds number Friction factor vs. Reynolds number ECD vs. Reynolds number Parametric Equations for annular flow Kinematics study of MPD Chapter 6 Summary and Conclusion Summary Conclusion Scope of Future work Appendix References viii

10 List of Tables Table 2.1: Flow control matrix of Return Gas Rate Table 2.2: Classification of research publications Table 3.1: Fann-50 Rheometer reading Table 3.2: Rheology data of the drilling mud Table 3.3: Shear Stress Measured in Field Units Table 3.4: Shear Stress Calculated as Function of Viscosity Table 3.5: Shear Stress Calculated as Function of Plastic Viscosity and Yield Point Table 3.6: Shear Stress Calculated as Function of Power Law Parameters Table 3.7: Calculated Shear Stress (τ τ ) Table 3.8: Shear Stress Calculated as Function of Herschel-Bulkley Parameters Table 4.1: Effective Diameter of annular flow of power law fluid Table 4.2: Experimental reading of drilling fluid flow through annulus Table 4.3: Reynolds number of drilling fluid flow through annulus Table 4.4: Annular pressure loss with respect to Reynolds number Table 4.5: Friction factor of the annulus Table 4.6: Equivalent circulating density of annular flow Table 4.7: shows Units and Dimensions of the Drilling Parameters Table 4.8: shows fundamental Dimensions of the Drilling Parameters Table 5.1: Values of absolute average percent error Table 5.2: Parametric equations ix

11 List of Figures Figure 1.1: Comparisons in OBD, UBD and MPD Figure 1.2: Different drilling problems during drilling process Figure 1.3: Narrow margin Drilling Window Figure 1.4: Components of Bottom Hole Pressure in MPD Figure 1.5 Managed Pressure Drilling system Figure 1.6: Constant Bottomhole Pressure Variation of MPD Figure 1.7: Pressurized Mudcap Uses a Lightweight Scavenger Drilling Fluid Figure 1.8: The Dual Gradient Variation Uses Two Density Gradients Figure 1.9: Equivalent Circulating Density method Figure 1.10: Different type of Non Return Valve Figure 2.1: Research publications related survey in MPD Figure 2.2: Classification of Research Paper in terms of Percentage Figure 3.1: Newtonian fluid Rheogram Figure 3.2: Comparison between measured data and calculated data Figure 3.3: Bingham plastic fluid Rheogram Figure 3.4: Comparison between measured data and calculated data Figure 3.5: Power-law fluid Rheogram Figure 3.6: Comparison between measured data and calculated data Figure 3.7: Herschel-Bulkley fluid Rheogram Figure 3.8: Comparison between measured data and calculated data Figure 4.7: Schematic diagram of the experimental setup Figure 5.1: Behavior of annular flow rate with respect to Reynolds number Figure 5.2: Behavior of annular flow Velocity with respect to Reynolds number Figure 5.3: Behavior of annular pressure loss with respect to Reynolds number Figure 5.4: Behavior of annular friction factor with respect to Reynolds number Figure 5.5: Behavior of ECD in annular flow with respect to Reynolds number Figure 5.6: Behavior of ECD in annular flow with respect to annular pressure loss x

12 List of Plates Plate 1.1: Rotating Control Device (RCD) Plate 1.2: Drilling Choke Manifold Plate 1.3: Back pressure pump Plate 1.4: Coriolis type Flowmeter Plate 1.5: Mud Gas Separator Plate 4.1: Experimental setup Plate 4.2: Mud tank of Experimental setup Plate 4.3: Mud Pump of Experimental setup Plate 4.4: Annulus Pipe of Experimental setup Plate 4.5: Gate valve of Experimental setup Plate 4.6: Control panel of Experimental setup xi

13 Abbreviations Used AFP BHP BOP CBHP CMC DDV EAAP ECD ECDRT EMD IADC MCD MFC MPD NPT OBD ROP TVD UBD Annular Friction Pressure Bottom Hole Pressure Blowout Preventer Constant Bottom Hole Pressure Controlled Mud Cap Downhole Deployment Valve Absolute Average Percent Error Equivalent Circulating Density Equivalent Circulating Density Reduction Tool Equivalent Mud Density International Association Drilling Contractor Mud Cap Drilling Micro Flux Control Managed Pressure Drilling Non Productive Time Overbalance Drilling Rate of Penetration Total Vertical Depth Underbalanced Drilling Super script A D F K μ n pp Area of the annular pipe Pipe Diameter Friction factor Consistency factor Length of the annular pipe Shear Viscosity Flow behavior index Pore Pressure Density of Drilling mud Annular Pressure Loss xii

14 Q τ YP Flow Rate the drilling fluid flow Shear Stress Velocity of the drilling fluid flow Shear Rate Yield Point Sub script τ Equivalent diameter Effective Diameter Hydraulic Diameter Inner Diameter of the Annulus Outer Diameter of the Annulus Laminar friction factor Plastic viscosity Effective Viscosity Reynolds Number Mean Shear Stress Maximum Shear Stress Maximum Shear Rate Initial Shear Stress Mean Shear Rate xiii

15 Chapter 1 Introduction Managed Pressure Drilling (MPD) is an innovative Drilling technique which is developed for reducing the various Drilling problems like kick, drilling fluid circulation loss, wellbore instability and formation damage. These Drilling problems generally grow up during the conventional drilling process. So Managed Pressure Drilling is a process which is used for mitigating drilling problems. MPD is used to precisely manage the wellbore pressure when drilling with a narrow window between pore pressure and fracture pressure. It is very useful for mature field because it can be revisited with better well control. Managed Pressure Drilling also reduces the Non Productive Time (NPT) and enhance productivity of the matured or Brownfield. According to the Definition of International Association of Drilling Contractors (IADC) Managed Pressure Drilling is an adaptive drilling process used to control precisely the annular pressure profile throughout the wellbore. The objectives are to ascertain the down hole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. MPD is intended to avoid continuous influx of formation fluids to the surface. Any flow incidental to the operation can be safely contained using an appropriate process. Managed Pressure Drilling process is divided in to two categories Proactive and Reactive. These categories contain three variations of the MPD, like Constant Bottom Hole Pressure (CBHP), Pressurized Mud Cap Drilling (PMCD) and Dual Gradient Drilling (DG). The constant bottom hole pressure method of managed pressure drilling uses annular frictional pressure and choke pressure in addition to mud hydrostatic pressure to achieve precise wellbore pressure control. MPD technology challenges the traditional drilling practice of weighting a mud system while drilling through formations that are over pressured. The technology is an advanced drilling optimization process that applies an advanced well control methodology and specialized equipment to enhance drilling economics and reduce drilling cost uncertainty. 1

16 1.1 Drilling The main objective of drilling process in the oilfield is to make hole. Whether that hole is for exploratory and appraisal purposes or for development of petroleum production. Drilling is the first and very important step for getting petroleum products from the reservoir after doing geological work. Drilling process is very difficult and sensitive also because the recovery of petroleum product depends on the drilling. So to accomplish the chief objective some elements need to be executed along the way: Maintain hole stability Transport cuttings Freedom of drill string to move Control flow in and out of the well Case hole Achieve target bottomhole location Achieve time objective Maintain budget According to the uses of oilfield, generally the drilling process are classified as follows 1. Conventional Drilling 2. Under Balance Drilling 3. Managed Pressure Drilling Conventional Drilling: Conventional drilling has largely been practiced in open field, one that is open to the atmosphere. By the conventional drilling circulation flow path, the drilling fluid inside of the drill pipe through the mud pump and exits the top of the wellbore through a bell nipple and traverses a flow line to mud-gas separation and solids control equipment. Conventional wells are most often drilled overbalanced. Overbalanced is defined as the condition where the pressure exerted in the wellbore is greater than the pore pressure in any part of the exposed formations. 2

17 ... (1.1) Regulatory bodies recommend that the well should be overbalanced under the static condition. For conventional drilling static condition means that the drilling fluid (mud) is not circulating by means of pumps but is at rest in the well. This static column of drilling mud exerts a hydrostatic pressure throughout the wellbore (1.2) While the static overbalanced condition addresses control of the pore pressure, once the mud pumps are engaged the system becomes dynamic. A component, annular friction pressure (P AF ) comes to play (Malloy K. P. 2008)..... (1.3) Figure 1.1: Comparisons in OBD, UBD and MPD Underbalancedd Drilling The origin of Managed Pressuree Drilling (MPD) is found in the utilization of a few specific technologies developed by its forbearer Underbalanced Drilling. Underbalanced Drilling (UBD) is a drilling activity employing appropriate equipment and controls where the pressure exerted in the wellbore is intentionally less than the pore pressure in any part of the exposed formations with the intention of bringing formation fluids to the surface, p Hyd is less than p B H. (Malloy K. P. 2008). 3

18 .. (1.4) or... (1.5) Underbalanced Operations (UBO) is a well construction or maintenance activity employing appropriate equipment and controls where the pressure exerted in the wellbore is intentionally less than the pore pressure in any part of the exposed formations with the intention of bringing formation fluids to the surface. In addition to improved rate of penetration, the chief objectives of UBD are to protect, characterize, and preserve the reservoir while drilling so that well potential is not compromised. To accomplish this objective, influxes are encouraged. The influxes are allowed to traverse up the hole and are suitably controlled by three major surface containment devices. (Malloy K. P. 2008). Rotating Control Device Drilling Choke Manifold Multiple Phase Separator Managed Pressure Drilling Unlike Underbalanced Drilling, Managed Pressure Drilling (MPD) does not actively encourage influx into the wellbore. Managed Pressure Drilling applications are driven by the very narrow drilling margins between formation pore pressure and formation fracture pressure downhole. The narrow margins are most pronounced in deepwater applications where much of the overburden is actually seawater. In such cases, it is usual to set numerous casing strings at shallow depths to avoid extensive lost circulation. More mature fields also offer the challenges of depleted zones and pressure reversals that are technically difficult to drill. The primary objectives of MPD are to mitigate drilling hazards and increase drilling operations efficiencies by diminishing Non-Productive Time (NPT). The operational drilling problems most associated with non-productive time include are: (Malloy K. P. 2008) 1. Lost Circulation 2. Stuck Pipe 3. Wellbore Instability 4. Well Control Incidents 4

19 Figure 1.2 Different drilling problems during drilling process (Malloy K. P. 2008) 1.2 Comparison between UBD & MPD MPD is similar to underbalanced drilling (UBD). It uses many of the same tools that were designed for UBD operations. The difference between the methods is that UBD is used to prevent damage to the reservoir while the purpose of MPD is to solve drilling problems. UBD allows influx of formation fluids by drilling with the pressure of the fluid in the wellbore lower than the pore pressure. MPD manages the pressure to remain between the pore pressure and the fracture pressure of the reservoir. It is set up to handle the influx of fluids that may occur while drilling but does not encourage influx. UBD is reservoir-issue related while MPD is drilling-issue related. These points are suggested by Malloy K. P and required to get confirmation through the field experience. 1.3 Pressure-Gradient Windows As a well is drilled, drilling fluid is circulated in the hole to obtain a specific bottom hole pressure. The density of the fluid is determined by the formation and pore pressure gradients and the wellbore stability. Below Figure 2.1 shows a pressure gradient profile of a typical well. This profile shows the change in pressure as the depth increases. The drilling window is the area between the pore pressure and the fracture pressure. The goal while drilling a well is to keep the pressure inside this pressure window. In a static well, the pressure is determined by the hydrostatic pressure 5

20 of the mud. In conventional drilling, the only way to adjust the pressure conditions is to vary mud weight in the well (Martin M. D. 2006). during static Figure 1.3 Narrow Margin Drilling Window 1.4 Hydraulics of MPD In MPD applications, the wellbore is closed and able to tolerate pressure. With this arrangement, p BH can be better controlled with imposed backpressure (pback) from an incompressible fluid in addition to the hydrostatic pressure of the mud column and annular friction pressure Bottomhole Pressure The Bottomhole Pressure (BHP) has three components: hydrostatic pressure, annulus frictional pressure (AFP) and choke pressure in a closed circulating system. The Constant Bottomhole Pressuree (CBHP) technique is intended to utilize the combination of these three pressure components for precisee wellbore pressure management at all times during drilling. Figure illustrates these three components of BHP and the variables that affect the magnitude of these pressure components. The variables such as mud flow rate which controls the AFP and choke pressure which controls the back pressure can be manipulated in real time during drilling allowing relatively quick changes in the wellbore pressure. Conversely, changing the magnitude of the mud properties, such as mud weight and viscosity, has a more delayed impact. 6

21 (1.6) Figure 1.4 Components of Bottom Hole Pressure in Managed Pressure Drilling 1.5 How Managed Pressure Drilling Works The basic technique in MPD is ability to manipulate the BHP and the pressure profile as needed. In conventional drilling, the BHP can be calculated by summing the mud weight hydrostatic head and the annular friction pressure (AFP). The AFP is the friction pressure that results from the circulation of the mud while drilling. Equivalent Circulating Density (ECD) is the equivalent circulating density constituting the BHP. It is basically the BHP while circulating converted into the units of mud weight. During a connection, the pumps turn off and the fluid stops circulating, thus eliminating the annular friction pressure. The starting and stopping of pumps can greatly affect the pressure profile, causing the pressure to fluctuate out of the pressure-gradient window and thus leading to drilling problems. The basic configuration for MPD is to have a rotating control device (RCD) and a choke. The RCD diverts the pressurized mud returns from the annulus to the choke manifold. A seal assembly with the RCD enables the mud returns system to remain closed and pressurized and enables the rig to drill ahead. The choke with the pressurized mud return system allows the driller to apply backpressure to the wellbore. If the pressure starts to climb above the fracture pressure of the formation, the driller can open the choke to reduce backpressure and bring the pressure down. If the driller needs to increase the pressure throughout the well, closing the choke will increase backpressure. This technique is mainly used during connections when the pumps are turned off then on. When the pumps are turned off, the choke is closed to apply backpressure 7

22 to replace the lost AFP. As the pumps are turned on and the AFP increases, the choke can be opened to decrease backpressure. This helps keep pressure profile to remain inside the pressure window throughout the well. The pressure profile shows that, in static conditions, the pressure will fall below the pore pressure and that, while circulating, the pressure will exceed the fracture pressure. By adjusting the mud weight and using backpressure, a driller would be able to keep the pressure inside the pressure window. The driller can decrease mud weight so that the pressure stays below the fracture pressure while circulating. Applying back pressure while not circulating could keep the pressure above the pore pressure of the formation. By adjusting the drilling plan, a driller would be able to successfully drill a well that has tight pressure margins as shown figure 1.3. (Martin M. D. 2006). Figure 1.5: Managed Pressure Drilling system ( 1.6 Methods of Managed Pressure Drilling There are two basic approaches to utilize MPD Reactive and Proactive. Reactive MPD uses Managed Pressure Drilling methods and/or equipment as a contingency to mitigate drilling problems as they arise. Managed Pressure Drilling is accordingly classified in two categories (Malloy K. P. 2008). 1. Reactive MPD 2. Proactive MPD 8

23 1.6.1 Reactive MPD Typically, the well is planned conventionally and MPD equipment and procedures are activated during unexpected developments. Utilizing a Rotating Control Device alone does not necessarily constitute Managed Pressure Drilling Operations. A Rotating Control Device is an excellent supplementary safety device and is adjunct to the BOP Stack above the Annular Preventer. Generally RCD are rated up to Pa are used alone or without other ancillary equipment. It is a best and highly effective reactionary tool that safely mitigates the presence of hydrocarbons escaping from the wellbore to the rig floor. This method is sometimes also described as the Health Safety Environmental variation. As additional equipment and know-how are added, the operation becomes more and more proactive (Malloy K. P. 2008) Proactive MPD Proactive MPD uses Managed Pressure Drilling methods and/or equipment to actively control the annular pressure profile throughout the exposed wellbore. This approach utilizes the wide range of tools available to better control placement of casing seats with fewer casing strings, better control of mud density requirements and mud costs, and finer pressure control to provide more advanced warning of potential well control incidents. All of these lead to more time drilling and less time spent in non-productive activities as reported by (Malloy K. P. 2008). 1.7 Variations of MPD Various techniques are utilized to accomplish these objectives. These variations are sometimes described as (Malloy K. P. 2008) 1. Constant Bottom Hole Pressure 2. Pressurized Mud Cap 3. Dual Gradient Drilling 4. ECD Reduction 9

24 1.7.1 Constant Bottomhole Pressure Constant Bottomhole Pressure (CBHP) Method implies control of the bottomhole pressure at the bottom of the hole, its actual objective is to control the most troublesome pressure anomalies within the exposed wellbore. Typically in this method, the drilling fluid is lighter than normal to the point where the hydrostatic column is actually statically underbalanced. During drilling, influx is avoided with the increase in annular frictional pressure from pumping... (1.7) During connections, influx is controlled either by imposing backpressure or by trapping pressure in the wellbore (1.8) or.. (1.9) In each of these cases the desire is to maintain the bottomhole pressure constant by replacing the annular friction pressure with an equivalent backpressure or annular trapped pressure.... (1.10) A typical comfort level is between and Pa well below the pressure ratings for RCD tools. As the imposed backpressure becomes higher, the circulating mud density is often increased to keep the backpressure within comfortable limits (Malloy K. P. 2008). 10

25 Figure 1.6: Constant Bottomhole Pressure Variation of MPD (Malloy K. P. 2008) Pressurized Mud Cap Method For taking floating mud cap as the start point, the pressures throughout the wellbore are stable. Once drilling begins again and the hole becomes deeper, assuming that the reservoir pressure increases with depth, the high density annular mud cap loses its ability to contain the bottom hole pressure by itself. Over time and distance an annular pressure differential between and Pa, below the pressure ratings for RCD tools, is not unremarkable. As the annular pressure becomes higher, the mud cap fluid density is often increased to keep the annular pressure within comfortable limits. Surface pressure fluctuations are used to monitor downhole conditions (Malloy K. P. 2008): 1. Gas migration to the annulus Produced fluid is injected back into the formation at a prescribed rate and volume 2. Pore pressure increase Annular hydrostatic fluid density is increased to maintain the surface pressure within a comfortable range 3. Fracture plugging Should the cuttings plug off the fractures, pressurized mud cap may have to be suspended in favor of conventional drilling operations 11

26 Figure 1.7: Pressurized Mudcap Uses a Lightweight Scavenger Drilling Fluid (Malloy K. P.) Dual Gradient Method Dual Gradient Drilling has been utilized successfully in primarily offshore applications, where water provides a significant portion of the overburden. Since here liquid overburden is less dense that the typical formation overburden, the drilling window is small because the margin between pore pressure and frac pressure is narrow. Because of the weak formation strength, deepwater conventional drilling applications usually require multiple casing strings to avoid severe lost circulation at shallow depths using single density drilling fluids. The intent of the dual gradient variation is the desire to mimic the saltwater overburden with a lighter density drilling fluid. Adjustment of bottomhole pressure can be accomplished by injecting less dense media, such as inert gas, plastic pellets, or glass beads into the base drilling fluid within the marine riser. Another method available is to fill the marine riser with saltwater while diverting and pumping the mud and cuttings from the seabed floor to the surface. Both of these methods alter the fluid density in the vicinity of the mud line. The overall hydrostatic pressure in the wellbore is produced by two different fluids (Malloy K. P. 2008). 1. To avoid breaking down the formation by exceeding the frac gradient 2. Saving drilling operations from spending non-productive time addressing lost circulation issues and its associated costs 3. With lost circulation under control, casing seats can be extended 12

27 Figure 1.8: the Dual Gradient Variation Uses Two Density Gradients (Malloy K. P. 2008) ECD Reduction Method Equivalent Circulating Density can be altered by modifying the annular pressure profile directly. Using a single density drilling fluid, a downhole motor can be used to add energy that creates an abrupt change in the annular pressure profile. While making a connection, loss of annular friction pressure can be directly compensated by judicious use of imposed backpressure to control the BHP. In severe kick stuck lost circulation scenarios, backpressure from an incompressible fluid may be used to compensate for the low-density drilling mud that may be indicated. Options to control annular friction pressures with downhole pumps are readily available as well (Malloy K. P. 2008). Figure 1.9: Equivalent Circulating Density method (Malloy K. P. 2008) 13

28 1.7.5 Continuous Circulating System Another method to control the annular pressure profile while making a connection is to maintain the Equivalent Circulating Density while the connection is being made. This is done by configuring pipe rams and a blind ram to effectively maintain circulation even while the drill string is apart while the connection is being made. The continuous circulating device breaks the drill string connection and through a sequence of operations diverts the fluid flow across the open connection, then makes up the new connection to the appropriate torque. Mud flow is uninterrupted by making the connection (Malloy K. P. 2008). 1.8 Equipments used in MPD Managed Pressure Drilling requires a certain minimum of equipment. That equipment list is dependent upon the MPD application and by what means the annular pressure is going to be controlled (Malloy K. P. 2008). 1. Rotating Control Device 2. Non-return Valve 3. Drilling Choke Manifold 4. Optional equipment Microprocessor control Back pressure pump Downhole isolation valve Flow meters - Coriolis - Paddle - Turbine Phase separators Downhole Pressure While Drilling tool Rotating Control Device: The location for the RCD is most typically over the annular preventer. The RCD is not intended to replace the Blowout Preventer stack as a primary well control device, but to act a supplement to the BOP stack to give it more range and flexibility. The size and design of the RCD for a specific drilling operation is application driven, including: (Malloy K. P. 2008) 14

29 1. Rig substructure geometry 2. Seal elements Single Dual 3. Pressure rating Static Dynamic 4. Flange connections 5. Operator preference Plate 1.1: Rotating Control Device (RCD) Non-Return Valve A non-return valve described in API Specification 7NRV describes drill string valves that prevent retrograde flow up the drill string. There are numerous models. Two of the pictures are given below (Malloy K. P. 2008). Figure 1.10: Different type of Non Return Valve (Malloy K. P. 2008) 15

30 1.8.3 Drilling Choke Manifold The full time use of the rig choke manifold to control the annular pressure profile while drilling ahead is not recommended. The rig choke manifold should be reserved for well control incidents. A well designed, dedicated and fit-for-purpose for safe drilling operations. Choke control are either manual, automated, or semi-automated; each with various degrees of interaction with a drilling choke manifold offers functionality and sufficient redundancy hydraulics model and human interaction (Malloy K. P. 2008). Plate 1.2: Drilling Choke Manifold (Malloy K. P. 2008) Back Pressuree Pump The back pressure pump is a low volume, triplex pump connected to the choke manifold and automatically controlled by the system. Whenever the pressure manager senses that the flow from the well is in sufficient to maintain the required back pressure. It automatically turns on the back pressure pump (Malloy K. P. 2008). Plate 1.3: Back pressure pump (Malloy K. P. 2008) 16

31 1.8.5 Coriolis type flowmeter The coriolis flow meter depends on a flowing mass which deflect the tube. Typically this is shown as a U-tube and this configuration shown in as plate 4.5. The coriolis meter is a very accurate method of measuring drilling fluids since they contain drill cuttings that tend to interface with other types of flowmeters (Malloy K. P. 2008). Plate 1.4: Coriolis type Flowmeter (Malloy K. P. 2008) Mud Gas separator Mud Gas Separator is commonly called as gas-buster or poor boy degasser. It captures and separate large volume of free gas within the drilling fluid. If there is a "KICK" situation, this vessel separates the mud and the gas by allowing it to flow over baffle plates. The gas then is forced to flow through a line and vent it to a flare. Plate 1.5: Mud Gas Separator (Malloy K. P. 2008) 17

32 Chapter 2 Literature Review This chapter is aimed to reviewing the literature related to the present investigation. A literature or section review was performed to fully understand the concept of managed pressure drilling and its different techniques like CBHP method, mud cap drilling, continuous circulation system, ECD reduction tool, dual gradient drilling method of MPD and its applications. Since the MPD method originated from the concept of underbalanced drilling, relevant published papers and journals on MPD are the main literature material of the thesis. In this literature review underbalanced drilling was also consulted. Special emphasis was placed on the well control aspects of CBHP method of MPD operations. CBHP method of MPD makes proper well control or kick control and form safe drilling, relative to conventional operations was found in the literature search. An overall summary of abstract of the published papers are also given. Literature review also includes basic concept of historical development of the managed pressure drilling with respect to time. 2.1 Past studies in Managed Pressure Drilling: The idea of Managed Pressure Drilling (MPD) was first coined by Don Hannegan. The references of the MPD can be found in the earlier works of last 10 or 12 years. The interest in this field started to grow between 2004 and 2008 with practical application of the process. In due course of time, interest in this field started to grow from research point of view. The process was investigated from different perspectives in the 1996s which still continues. Various investigations in the last 10 years have been presented. This would give the journey path of the current status of research in the Managed Pressure Drilling. Hannegan D. (May 2004) is the first investigator who clearly defined managed pressure drilling s concept and application. This paper speaks to offshore applications of specialized equipment developed for the practice of underbalanced drilling (UBD) where the intent is not to achieve a true state of underbalance at any point in a well s drilling program. The intent is not to produce hydrocarbons while drilling ahead. Instead, the intent is to apply well-proven UBD tools and technology for the purpose of more precisely managing wellbore pressure(s) and annulus returns while drilling overbalanced in marine environments. Many of today s offshore drilling programs significantly exceed their Authorization for Expenditure (AFE). Such excessive costs contribute greatly to the percentage of known prospects that are 18

33 economically undrillable. However, Managed Pressure Drilling in marine environments offers a reality acceptable step change that will overcome many of today s obstacles. MPD can fill the void that exists today in the evolution of offshore drilling tools and technology. Hannegan D. (September 2004) described that MPD is enabled by some of the tools and technology developed for UBD and MPD focuses on more precise wellbore pressure management rather than creating a pressure drawdown across formations, as UBD. More precise wellbore pressure management has the potential to see fewer hydrocarbons produced to the surface than most conventional overbalanced drilling operations experience in reality. What is important here is the fact that more precise wellbore pressure management has the potential to address - at least to some degree and, in some cases, eliminate entirely - perhaps up to 80% of the drilling-related obstacles facing conventional drilling programs today. Clearly, conventional offshore drilling tools and techniques require a step-change technology now more than ever. Solutions to overcoming, remediating or otherwise dealing with drillingrelated challenges beg for more precise wellbore pressure management; thus the interest in applying managed-pressure drilling (MPD) technology in marine environments. Borre Fossil, Sigbjorn (Oct 2004) described controlled mud cap (CMC) MPD technology for deepwater offshore applications. The system utilizes an engineering simulator to calculate the dynamic pressure losses in the wellbore during drilling and controls the speed of the mudlift pump at the sea floor in real time to maintain the required mud level in the riser to control the BHP. In this system, during pipe connection, the effect of loosing friction during pipe connection is compensated by varying the level of fluid in the riser to maintain the same BHP same as during drilling. The main advantage comes from using a heavier than conventional mud weight, having a lower mud level in the riser and from being able to compensate for the ECD effect. By using this method during well control events, when hydrocarbon influxes are being circulated out of the well, the inherent problem with added annular pressures due to friction is neutralized. In fact it can be shown that being able to circulate out influxes at higher circulating rates improves the margins against weaker formations at a higher interval of the well, such as at the casing shoe. This advantage also counts for MPD, however the margins will be substantially higher for the CMC method. George Medley, Rick Stone (Oct 2004) Simplified techniques for deciding when to switch over from conventional drilling operations to UBO in general and MCD in particular must account for Safety, Economics, and Logistics considerations. Everyone involved should 19

34 understand the process of making the decision. Understanding can be encouraged through appropriate training and through the Using data and examples from MudCap Drilling (MCD) scenarios from around the world, this paper demonstrates the process and techniques that have been utilized to successfully determine when the critical point has arrived to make the switch. The development of a simple flow chart that can be utilized at the field location in making the determination to switch based on satisfaction of pre-determined criteria is also demonstrated. Hannegan D. (February 2005) gave an overview of MPD as an emerging technology. He explained the conceptual difference between UBD, MPD and power drilling (PD) for ROP enhancement. More precise wellbore pressure management has the potential to see fewer hydrocarbons produced to the surface than most conventional overbalanced drilling operations experience in reality. The various forms of MPD as a means of wellbore pressure management such as dual gradient drilling, pressurized mud cap drilling, riserless drilling and zero discharge riserless drilling were explained. This case studies shows application of Managed Pressure Drilling in marine environment. However, the well control issues associated with MPD were not discussed in this literature. Saponja, Adeleye and Hucik (April 2005) addressed the question whether or not to close the BOP on a gas flow during UBD operations with surface facilities to handle the gas. Saponja refers to these as MPD operations. He has suggested a field specific flow control matrix (FCM) that would determine the severity of the well control hazard and recommend the well control measures to follow. The flow control matrix specific to the example well is reproduced here at below Table 2.1 for a better insight. R E T U R G A S (0-594) 10 3 m 3 /day (0-21) MMscfd Manageable ( ) 10 3 m 3 /day ( ) MMscfd (892+) 10 3 m 3 /day (31.5+) MMscfd WELLHEAD FLOWING PRESSURE kpa kpa kpa Adjust system to increase BHP - Increase liquid injection rate - Decrease surface back pressure Adjust system to increase BHP - Increase liquid injection rate - Decrease surface back pressure Adjust system to increase BHP - Weight up drilling fluid Shut-in on Rig s BOP Shut-in on Rig s BOP Shut-in Rig s BOP Shut-in Rig s BOP Shut-in on Rig s BOP Table 2.1 Flow control matrix of Return Gas Rate 20

35 The severity of the hazard is gauged by the return gas rate and flowing wellhead pressure. The well control measures are: change liquid injection rate, change surface back pressure, weighting up of drilling fluid or shut in the well. On the contrary, the Minerals Management Services (MMS) have proposed that GOM lessees be required to revert to conventional well control with the BOP and primary choke manifold if a kick is detected in a MPD operation. Medley G. and Reynolds P.B.B. (March 2006) In this Paper Author separates MPD into two categories -"reactive" and (the well is designed for conventional drilling, but equipment is rigged up to quickly react to unexpected pressure changes) and "proactive" (equipment is rigged up to actively alter the annular pressure profile, potentially extending or eliminating casing points). The reactive option has been implemented on potential problem wells for years, but very few proactive applications were seen until recently, as the need for drilling alternatives increased. It also shows the major difference between the MPD and UBD. in which MPD will never invite influx into the wellbore. Conversely, this is UBD's objective. The UBD process involves drilling into any formation, where the pressure exerted by the drilling fluid is less than the formation pressure. The technique reduces the hydrostatic pressure of the drilling fluid column, so that the pressure in the wellbore is less than the formation pressure. Consequently, the formation pressure will cause permeable zones to flow, if conditions allow flow at the surface. In MPD, the driller seeks to stay slightly above or "atbalance" to the downhole pore pressure (pp), or as close to near-balance as possible during the entire section of problem hole, both during drilling and connections. Precise control of downhole pressure allows the driller to effectively drill within the window between pp and fracture gradient (FG) without setting casing prematurely. This window typically is narrower in deeper water environments or where pore pressures are greatly depleted. Nogueira and Lage (May 2006) described the development of systems for improving the management of downhole pressure. Many different concepts have been proposed and developed, but the present work describes the efforts for planning and executing a series of four wells using a new managed pressure drilling (MPD) technology based on the Micro-Flux Control (MFC) method. The MPD system will be installed to assist the construction of difficult HPHT well sections to be drilled from a jack-up rig. it also presents an analysis of the overall performance including the hardware and the software of the MPD system as well as the interfaces with the conventional rig equipment. Along with the report of the aspects associated with training drilling crews and their performance during operations. Conscious of these problems, the industry has been developing new techniques, labeled by the general 21

36 name of MPD, in order to improve the management of downhole pressures. In other words, MPD is a family of technologies that offers more precise pressure management. It also provides fewer interruptions to drilling ahead despite devising significant gains, some MPD concepts introduce radical changes into the operational routine. Their implementation is more complex, demanding special training and considerable additional costs. In general, those techniques are still far from the operational routines, requiring additional time to be developed and deployed. Hannegan D. (Jun 2006) described that Asia-Pacific region offers a stark contrast to the GoM in terms of operators acceptance and application of MPD techniques. In the last two years, Weatherford has completed about 80 onshore and offshore MPD wells in the Asia- Pacific. In June 2006, the company had 12 rigs practicing MPD in the region. Today, there are 34. The number of operators has more than doubled from seven in June of 2006 to 15 today. And in all cases where operators have tried MPD, they have planned subsequent MPD projects. A major operator s highly challenging development wells in Sumatera, Indonesia, and an independent operator s project in Papua New Guinea demonstrate the power of MPD technology. Both projects also demonstrated the advantage of combining MPD with a downhole deployment valve (DDV) tool, which eliminates the need to kill the well for trips out of the hole and saves operating time. Beltran, Gabaldon and Puerto (Sep 2006) shows the application of the MPD technology to solve the varied range of operational problems that had been experienced in the San Joaquin field. Twelve wells have been performed up to date using proactive Managed Pressure Drilling (MPD) & Underbalanced Drilling (UBD) techniques in the San Joaquin field. Nitrogen injection has been applied in the San Juan formation to achieve the required ECD below 6.0 ppg.mpd is a collection of tools and techniques that offers incredible advantages to drill in a safer mode. The Reactive MPD involves tooled up to more efficiently react to downhole surprises. In a Proactive MPD System the fluids and casing programs are designed, The closed system utilized in MPD and UBO operations has the potential for safer well control due to: More sensitive kick detection, the influx is stopped faster and we can perform a faster kill in the case this will be mandatory. Iversen, Gravdal (Sep 2006) gave main focus on application of linear PID control and model predictive control regulator technique for choke control These techniques can be combined or used separately. Drilling wells in depleted reservoirs is often characterized by a 22

37 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 is 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 wel. 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. Application of a mud heater and/or CCD has primarily a stabilizing effect on the wellbore pressure profile, while automatic choke regulation is a direct and fast response technique that falls within the collective term of MPD. Though all these aspects were simulated, the main focus was on drilling and pipe movements (surge, swab, tripping out) in the 8 1/2 hole section Hannegan D. (September 2006) This paper will define for the audience the two Categories (Reactive & Proactive) and the Variations of MPD that are being currently practiced or will be practiced in the near future in marine environments. Case studies will be presented which speak to MPD applications from both fixed (Jackup, platform) rigs with surface BOP stack and from floating rigs (moored semisubmersibles and DP Drillships) with subsea and surface BOP s. There will be an emphasis upon the drilling trouble zones benefits of MPD. Operator company objectives of practicing the variations of MPD will be detailed. Stances of various regulatory agencies are discussed. Kozicz J. (Oct 2006) described that MPD methods can significantly improve drilling efficiencies by minimizing the time spent monitoring and interpreting well conditions (flow checks, drilling fluid expansion, ballooning, influx and loss detection,etc). Further, having the ability to manage the well bore pressure profile may enable changes in well design minimizing the requirement for close tolerance casing programs, and contingencies such as drilling liners and expandable casing. In other instances these methods may enable wells to be drilled where application of conventional drilling practices would not be technically or economically feasible. Much of the initial industry focus has been on developing MPD methods for deepwater applications, many of the techniques are applicable to all offshore 23

38 drilling operations and a number of recent applications of Constant Bottom Hole Pressure drilling. The limited offshore application of MPD techniques from floating drilling rigs have to date generally focused on solving particular well problems by employing a single method when required, i.e. employing PMCD to drill massive loss circulation zones. As the capabilities of the various MPD methods become better understood opportunities to employ these methods with the primary motive to improve efficiency will broaden. A systematic approach to evaluating both the problem mitigation benefits and efficiency potential of the various methods is required in order to demonstrate the potential economic benefit resulting from employing an appropriate combination of the various MPD methods Fredericks P.D. (Oct 2006) described that Dynamic Pressure Control is a managed-pressure drilling (MPD) service to maintain constant bottomhole pressure (CBHP) while drilling. Operators drilling the challenging environments found in mature fields are benefiting from its ability to overcome the pressure limitations of conventional drilling and expand their drillable prospects. Most MPD systems that provide constant BHP include a rotating control head (RCH) while the majority of CBHP systems include a choke connected to it to manage annulus backpressure. Beyond these features choke systems differ from each other by, among other things, the ability to control and create backpressure. Control can be manual, automated or a mix of both and the ability to create backpressure can be achieved through active or passive control. All choke systems create backpressure while mud is flowing but, without a backpressure pump when flow stops, active control is lost. When that happens backpressure is fixed at the level trapped before flow ceased and the system shifts to passive control to maintain trapped pressure until flow resumes. Bansal R.K., Brunnert (Feb 2007) described that equivalent circulation density reduction tool is designed to counter the increased fluid pressure in the annulus caused by friction loss and cuttings load by reducing the total hydrostatic head. This paper describes progress on development and testing of a prototype ECDRT. The test involved drilling mm hole with the tool running inside mm. casing cemented at a depth of 4,500 ft. Performance was monitored continuously from a real-time display of surface and downhole measurements. Wellbore pressure management was clearly demonstrated in the field trial. The ECDRT consistently reduced ECD by about MPa, or the equivalent of about 0.7 ppg kg/m 3 at m. Drilling performance was not limited in any way by the ECDRT. Fluid returns and wellbore cleaning were normal throughout the drilling operation. The ECDRT processed cuttings generated by the drilling at m/hr without difficulty. More than 500 ft of hole 24

39 was successfully drilled before the tool was pulled because of difficulties with the directional drilling system. The final goal to evaluate ECDRT operational procedures was achieved as performance indicators on the surface worked reliably to diagnose the operational status of the tool. High ECD is a significant problem in deepwater drilling and in ERD wells because of narrow pore-pressure and fracture- gradient windows. The ECDRT has the potential to alleviate ECD-related problems in both situations. Results from tests conducted in a flow loop and in an experimental well have shown that the ECDRT can provide up to 450-psi pressure relief in the annulus. The pressure relief in the annulus corresponds to a significant ECD reduction, which is a function of the vertical depth of the well. The results from field trials have proved the viability of using the ECDRT to manage ECD. Adding the ECDRT in the drillstring required tripping out only seven stands. Surge and swab pressure effects were managed by slowing trip speeds. Cuttings generated from drilling flowed smoothly through the ECDRT. Similarly, mud-pulse telemetry worked flawlessly. Rasmussen and Sigbjon (March 2007) presents the magnitude of surge and swab pressures that can occur in typical drilling operations, but will focus on Through Tubing Rotary Drilling (TTRD) operations. Most of the current methods for Managed Pressure Drilling (MPD) from MODUs do not have a functionality to compensate for both surge and swab pressures. A comparison and evaluation of selected MPD methods for compensation of surge and swab pressure are presented in the paper. The paper presents a comparison and evaluation of the different MPD methods for compensation of surge- and swab pressure. A comparison of the selected MPD systems is given In some cases, surge and swab pressures due to heave motion may be higher than the annular pressure loss experienced during drilling. Generally speaking, with the large heave motion of the MODU (± 2-3 m) and short time between surge and swab pressure peaks (6 7 sec.), it may be difficult to achieve complete surge and swab pressure compensation. A real-time hydraulics model is required to control wellbore pressures during connections and tripping. The capability of measuring BHP using a wired drillstring telemetry system will make ECD control easier during drilling. However, when more accurate control of the BHP is required during connections and tripping operations, the computer model will be needed to predict the surge and swab pressure scenario for the specific conditions. 25

40 One potential alternative to reduce BHP control requirements is to use a heavy compensated drillfloor. Prototypes have been build and tested, but so far, this technology has not yet been made commercial available to the industry. Tian S., Medley (March 2007) described many parameters that play a part in the managing of wellbore pressure during fluid flow. Wellbore pressures are impacted by fluid density and rheological properties, injection rates, cuttings transport, influx while drilling, wellhead or choke pressure, hole geometry and drillstring configuration. The effects of these parameters on wellbore pressure are different, but interact with one another. This paper discusses the effects of various operating parameters on wellbore pressure and provides guidelines for managing wellbore pressure by adjusting those operating parameters. Rheology of MPD fluids plays an important role in frictional pressure loss. Rheology model parameters should be determined by readings at all six speeds on the viscometer. Rheology parameters determined by only two readings (600 rpm and 300 rpm) may cause inaccurate wellbore pressure prediction. A non-zero YP causes a sudden pressure jump when fluid starts to move or when fluid is about to stop moving. It also causes a sudden BHP jump when the drillstring starts to move up or down during tripping regardless of how slow the pipe moves. Low YP fluids help to reduce the pressure jump. Circulation rate should always be equal to or greater than the optimum rate for MPD. Cuttings accumulation along the wellbore can cause not only downhole problems and reduce drilling efficiency, but also can create higher or unstable wellbore pressure, and has significant impact on the other controllable parameters. Malloy K.P. (March 2007) In the conventional drilling circulation flow path, drilling fluid exits the top of the wellbore open to the atmosphere via a bell nipple, then through a flowline to mud-gas separation and solids control equipment, an open vessel approach. Drilling in an open vessel presents difficulties during operations that frustrate every drilling engineer. Annular pressure management is primarily controlled by mud density and mud pump flowrates. In the static condition, bottomhole pressure (P BH ) is a function of the hydrostatic column s pressure (P Hyd ). In the dynamic condition, when the mud pumps are circulating the hole, P BH is a function of P Hyd and annular friction pressure (P AF ), on land and in some shallow water environments, a comfortable drilling window often exists between the porepressure and fracture-pressure gradient profiles, through which the hole can be drilled safely and efficiently, From an offshore prospective, MPD was and still is driven by the very narrow margins between formation pore pressure and formation fracture pressure downhole. Narrow margins are most pronounced in deepwater drilling, where much of the overburden is 26

41 seawater. In such cases, it is standard practice to set numerous casing strings at shallow depths to avoid extensive lost circulation. Santos H. (March 2007) Managed Pressure Drilling (MPD) involves a collection of tools, processes and equipment to manage the annular pressure profile in an oil or gas drilling operation. Key to this is a more precise determination of the wellbore pressure limits (pore and fracture) and keeping the pressure within the safety limits. It is not surprising, then, that the oil industry is seeing this new drilling method as the best alternative for successfully drilling wells in difficult environments, where conventional drilling has failed Secure Drilling is a closed-loop MPD system based on the Micro-Flux Control method. It can be used to drill standard or special MPD wells, depending on a well s complexity and needs. The system uses a rotating control device to keep the well closed to the atmosphere at all times and a specialized manifold with a very small footprint that includes redundant chokes, a flow meter and data acquisition and control electronics. The simplicity of this system makes it very attractive for use on almost every well. Downhole pressure sensors and additional surface equipment are usually needed when using the system on its special mode. Ostroot and Shayagi (April 2007) discussed two technologies that offer several advantages over conventional overbalanced methods if applied in the proper conditions. These concepts are under-balanced drilling (UBD) and managed-pressure drilling (MPD). This paper focuses on defining each technique, where each should be used, and what benefits can be expected. Differences between the two techniques concerning equipment requirements and reservoir characterization potential also will be analyzed. Results from UBD and MPD case histories are used to qualify the results from these operations. MPD and UBD both address drilling problems, reducing NPT by minimizing losses, and differential sticking and the time associated with well control events typically associated with conventional overbalanced drilling. However, when the drivers are primarily related to solving drilling problems, MPD may prove to be more economical than and just as efficient as UBD in mitigating the problems. UBD can be more costly than MPD due to additional equipment that may be required to achieve and maintain underbalanced conditions. Additionally, in some regions regulatory limitations offshore and unstable formations preclude the use of UBD. Additionally, MPD allows a high level of drilling optimization. UBD is often viewed as complex and more costly by the industry, and rejected in favor of MPD. MPD cannot match UBD in terms of minimizing formation damage/improved productivity and allowing 27

42 characterization of the reservoir; and this aspect needs to be considered in the technical and economic comparison of the methods before a final decision is made. Ostroot and Shayagi (May 2007) described MPD and UBD are both focused on controlling bottomhole circulating pressure during drilling; however, the two methods differ technically in how this is accomplished. Whereas MPD is designed to maintain bottomhole pressure slightly above or equal to the reservoir pore pressure (i.e. overbalanced or at balanced drilling), UBD is designed to ensure that bottomhole pressure (BHP) is always below the reservoir pore pressure (i.e. underbalanced drilling), so that it will induce formation fluid influx into the wellbore, and subsequently, to the surface. A comparison of the two methods can be performed by considering the objectives for the project, the equipment requirements, and potential benefits/risks of each method. This paper helps to identify the situations appropriate for each technique and the benefits that can be expected. Differences between the two techniques concerning equipment requirements and the potential for reservoir characterization are analyzed also. Results from UBD and MPD case histories are used to qualify the results from these operations. Each technique has its place, and which solution is applicable depends on the problems faced. MPD cannot match UBD in terms of minimizing formation damage, allowing characterization of the reservoir, or identifying productive zones that were not evident when drilled overbalanced; but when the objective is simply to mitigate drilling problems, MPD can often be as effective as UBD and is more economically feasible. Curtis F., Lovorn (October 2007) described MPD is drilling with a controlled annulus pressure using an equivalent mud weight maintained at, or marginally above, formation pressure using a dedicated choke device or other method. The intention is to keep reservoir fluid from reaching the surface. The primary purpose of MPD is to enhance well construction by minimizing drilling problems, with reservoir benefits a secondary advantage. As a drilling solution, MPD improves ROP and extend bit life, as well as minimize differential sticking and lost circulation. Able to drill narrow pressure margins efficiently and safely, MPD can reduce the number of casing strings required and allow integration of MWD/LWD, directional, engineering, and mud logging services. Lovorn and Curtis (October 2007) MPD techniques give operators a versatile tool for solving many drilling problems through a wide range of pressures. When coupled with a suite of optimization or Sigma Service levels, they can maximize the efficiency of an operation and avoid problems to help provide the maximum return on investment. But whatever the 28

43 correct solution or optimal service level, the starting point should be a full collaboration between the operator and service company that begins at the planning stage. Such collaboration allows a full understanding of the project s challenges and complexities and helps guarantee that the project will be efficiently and effectively executed. Medley G. (January 2008) Managed Pressure Drilling has gained widespread popularity and a great deal of press coverage in recent years. By applying MPD techniques, it is possible to drill holes that simultaneously expose formations with pore pressures very close to the frac pressures of other exposed formations with minimal formation influx or mud losses. Complex and expensive systems have been designed and implemented to maintain pressure on the wellbore using hydraulics modeling software, automated chokes, and continuous surface circulating systems, often working in conjunction with each other. These systems usually require several specially trained operators. This aggregation of personnel and equipment increases both the footprint and housing required for implementation, as well as substantially increasing the cost of the operation. MPD can justify the cost of an elaborate, fully automatic annular pressure control system. Fortunately, a complex system is not always required and often a more simple historical method of controlling the annular pressure manually within a close tolerance can be employed in these instances. While improvements in fully automated annular pressure control systems are continually being made, allowance for disruption in the operation must still be made. When disruptions occur, the same simple, historical methods of manually controlling annular pressure can be employed effectively to handle such contingency events. It is possible in most cases to adequately manage downhole pressures within acceptable limits using simple, historical, manual surface controls in lieu of complex, expensive surface pumping systems and software controls. Solvang S.A. (January 2008) This paper describes the need to implement managed pressure drilling (MPD) techniques in the Kristin field to overcome the problems related to a narrow drilling window. MPD is a technique that allows the use of lower-density drilling fluid, minimizing the overbalance pressure. Thus, BHP can be easily controlled and changed by applying surface-back pressure using a closed and pressurized circulation system and an automated choke. Circulating and static BHP can be increased rapidly, by applying back pressure at surface, if a higher than expected reservoir pressure is encountered. Conversely, BHP can rapidly be reduced, by reducing surface back pressure, should losses be seen down hole. The paper discusses the use of a drilling fluid with a density giving a hydrostatic 29

44 pressure lower than the original pore pressure to facilitate drilling operations and allow better control of the BHP for drilling future wells in the Kristin Field. The Kristin development wells may be the first wells globally to use MPD techniques in a harsh weather offshore environment on a floating drilling installation. The paper will also discuss some of the new equipment which has been designed to allow the implementation of MPD techniques in a harsh weather offshore environment from a semi submersible rig. Spriggs P. (January 2008) The purpose of this paper is to address the key drivers and risks associated with the use of Applied Back Pressure Managed Pressure Drilling. One of the two key issues to understand early on is whether the well can be drilled statically overbalanced or needs to be drilled with a statically underbalanced fluid. The second issue to comprehend is the level of service needed to avoid compromising safety and well objectives answering these two questions defines the path to be followed for adequate planning. Detailed planning aspects, such as flow modeling, crew training, operational procedures, process flow diagrams and HAZID /HAZOPs meetings are also described in this paper. By asking the what if questions prior to operations, it should become apparent what additional surface equipment is required to safely and efficiently drill in MPD mode. Control of the what if s should help to keep the planning and rig up both reasonable and cost effective. Njoku J. C. and Clyde R (March 2008) As hydrocarbon basins mature, reservoir pressure depletion caused by hydrocarbon production leads to severe pore pressure/fracture gradient anomalies that can reduce an otherwise sufficient mud weight window significantly. At the same time, reentries involving slim-hole sidetracks incur high annular losses that further widen the gap between equivalent static and circulating densities ESD and ECD. In this situation, it is not possible to drill using normal overbalanced methods. The risk of formation fracturing and fluid losses, fluid influxes, and wellbore collapse would far outweigh the reward of increased production. The effective variation of static and circulating densities must be minimized. A major project in the Gulf of Mexico posed such a problem. Managed pressure drilling (MPD) was adopted as the solution to manage a tight hydraulic window and effectively drill reservoirs which would have been extremely challenging using conventional drilling methods. Traditional directional drilling with a positive displacement motor would normally create more pressure balance complications under a MPD environment due to the continuous fluctuations to the ECD when the motor is in sliding or steering mode. This paper outlines how new generation rotary steerable systems coupled with the interpretation from a 30

45 downhole real time pressure while drilling sensor was engineered to maximize drilling performance for a directionally drilled well in MPD environment. This paper will also discuss the case histories and lessons learned and thoroughly review the range of opportunities these technologies have created in the maturing areas of the Gulf of Mexico Dharma and Toralde (March 2008) described that Managed Pressure Drilling (MPD), particularly the Pressurized Mud Cap Drilling (PMCD) variant, was used. This operation also included Weatherford s proprietary Downhole Deployment Valve. The combination of MPD with a DDV system was applied during drilling operations and resulted in wells capable of producing 300 MMcfd, while improving the safety and efficiency of drilling and completion operations. The combined MPD/DDV system allowed drilling to continue even with total loss of circulation. The combined system increased the safety margin of operations, reduced the amount of mud and Lost Circulation Materials (LCM) required, minimized formation damage and made running and installing the completion assembly possible without killing the well. MPD and DDV technologies can be successfully integrated and applied during drilling and completion operations to produce high-rate gas wells. The combination of the two technologies opens the door to the construction of gas wells designed for increased productivity and output, by deliberately seeking out large fractures while concurrently minimizing formation damage. The synergized use of MPD and the DDV will allow the drilling of fewer but larger output wells, greatly improving the economics of gas-field development. Santos H. (March 2008) describes that MPD system uses a Rotating Control Device (RCD) to keep the well closed to the atmosphere at all times, and a specialized manifold with a very small footprint that includes redundant chokes, a flowmeter, and data acquisition and control electronics. The simplicity of this standard MPD system makes it attractive for use on many wells. Since the first well was drilled with MFC MPD in August 2006, the method has been used on many wells in both the standard (when the mud weight is hydrostatically overbalanced) and special (when the mud weight is hydrostatically underbalanced) modes. The wells were drilled with water- and oil-based fluids with densities up to 18 ppg, offshore and onshore, for both exploration and development. The flexibility and simplicity to change from one mode to the other allows the operator to select the proper configuration depending on well conditions, well problems, rig capability, crew competency and other conditions. One 31

46 interesting finding is that the standard mode can provide unique value in understanding more accurately the downhole events, leading to a clearer identification of the problems faced. Ozegovic A. (Oct 2008) describes that in applications where techniques such as air drilling and underbalanced drilling may be unsuitable due to limitations such as borehole stability, water flows, coal seams, or environmental concerns such as flaring gas, managed-pressure drilling (MPD) is being deployed. The primary incentive of MPD is to mitigate drilling hazards and reduce the resulting nonproductive time (NPT) due to encountering lost circulation zones, tight pore pressure/fracture gradient margins, and high-pressure, lowvolume nuisance gas zones. MPD technology is being used to drill wells with very few options wells with low-pressure differential across the entire well bore, requiring various mud weights and casing designs. In some instances, so many casing strings have to be set that optimal production is impossible. Thirdly, MPD is mitigating lost circulation in the well and the potential for kicks from high pore-pressure formations. When operators hit highpressure/low-volume environments with gas pockets, MPD technology enables gas bleeding at the surface through the equipment and flare stack, allowing drilling to continue uninterrupted and providing operational efficiency and peace of mind. 2.2 Research publications in MPD While doing research in literature survey in to managed pressure drilling then it is being found that the concept of managed pressure drilling came in existence before 1996 but and used in the field there after. Since MPD is a adapting drilling process so it used when we faced drilling problems in conventional drilling. The progress in research of managed pressure drilling start from nearly and we see that most of the research paper in managed pressure drilling published from 2005 to Till now many paper has been published but here in this literature review approximately 150 research papers are reviewed from 1996 to 2008 and categorized in different category. 32

47 Figure 2.1: Research publications related survey in Managed Pressure drilling 2.3 Classification of research publications In my literature review I have classified approximately 150 research papers in 5 categories so percentage of research papers in terms of categories are as following Name of Category Percentage of Papers MPD techniques 30% Field experience 25% MPD development 10% Application 15% Case studies 20% Table 2.2: Classification of research publications 33

48 Figure 2.2: Classification of Research Paper in terms of Percentage 2.4 Conclusion of literature review A literature review was performed to fully understand the concept of managed pressure drilling and its different techniques. Here in this dissertation work literature review includes all above types of categories research work. After literature review it is concluded that Managed Pressure Drilling is adapting and modified drilling process because it comes according to needs and mitigating different drilling problems. In Managed Pressure Drilling most of the research work is focused on different drilling techniques and field experience. There is lot off research work required in drilling fluid Rheology and Hydraulics of MPD. So overall conclusion of the literature review includes following things: MPD is a new drilling process so research is continuously reported. Research papers are published mainly on field experience, application and case study. Rheology modeling and Hydraulics modeling of MPD rarely reported Experimental based investigation of Hydraulics of MPD has rarely been reported. 34

49 2.5 Objective of the research After the literature review, we have concluded that Managed Pressure Drilling (MPD) is newly developed drilling techniques in which lot of research is in progress. The research in MPD is mainly oriented toward development of field applications for various conditions. Limited work has been published on the theoretical aspects, modeling and experimental demonstration of MPD. The current dissertation is intended to develop theoretical model of MPD followed by experimental validation. To make drilling mud and develop experimental setup. To develop a theoretical and mathematical Rheology model of drilling fluid. To develop a theoretical and mathematical Hydraulics model of MPD To validate the theoretical model with the experimental data. 2.6 Problem identification Managed Pressure Drilling is newly developed drilling techniques in which lot of research is in progress. Since MPD is an adaptive drilling process so the research in MPD is mainly oriented toward development of field applications for various conditions. Limited work has been published on the theoretical aspects, modeling and experimental demonstration of MPD. Hence in my dissertation work I am going through Rheology and Hydraulics parameters of the MPD and developed a theoretical and mathematical modeling of the drilling fluid Rheology and Annular flow. Then I can brief problem identification of dissertation work in Experimental and modeling based investigation into Managed Pressure Drilling. There after attempt is made to validate MPD system by Rheological and hydraulically contribution. 35

50 Chapter - 3 Rheology model Rheology is the study of the deformation and flow of matter. Viscosity is a measure of the resistance offered by that matter to a deforming force. Shear dominates most of the viscosityrelated aspects of drilling operations. Because of that, shear viscosity (or simply viscosity ) of drilling fluids is the property that is most commonly monitored and controlled. Retention of drilling fluid on cuttings is thought to be primarily a function of the viscosity of the mud and its wetting characteristics. Drilling fluids with elevated viscosity at high shear rates tend to exhibit greater retention of mud on cuttings and reduce the efficiency of high-shear devices like shale shakers. Conversely, elevated viscosity at low shear rates reduces the efficiency of low-shear devices like centrifuges, inasmuch as particle settling velocity and separation efficiency are inversely proportional to viscosity. Water or thinners will reduce both of these effects. Also, during procedures that generate large quantities of drilled solids. It is important to increase circulation rate and/or reduce drilling rate. Other rheological properties can also affect how much drilling fluid is retained on cuttings and the interaction of cuttings with each other. Some drilling fluids can exhibit elasticity as well as viscosity. These viscoelastic fluids possess some solid-like qualities (elasticity), particularly at low shear rates, along with the usual liquid-like qualities (viscosity). Shear-thinning drilling fluids, such as xanthan gum based fluids, tend to be viscoelastic and can lower efficiency of low-shear-rate devices like static separation tanks and centrifuges. Viscoelasticity as discussed above is based on flow in shear. There is another kind of viscoelasticity, however, that is just now receiving some attention: extensional viscoelasticity. As the term implies, this property pertains to extensional or elongational flow and has been known to be important in industries in which processing involves squeezing a fluid through an orifice. This property may be important at high fluid flow rates, including flow through the drill bit and possibly in high throughput solids-control devices. High-molecular-weight surface-active polymers, such as PHPA and 2- acrylamido-2-methylpropane sulfonic acid Acryl amide copolymers, which are used as shale encapsulators, produce high extensional viscosity. Muds with extensional viscosity especially new muds will tend to walk off the shakers. Addition of fine or ultra-fine solids, such as barite or bentonite, will minimize this effect (Robinson L, Growcock F ). 36

51 Rheology Models Shear viscosity is defined by the ratio of shear stress ( ) to shear rate ( ): /.. (3.1) The traditional unit for viscosity is the Poise (P), or 0.1 Pa-sec (also 1 dyne-sec/cm2), where Pa¼Pascal. Drilling fluids typically have viscosities that are fractions of a Poise, so that the derived unit, the centipoise (cp), is normally used, where 1 cp = 0.01 P = 1 mpa-sec. For Newtonian fluids, such as pure water or oil, viscosity is independent of shear rate. Thus, when the velocity of a Newtonian fluid in a pipe or annulus is increased, there is a corresponding increase in shear stress at the wall, and the effective viscosity is constant and simply called the viscosity. Rearranging the viscosity equation gives.... (3.2) and plotting τ versus γ will produce a straight line with a slope of μ that intersects the ordinate at zero (Robinson L, Growcock F ). There are four different types of Rheology models that are used widely to estimate the viscosity of a flowing drilling fluid, Newtonian, Power Law, Bingham Plastic, and Herschel- Bulkley. A Rheology model simply tries to mimic the relationship seen in real life between Shear Stress and Shear Rate, how viscosity changes, for a given fluid. This relationship is simple for Newtonian fluids as it is a straight line through the origin and thereby has a constant viscosity, but more complex for Non-Newtonian fluids where viscosity changes. Once the viscosity is estimated, this is used within the frictional pressure loss equations to estimate the pressure drop (Liu p ). 3.1 Gel Strength Gel strength measures attractive forces of the fluid under static conditions. Gel structure develops when the mud is static such that reactive clay particles move very slowly (Brownian motion), and seek out other reactive clay particles in order to link up positive valance electrons to negative valence electrons manner to form a gel structure. Engineers would like fragile gels, so that as soon as the pumps stop, a gel is generated whose strength remains about the same as time progresses. Progressive gels continue to steadily increase in strength 37

52 over time which is not good. On mud reports it is normal to report the strength of the gels that have developed after 10 seconds and 10 minutes (Liu p ). 3.2 Plastic Viscosity Plastic viscosity (PV) is the resistance to fluid flow due to mechanical friction. It is similar to adding flour to gravy so as to thicken it. A low PV indicates that rapid drilling may be possible because of the low viscosity of mud exiting at the bit. High PV is caused by a viscous base fluid and by excess colloidal solids. To lower PV, a reduction in solids content can be achieved by dilution of the mud. PV is affected by solids concentration, the size and shape of solids and the viscosity of the fluid phase, and increased by drilling solids (clays, shale cuttings) and inert drilling solids (sand). Finer particles have higher PV due to increased surface area. (The water phase of drilling fluid coats the surface of the solids). PV is decreased by removing solids using shale shakers, desanders, desilters and centrifuges. Lowering the gel strength allows larger particles to settle out. Dilution of solids with water is a frequent drill-site practice. Engineers want a shear thinning drilling fluid, thin at the bit nozzles when under high shear, then viscosity increases in annulus as shear rate decreases. This helps with hole cleaning (Liu p ). 3.3 Yield Point Yield Point is the resistance to flow due to electrical attraction between solids under flowing conditions. It is main factor that causes cuttings to come out of the hole, while plastic viscosity has a small impact. High YP implies a non-newtonian fluid or one that carries cuttings better than a fluid similar density but lower YP. YP is lowered by adding deflocculant and increase by adding freshly dispersed clay or a flocculant, such as lime. The Bingham Plastic model assumes that fluid will not flow until the shear stress exceeds the YP (Liu p ). 3.4 Drilling Mud The drilling fluid program greatly affects the friction factors that are encountered during the drilling of a well. The choice of mud types and the type of formation determine the lubricity of the mud. In a conventional well, torque and drag friction factors are usually within 20% of 38

53 the predicted amount; however, in extended reach or highly deviated wells, torques can vary substantially with the lubricity of the drilling fluid Selection of Mud Type Selection of the mud type can make a significant impact on drilling efficiency and stability because friction factors can vary widely with the choice of oil-base or water-base mud systems. Water-base systems may perform well in the upper sections of a horizontal well, but perform poorly in the lower sections. Overall, friction factors are lowered by the application of an oil-base mud system Additives Additives to the drilling mud determine the effectiveness of the mud to the drilling application. For example, gel strength (the ability of the fluid to suspend particles) is significantly more important in horizontal drilling than in vertical drilling. Bentonite is widely used as a mud additive in directional drilling. Bentonite particles build a wall cake on the inside of the borehole, sealing the walls of the borehole and minimizing the drilling fluid that enters the formation. Polymer additives are used to prevent skin damage, damage to the formations caused by solids and fluids entering the formation. Polymers lubricate and increase gel strength, inhibiting the absorption of fluids into the formation; however, polymers can only be added to water- or brine-base mud. Lost circulation material is added to mud when the wellbore fluid escapes into the formation and does not continue its cyclical travel from the mud pits, down into the well, and back to the surface. Lost circulation material can form beds on the low-side of the well, producing much lower friction between the drillstring and the formation. This lower friction reduces torque and drag values. (Robinson L, Growcock F-2005) Preparation of drilling mud: The preparation of drilling mud performed in drilling lab. The drilling mud prepared for doing rheology modeling and experimental work of annular flow modeling. For this experiment water based drilling mud is prepared. In this experiment water is taken 20 liter, bentonite 850 gm and barite 100 gm, soda ash and caustic 50 gm. The mud balance density of 39

54 drilling mud is 9 ppg ( kg/m 3 ) and quart funnel viscosity cp (0.001 Pa) [A1]. Due to some limitations of experimental setup low density and low viscosity is preferred for experiment. 3.5 Rheology Data After the preparation of drilling mud, the rheology testing of the drilling mud is done in drilling lab with the help of rheometer or fann-50 viscometer. The reading of fann viscometer is taken at different speed rheometer like R 600, R 300, R 200, R 100, R 6, and R 3. Here below table 6.1 shows the rheometer reading at different speed and table 6.2 shows different rheology data after calculation. RPM (R) Reading ( ) Table 3.1: Fann-50 Rheometer reading After getting Fann-50 Rheometer reading, the properties of the prepared drilling mud find out in drilling fluid lab. Density of the drilling mud measured directly in ppg by mud balance meter. The viscosity is also measured with the help of Marsh funnel. The PH value measured with PH meter. Other properties of the drilling fluid calculated with the help of rheometer reading as shown in appendix [A2]. Then calculated result of the drilling fluid properties are showing in below Table 3.2. This table shows value of drilling mud properties after calculation of rheometer data, like Density, Viscosity, Gel Strength, Plastic viscosity, Yield Point, Consistency Factor, and Flow Behavior Index etc. 40

55 1. Density of Drilling mud ( ) 9 ppg or Kg/m 3 2. Marsh funnel viscosity ( ) cp (0.001 Pa) 3. PH value of Drilling mud Plastic Viscosity (PV) 3 cp (0.001 Pa) 5. Yield Point (YP) 4.5 lbf/100 ft 2 (.049 kgf/m 2 ) 6. Apparent Viscosity 5.25 cp 7. Gel Strength 3.5 lbf/100 ft 2 (.049 kgf/m 2 ) 8. Consistency factor (K) 5.72 lbf sec n /100 ft 2 (.049 kgf.sec n /m 2 ) 9. Flow behavior index (n) Yield stress 3 lbf/100 ft 2 (.049 kgf/m 2 ) Table 3.2: Rheology data of the drilling mud 3.6 Procedure for selecting the best Rheological models Most drilling fluids used today are dispersions. Many fluid properties depend on the system s rheology. The rheology of dispersions is complex, since they usually exhibit non-newtonian behavior. Non-Newtonian fluids are those fluids that do not conform to a direct proportionality between shear stress and shear rate, and no single equation has been proved to describe exactly the rheogram of all such fluids. Conventional rheological models in widespread use for the past half century in the oil industry include the Bingham plastic, Power-law, and Newtonian models. Of these, the Bingham plastic is advantageous because it includes a yield point that is a positive shear stress at zero shear rate, which most drilling fluids, cement slurries, and spaces have. 41

56 More recently, the Herschel-Bulkley model has seen increased usage because it accommodates the existence of a yield point (Bingham plastic) as well as nonlinearity of the relationship of shear stress to shear rate (Power-law). We assumed that the model which gives the lowest absolute average percent error (EAAP) between the measured and calculated shear stresses is the best one for a given non-newtonian fluid (Ochoa M. V. 2006). Selection of the best model is of great importance in achieving correct results for pressure drop and hydraulics calculations Newtonian Model A fluid that has a constant viscosity at all shear rates at a constant temperature and pressure is called a Newtonian fluid. Also, it can be described by a one- parameter rheological model. An equation describing a Newtonian fluid is given below:.. (3.3) When the shear stress (τ) of a Newtonian fluid is plotted against the shear rate (γ) in linear coordinates a straight line through the origin results. The Newtonian viscosity (µ) is the slope of this line (Ochoa M. V. 2006). RPM (R) Reading ( ) Table 3.1: Fann-50 Rheometer reading 42

57 To transform the laboratory data units to field engineering units (Table 3.1), we have to apply conversion factors: (Ochoa M. V. 2006) (3.4) (3.5) Then with the help of conversion factor, the Shear Stress and Shear rate measured. Table 3.3 shows the measured value of the shear stress and shear rate. (Sec -1 ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) Table 3.3: - Shear Stress Measured in Field Units Figure 3.1 shows the Newtonian rheogram; from the equation of straight line we can estimate the slope, µ= lbf.sec/100 ft 2 (.049 kgf.sec/m 2 ). The straight line was obtained using linear regression techniques. 43

58 (lbf/100 ft 2 ) Newtonian fluid Rheogram (Sec -1 ) = Measured Data Linear (Measured Data) Figure 3.1: Newtonian fluid Rheogram To estimate viscosity in field units (cp) we have to convert by the following equation: µ = m/100 (3.6) Now, we can estimate the shear stresses as function of viscosity. Table 3.4 shows the results (Sec -1 ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) Table 3.4: Shear Stress Calculated as Function of Viscosity To estimate the EAAP, we used a statistical method. This method is used between the measured and calculated shear stresses: 1/ / 100 (3.7) 44

59 Using this example, for the Newtonian model EAAP = 49.95%. Figure 3.2 shows a comparison between measured and calculated data. Newtonian fluid Rheogram (lbf/100 ft 2 ) Measured Data Calculated Data (Sec -1 ) Figure 3.2: Comparison between measured data and calculated data Bingham Plastic Model The Bingham plastic model was the first two-parameter model that gained widespread acceptance in the drilling industry and is simple to visualize. However, it does not represent accurately the behavior of the drilling fluid at very low shear rates (in the annulus) or at very high shear rate (at the bit).... (3.8) The Bingham parameters, yield point ( ) and plastic viscosity ( ) can be read from a graph or can be calculated by the following equations (Ochoa M. V. 2006). (3.9) (3.10) Let us consider the same data used in the Newtonian model to show the calculations for the Bingham plastic model. Figure 3.3 and Table 3.5 show the results. The straight line was obtained using linear regression techniques. 45

60 Bingham Plastic fluid Rheogram (lbf/100 ft 2 ) (Sec -1 ) = Measured Data Linear (Measured Data) Figure 3.3 Bingham plastic fluid Rheogram. From equation τ Y lbf/100 ft2 μ P (Sec -1 ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) Table 3.5: Shear Stress Calculated as Function of Plastic Viscosity and Yield Point Eq. 3.7 was used to estimate the absolute average percent error (EAAP), which for this example, for the Bingham plastic model, is 1.83%. Fig. 4.4 shows a comparison between measured and calculated data. 46

61 (lbf/100 ft 2 ) Bingham Plastic fluid Rheogram (Sec -1 ) Measured Data Calculated Data Figure 3.4: Comparison between measured data and calculated data Power Law Model The Bingham plastic model assumes a linear relationship between shear stress and shear rate. However, a better representation of the behavior of a drilling fluid is to consider a Power-law relationship between viscosity and shear rate such that:.. (3.11) Where K is the consistence index and n is flow behavior index. Above Eq. was linearized as follows: (3.12) Where n is determined from the slope and k is the intercept. The Power-law model provides more information in the low-shear-rate condition but still has a weakness at high shear rates (Ochoa M. V. 2006). Let us consider the data given in the Newtonian model to illustrate the calculations. The first step is to obtain a logarithmic graph shear rate and shear stress from Table 3.2. Fig. 3.5 and Table 3.6 show the results. The straight line was obtained using linear regression techniques (least-squares regression) 47

62 (lbf/100 ft 2 ) Power law fluid Rheogram (Sec -1 ) = Measured Data Power (Measured Data) Figure 3.5: Power-law fluid Rheogram From Figure 3.5 the Power law parameters are: n = k = lbf.sec n /100ft 2 (Sec -1 ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) Table 3.6: Shear Stress Calculated as Function of Power Law Parameters One of the obvious disadvantages of the Power law is that it fails to describe the low-shearrate region. Since n is usually less than one, at low shear rate μ goes to infinity (only as 0) rather than to a constant, as usually observed experimentally. 48

63 Viscosities also become Newtonian at high shear rates for many suspensions and dilute polymer solutions. Using Eq. 3.7, EAAP = 0.016%. Figure 3.6 shows a comparison between measured and calculated data. 12 Power law fluid Rheogram (lbf/100 ft 2 ) Measured Data Calculated Data (Sec -1 ) Figure 3.6: Comparison between measured data and calculated data Note that the estimations of Power-law parameters also can be made by the following equations: 3.32 (3.13) (3.14) But for our case from figure 3.5, n = and k = lbf.sec n /100ft 2 (.049 kgf/m 2 ). These equations to estimate Power law parameters are used for hydraulics calculation Herschel-Bulkley The Herschel-Bulkley model defines a fluid by three-parameter and can be described mathematically as follows:... (3.15)... (3.16) 49

64 For τ τ the material remains rigid. For τ τ the material flows as a Powerlaw fluid. The Herschel-Bulkley equation is preferred to Power-law or Bingham relationships because it results in more accurate models of rheological behavior when adequate experimental data are available. The yield stress is normally taken as the 3 RPM reading. However, we are taking Versan and Tolga s approach to obtain τ. Then n and k values can be calculated from the 600 and 300 RPM values or graphically. The Power-law model described above is valid for fluids for which the shear stress is zero when the strain rate is zero. The Herschel-Bulkley model is commonly used to describe materials such as concrete, mud, dough, and toothpaste, for which a constant viscosity after a critical shear stress is a reasonable assumption when a log-log graph is made. In addition to the transition behavior between a flow and no-flow regime, the Herschel-Bulkley model can also exhibit a shear-thinning or shear thickening behavior depending on the value of n (Ochoa M. V. 2006). Since this is a three-parameter model, an initial calculation of τ is required for other parameter calculations. τ is calculated by (Versan and Tolga). (3.17) Where τ is the shear stress value corresponding to the geometric mean of the shear rate.... (3.18) From Eq. 3.18, γ = sec -1. Then using this value we can interpolate between values of shear stress in Table 3.3, = lbf/100ft 2 (.049 kgf/m 2 ) Finally, from Eq = lbf/100ft 2 (.049 kgf/m 2 ) Figure 3.7 and Table 3.7 show the results. The straight line was obtained using linear regression techniques. 50

65 (Sec -1 ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) ( ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) Table 3.7: Calculated Shear Stress (τ τ ) Herschel-Bulkley Rheogram 10 0 = (lbf/100 ft 2 ) Measured Data Power (Measured Data) 0.1 (Sec -1 ) Figure 3.7: Herschel-Bulkley fluid Rheogram From Fig. 3.7 the Herschel-Bulkley parameters are n = k = lbf.sec n /100ft 2 (.049 kgf.sec n /m 2 ) 51

66 (Sec -1 ) (lbf/100 ft 2 ) (.049 kgf/m 2 ) Table 3.8: Shear Stress Calculated as Function of Herschel-Bulkley Parameters Using Eq. 3.7, EAAP = 0.195%. Figure 3.8 shows a comparison between measured and calculated data. 12 Herschel-Bulkley Rheogram (lbf/100 ft 2 ) Measured Data Calculated Data (Sec -1 ) Figure 3.8: Comparison between measured data and calculated data Hence, the result of selection of best rheology model of drilling fluid comes through Absolute Average Percentage Error (EAAP). It is proved that the prepared drilling mud in the drilling fluid laboratory follows power law model. Then in next chapter, drilling fluid flow model described for power law fluid. 52

67 Chapter - 4 Drilling fluid flow model The model described in this section is based upon the analyses of Reed and Pilehvari, in SPE paper published in The method is based upon relating non- Newtonian flows to Newtonian flows, and the definition of an effective diameter is a key concept within the model. This concept is important because it accounts for both geometric and non- Newtonian effects on frictional pressure gradients in pipes and annuli. The analysis is valid for laminar, transitional, and fully turbulent flow regimes. The method incorporates new transition criteria that account for the delay in flow transition with increasing ratio of inner to outer diameters in concentric annuli. These criteria agree with experimental data reported in the literature presented by Reed and Pilehvari. When using the same viscometer data, the results from the analyses (included below) show that the transition from laminar to turbulent flow occurs at higher pump rates than for a Power Law fluid, but significantly lower than for the corresponding Bingham plastic fluid. For turbulent flow, the Colebrook equation is modified so that the equation applies to non-newtonian flows through pipes and annuli with smooth or rough walls. The method also accounts for the effects of wall roughness on frictional pressure gradients in transitional flow. The iterative solution proposed below is slightly more time-consuming than a direct calculation using explicit friction factors, but avoids the necessity for computationally expensive finite-difference or finite-element simulations. (Liu p., 2008) 4.1 Newtonian fluid flow model Newtonian flow is defined by:..... (4.1) Where = Shear Stress, = Viscosity = Shear Rate The calculations for the different flow regimes of a Newtonian fluid are given next. The hydraulic diameter is defined as follow: (Liu p., 2008). 53

68 . (4.2) Where D hy = hydraulic diameter D o = outer diameter D i = Inner diameter Laminar Pipe Flow The Reynolds number (Re) is defined as: (Liu p., 2008)... (4.3) Where D is the pipe inner diameter, V is the fluid velocity in the pipe, is the Newtonian viscosity, and is the local fluid density. The laminar friction factor is given as follows:.. (4.4) The corresponding frictional pressure gradient is given by the following: (4.5) Where all terms have been defined above Laminar Annular Flow The analysis for annular flow is similar to that of pipe flow, except that the Reynolds number for annular flow is based on the equivalent diameter D eq as defined by:... (4.6) and the frictional pressure gradient is based on the hydraulic diameter, as follows: (4.7) 54

69 4.2 Power Law fluid model Calculations are given for the following regimes of a Power Law fluid: laminar pipe flow, laminar annular flow, turbulent pipe and annular flow, and transitional pipe and annular flow Laminar Pipe Flow modeling In laminar pipe flow, an effective diameter is defined. The Reynolds number (Re) is defined by Equation 4.3. So, the following applies: (Liu p., 2008).... (4.8) Where D is the pipe diameter The average wall shear rate is defined as follows:.... (4.9) The effective viscosity becomes as follows: (4.10) Consequently, the Reynolds number and friction factor are as follows:.. (4.11) and f lam is defined by Equation (4.12) Laminar Annular Flow modeling This calculation is a bit more involved because of the nature of the geometry. In laminar annular flow modeling of the power law fluid requires precisely calculated D eff. The value of the D eff is calculated by the help power law functions Y, Z, and G. However, a good solution is given by Reed and Pilehvari. First, the parameters are given that describe the new effective 55

70 diameter and allow for the effects of both the annular geometry and the non-newtonian behavior of the fluid. This is based on the work by Reed and Pilehvari. Y = 0.37 n. (4.13) 1 1. (4.14) The effective diameter is defined as follows: 1 (4.15).. (4.16) Here effective diameter calculated by the power law functions, which is given by work of Reed and Pilehaveri. Table no. 4.1 shows the effective diameter and effective area D eff (m) A (m 2 ) Density, (Kg/m 3 ) Viscosity, (Pa.s) Table 4.1: Effective Diameter of annular flow of power law fluid 4.3 Experimental Work The experimental work is performed on developed and modified experimental setup of Reynolds number. In this experimental setup drilling fluid flow regimes find out and Reynolds number of the drilling fluid is calculated at different flow rate. The experimental work of this study contains description of the experimental setup, annular drilling fluid flow modeling and annular pressure loss modeling. 56

71 Plate 4.1: Experimental setup 4.4 Description of experimental setup: The description of the experimental setup contains dimensions of the experimental setup and procedure of the experiment for fluid flow modeling. The dimension of the experimental setup is showing in appendix-4. The description of the experimental setup describes the various part of the equipment. 1. Tank: This is the important part of the experimental setup which contains the drilling mud. The size of the tank is cm. tank is connected by the pump and a return flow pipe from annulus pipe. Plate 4.2: Mud tank of Experimental setup 57

72 2. Pump: This is also an important part of the experimental setup which is used for circulating drilling fluid from annulus pipe. Here in this experimental setup centrifugal pump is used. Plate 4.3: Mud Pump of Experimental setup 3. Annulus pipe: This is the main part of the experimental setup which is consisting by transparent glass. Then fluid flow regimes can see directly by eyes. Concentric annulus is provided by a 10 mm rod. The diameter of glass pipe is 35 mm and length of the annulus is 100 cm. the one end of the annulus pipe is connected by the drilling mud supply pipe and other end is connected with the flow control valve. Plate 4.4: Annulus Pipe of Experimental setup 4. Valve it is also a main part of the experimental setup which controls the annular flow. So it is called as control valve. It is a gate valve and connected at the one end of annulus pipe. Annulus flow is controlled by the rotating of its lever. 58

73 Plate 4.5: Gate valve of Experimental setup 5. Manometer In this experimental setup U-tube manometer is used and the fluid of manometer is CCl4. The aim of using CCl4 is better and precisely reading of annular friction pressure loss. The deflection of level of U-tube can be read on a scale. 6. Control panel it is used for controlling electrical supply by a on-off switch. There is also a red indicator which shows either power is on or off. Plate 4.6: Control panel of Experimental setup 59

74 4.5 Procedure of the Experiment Clean the tank with help of wet and dry cloth. Fill the tank with drilling mud. Connect the power wire with electrical supply. Close the valve fully. Switch on pump by on-off switch. Open the valve slowly. Take reading after 1 or 2 minute. Measure volume and time of drilling fluid flow. Take the reading of manometer. Again open valve slowly Measure volume and time drilling fluid flow and take reading of manometer. Figure 4.7: Schematic diagram of the experimental setup 60

75 4.6 Experimental reading of fluid flow through annular pipe Here below table no. shows the experimental reading of drilling fluid flow through the annulus. Time and volume is taken at different flow rate. Three times reading of time and volume is taken for decreasing human error by calculating average time and average volume. Time (S) Volume (ml) Average T1 T2 T3 V1 V2 V3 T av V av Table 4.2: Experimental reading of drilling fluid flow through annulus Then flow rate and velocity of the drilling fluid flow through annulus calculated with the help of experimental reading. Reynolds number is calculated by power law formula. Here below 61

76 table 4.3 Shows the Reynolds number of power law drilling fluid. Reynolds number shows laminar fluid flow regime. Flow rate Q (m 3 /s) Velocity V (m/s) Reynolds Number Re Table 4.3: Reynolds number of drilling fluid flow through annulus 4.7 Pressure Drop Flow conditions in the drill-pipe are usually turbulent and are, therefore, primarily influenced by the viscous properties of the mud. The effective shear rate at the pipe wall is generally between 200 and 1,000 reciprocal seconds. The conduit dimensions are typically known quite accurately, so pressure losses can be determined quite accurately. The only uncertainties involved are the tool joint losses and the roughness of the pipe walls. The pressure loss in the drillpipe is about 20 to 45% of the pressure loss over the entire circulating system. The total drill string pressure loss is measured at the standpipe. Flow velocity through the bit nozzles is extremely high, corresponding to shear rates of about 100,000 reciprocal seconds. The pressure loss across the nozzles can be easily calculated. The pressure loss across the bit nozzles is typically about 50 to 75% of the standpipe pressure. Flow in the annulus is usually laminar and is, therefore, a property of the viscous properties of the mud. (Liu p., 2008) 62

77 Shear rates are generally between 50 and 150 reciprocal seconds. The pressure loss from the bit to the surface comprises only about 10% of the standpipe pressure in a conventional hole geometry (it is higher in slim holes). However, knowledge of the pressure and flow in the various sections of the annulus is very important when dealing with such problems as hole cleaning, induced fracturing, and hole erosion. Unfortunately, accurate prediction of the flow relationships is usually difficult because of the numerous unknowns and uncertainties. Perhaps the greatest of the unknowns is the true diameter of the hole, which may be as much as twice the nominal diameter in enlarged sections of the hole, decreasing the rising velocity of the mud by a factor of at least five. From the earlier discussions, joint losses and pipe roughness are also major uncertainties. The influence of the drillpipe rotation on the velocity profile is also difficult to account for (Bode, 1991, McCann, 1995, Lockett, 1991, Lockett, 1993). There are equations available for helical flow, but there is debate about whether fluid particles actually follow a helical path in the presence of rotation. These equations were derived for drillpipe rotating concentrically in a vertical hole. In practice, the drillpipe whirls around in a seemingly random manner, particularly in deviated wellbores. Furthermore, equations for flow in eccentric annuli show that the annular velocity is greatly lowered when the drillpipe lies against the low side of the hole (as in directionally drilled wells); therefore, equations based on concentric annuli are seriously in error. Neither is there a way to account for the influence of thixotropy on the viscosity of the mud as the mud rises in the annulus. The high shear rates in the drillpipe and bit reduce the viscosity to a very low value. The shear rates in the annulus are far lower, but change in each annular section, depending upon the drill collar, drillpipe, casing diameters, and degree of hole enlargement. The viscosity adjusts to each shear rate, but may take time to do so, and might never reach an equilibrium value (except in long sections of gauge or cased hole). (Liu p., 2008) To summarize, accurate pressure losses in the drillpipe and bit are reasonably easy to predict, but pressure losses in the annulus are more questionable. However, quite accurate losses are obtained for the whole circulatory system because the annular loss (usually) forms such a small percentage of the total loss. The results of the field tests of Fontenot and Clark (1974) support these conclusions. The rigorous flow equations and testing procedures described in this thesis are suitable for laboratory investigations and for detailing the models used in the Osprey Risk software. A number of methods of making well site hydraulic calculations are 63

78 published, the complexity of which varies according to the authors acceptable degree of accuracy. Whittaker (1985) has reviewed these procedures and makes the following recommendation for making annular pressure calculations: When drilling in formations that enlarge significantly calculate the pressure loss in the drillpipe and in the bit nozzles and subtract this figure from the sum of the standpipe pressure. The resulting figure is the annular pressure loss. (Whittaker, 1985). The above method is open to the objection that the pressure loss in the bit and drillpipe form such a large proportion of the system pressure losses that a small error will cause a large percentage error in the annular pressure loss. To estimate accurate annular pressure losses while drilling, the use of an APWD (Annular Pressure While Drilling) sensor may be more appropriate (Hutchinson and Cooper, 1998). 4.8 Annular pressure loss modeling The annular pressure loss is the total pressure loss resulting from the frictional forces developed by circulation of the mud in the wellbore annulus over a given length (measured depth). Then consideration of annular pressure loss becomes more important for calculating bottom hole pressure in managed pressure drilling. The pressure loss in the open hole section can also be determined in the field by calculating the pressure loss in the cased hole section and subtracting that loss from the total annular loss. Osprey Risk also expresses the additional effects of the annular pressure losses (and of suspended cuttings) in terms of the equivalent circulating density (ECD). The ECD is defined as the effective mud weight at a given depth, created by the total hydrostatic (including cuttings pressure) and dynamic (friction loss) pressures. (Liu p., 2008) Annular pressure loss calculated by following formula for power law drilling fluid. (4.17) Where, = Annular pressure loss = hydraulic diameter = Effective diameter = Fluid flow velocity 64

79 Here following table no. shows the annular pressure loss for given power law drilling fluid. Annular pressure loss is calculated at different velocity of flowing fluid. Flow index and consistency factor of the drilling remains constant. Then behavior of pressure loss can be predicted by a graph with respect to Reynolds number. pressure loss Velocity Flow index Consistency (Theoretical) Reynolds V (m/s) (n) factor (k) 4 K (8 V) n /D hy Number (D eff ) n (Re) Table 4.4: Annular pressure loss with respect to Reynolds number 4.9 Friction Factor Friction is a result of the contact between the wellbore and the drillstring during lateral and axial movement of the drillstring. Torque losses and drag losses are experienced because of the frictional force involved in rotating, sliding, and reaming with the drillstring in the wellbore. A friction factor is defined as the ratio of the force required to move an object, divided by the side force between the object and the surface on which it is resting (Belaskie, 1994). The friction factor is always less than unity. Depending upon the nature of the drillstring motion, frictional forces may be drag forces, axial motion of the drillstring only sliding mode, frictional torque generated by rotation 65

80 only (rotating mode) or a combination of both translation and rotation friction i.e., torque and drag reaming mode. (Liu p., 2008) There are numerous factors that determine the friction encountered in the actual drilling of the well, such as the drilling fluid program, lithology, use and type of drillpipe protectors, differential sticking, cuttings, and unstable formations such as sloughing shales and swelling clays. Pressure loss Reynolds Number Re (Theoretical) 4 K (8 V) n /D hy (D eff ) n (Pa) Friction factor f lam =16/Re Table 4.5: Friction factor of the annulus 4.10 Equivalent Circulating Density When circulating a drilling fluid, friction increases the well bore pressure over the static condition. The equivalent circulating density at any point accounts for the sum of hydrostatic pressure of a column of fluid and frictional pressure loss above that point. Thus, at any point of interest, the dynamics equivalent density, ECD, is higher than the static equivalent mud density, EMD. The ECD is calculated as. (4.18) Where 66

81 = static equivalent density of a column of fluid that is open to the atmosphere = frictional pressure loss = true vertical depth = constant, in the English system is equal to and in the metric system is equal to 0.01 When changes in viscosity with temperature and pressure are taken into account, the calculation of ECD becomes more complicate, especially in HPHT wells. To avoid kicks and losses, particularly in wells that have a narrow window between the pore pressure gradient and fracture gradient, constant monitoring of ECD is a must. Reynolds Number Re pressure loss (Theoretical) 4 K (8 V) n /D hy (D eff ) n (Pa) ECD (kg/m 3 ) Table 4.6: Equivalent circulating density of annular flow 4.11 Kinematics modeling of MPD The kinematics modeling of MPD is described by drilling parameters like rate of penetration, RPM of drill pipe, drilling fluid viscosity and density etc. the kinematics modeling of drilling at the bottomhole can distinguish managed pressure drilling from other processes like OBD and UBD. Here in this dissertation work kinematics modeling is developing with the dimensional analysis method. 67

82 Dimensional analysis Dimensional analysis is a mathematical techniques used in research work for design and for conducting model tests. It deals with the dimensions of the physical quantities involved in the phenomenon. All physical quantities are measured by comparison, which is made with an arbitrarily fixed value. Length L, Mass M, and Time T are three fixed dimensions which have importance in fluid mechanics, temperature is also taken as fixed dimension. These fixed dimensions are called fundamental dimensions or fundamental quantity Methods of dimensional analysis If the numbers of variables involved in a physical phenomenon are known, then relation among the variables can be determined by following two methods: Rayleigh s method Buckingham s π- Theorem Development of dimensional analysis model The present work uses the technique of dimensional analysis to develop a semi theoretical model of kinematics of drilling near the bottomhole in managed pressure drilling. Dimensional analysis is a method by which we can predict information about a phenomenon of drilling parameters at the bottomhole during circulation. The theory of dimensional analysis is the mathematical theory which is purely algebraic. The application of dimensional analysis is based on the hypothesis that the solution of the problem is expressible by means of a dimensionally homogeneous equation in terms of specified variables In the developed model, the parameters of the managed pressure drilling are drilling fluid density, viscosity, flow rate, pressure, rate of penetration, drill string rotation speed, depth, The dimensions of these variables as well as their values are shown in Table 4.7. Applying dimensional analysis method on the given below drilling parameters. There are seven variables in which one is dependent variable and other are independent variables. So the function of all these parameters will be zero. Then it can be represented by following equations. Δp = f (ΔQ, µ, ρ, r, d, ω) (4.19) f (Δp, ΔQ, µ, ρ, r, d, ω) = 0 (4.20) 68

83 Properties Unit Symbol dimensions Pressure N/m 2 Δp M L -1 T -2 Flow rate m 3 /s ΔQ M 0 L 3 T -1 Viscosity Pa.s Δµ M L -1 T -1 density Kg/m 3 Δρ M L -3 T 0 Drill string rotation rad/s ω M 0 L 0 T -1 Drilling depth m d M 0 L T 0 Rate of penetration m/s r M 0 L T -1 Table 4.7: shows Units and Dimensions of the Drilling Parameters Buckingham s π theorem Buckingham theorem is based on knowledge if there are M basics dimensions and N variables then are M N dimensionless numbers. In the present study, this theorem is used to assemble all variables appearing in the problem in a number of dimensionless products (π s). The required relations connecting the individual variables are determined as algebraic expressions relating π s. A dimensional matrix is then formulated as shown in Table 4.8, where the dependent as well as independent variables are defined as per their fundamental dimensions, where x1, x2, x3, x4, x5, x6, and x7 are the indices of the variables in equation respectively. Dimensions X 1 X 2 X 3 X 4 X 5 X 6 X 7 Δp ΔQ Δµ Δ r d ω M L T Table 4.8: shows fundamental Dimensions of the Drilling Parameters 69

84 The results of dimensional analysis are shown in Table 4.8. The detailed derivation of this model is given in the Appendix A5. Hence, as per the results shown in table 4.8, the following complete set of dimensionless products is obtained: (4.21) (4.22). (4.23). (4.24) Here above equations shows that rate of penetration and depth of drilling are really strong function for drilling process. Since,,, 0... (4.25) Note that equation (4.25) can also be written as;,,. (4.26) Therefore, the final form of the model can be written as below:,, Then (4.27) Finally above equation shows the pressure loss during the circulation of drilling fluid. Here, k is the coefficient and a, b and c are the power indexes of the corresponding dimensionless bracket, i.e. Πs. The exact relation may be obtained after getting the values of these power indexes. Also, the value of power indexes may get through experimentally. Then for getting these values, the design of experimental setup also designed by me which is showing in appendix [A6]. 70

85 Chapter 5 Result and Discussion This dissertation work discussed experimental and modeling based investigation of Managed Pressure Drilling. Experimental and modeling based investigation contains selection criteria of drilling fluid model, annular flow modeling, annular pressure loss modeling and equivalent circulation density (ECD) calculation. Annular pressure loss and equivalent circulation density is very important for hydraulics calculation of managed pressure drilling. Bottom hole pressure can be precisely controlled by annular pressure loss, ECD and provided back pressure. So here it can be say that this dissertation work nearly focused on hydraulics of managed pressure drilling. 5.1 Selection of drilling fluid model The non-newtonian drilling fluid has been used to illustrate the accuracy of this approach for selecting the best rheological model, one with the lowest E AAP value. The physical properties of this fluid are given in Table 3.2, and the values for the absolute average percent error are given for each model in Table 5.1. Rheological Model EAAP (%) Newtonian model Bingham model 1.83 Herschel & Bulkley model Power Law model Table 5.1 Values of absolute average percent error Table 5.1 shows that the Power law model is the best model to represent the rheological properties for this non-newtonian fluid. However, it was close followed by Herschel- Bulkley. The Newtonian and Bingham models gave high values of EAAP for the fluid, and therefore they are not recommended for use in pressure drop and hydraulics calculations. 71

86 5.2 Drilling fluid flow modeling The model described in this section is based upon the analyses of fluid flow through annulus. The method is based upon relating non- Newtonian flows, and the definition of an effective diameter is a key concept within the model. This concept is important because it accounts for geometric and non- Newtonian effects on frictional pressure gradients in pipes and annuli. The analysis is valid for laminar flow regimes. These criteria agree with experimental data reported in the literature presented by Reed and Pilehvari. Here following different graph shows behavior of fluid flow through annular pipe Flow Rate vs. Reynolds Number Here below figure 5.1 shows the behavior of annular flow rate with respect to Reynolds number of the drilling mud. This relation comes through experimental result. In which drilling mud flows through a annulus pipe and experimental Data is collected for getting different relation in fluid flow properties. As shown in Figure 5.1, flow rate is directly proportional to Reynolds number. When the flow rate increased then Reynolds number of the annular flow of drilling mud also increased rapidly. There is laminar flow regime because the Reynolds numbers of drilling mud flow vary from 217 to Flow rate (m 3 /s) 6.00E E E E E E E+00 Q = 1E 07Re 3 2E 06Re 2 + 1E 05Re 4E 06 Flow rate Poly. (Flow rate) Reynolds Number Figure 5.1: Behavior of annular flow rate with respect to Reynolds number 72

87 5.2.2 Velocity vs. Reynolds number: Here below figure no. 8.1 shows the behavior of annular flow Velocity with respect to Reynolds number of the drilling mud. As shown in Figure, Velocity is directly proportional to Reynolds number. When the Velocity of the drilling fluid flow increased then Reynolds number of the annular flow of drilling mud also increased rapidly. The relation between Velocity and Reynolds number of the drilling mud is same as relation between Flow rate and Reynolds number because flow rate and velocity are directly proportional. Velocity V = 0.00Re Re Re Velocity Poly. (Velocity) Reynolds Number Figure 5.2 Behavior of annular flow Velocity with respect to Reynolds number Annular Pressure Loss vs. Reynolds number Annular Pressure Loss is the important factor for study Rheology study or Hydraulics study of the Managed Pressure Drilling because calculation of annular pressure loss plays important role for accurate calculation of Bottomhole Pressure, through which annular pressure controlled precisely. Then modeling of annular pressure loss becomes more useful and important for Managed Pressure Drilling. Here below figure 5.3, shows the behavior of the Annular Pressure Loss with respect to Reynolds number of the drilling mud. Annular pressure loss is directly proportional to the Reynolds number. When the Reynolds number is increased then annular pressure loss first increased rapidly and after slowly. Annular pressure loss is high at less Reynolds number, it s mean at high velocity or flow rate of the drilling mud flow, the annular losses will high. 73

88 Annular pressure loss P AF = 7.810Re Re Re Annular pressure loss Poly. (Annular pressure loss) Reynolds number Figure 5.3 Behavior of annular pressure loss with respect to Reynolds number Friction factor vs. Reynolds number: Friction factor is the important factor for the Rheology modeling of drilling fluid. Friction factor also plays important role for find out fluid flow behavior through pipe or annulus. It provides pressure loss for different different material and helps for calculating bottomhole pressure. Here in figure 5.4 show that when Reynolds number of the drilling mud is less then friction factor is high. It s mean at starting or at low flow rate and low velocity, the friction factor of the fluid flow is high. The high friction factor shows high pressure loss. Here in figure shows that friction factor first drop rapid and after slowly when Reynolds number increased. Friction factor f = 1E 05Re Re Re Re Re Re Friction factor Poly. (Friction factor) Reynolds Number Figure 5.4 Behavior of annular friction factor with respect to Reynolds number 74

89 5.2.5 ECD vs. Reynolds number Equivalent Circulating Density is the very important factor for the hydraulics of the Managed Pressure Drilling. When drilling fluid flows through the annulus then it loose its properties, it means the density of the drilling fluid changes. Then it becomes very difficult to maintain or control Bottomhole pressure precisely within the pore pressure line (for MPD). So determination of the Equivalent circulating density for annulus flow is very important in MPD. Here below figure 8.5 shows that Equivalent circulating density varies first rapidly and after slowly and in figure 8.6 ECD also varies rapidly and after slowly. Its mean ECD changes according to the annular pressure loss and flow rate of the drilling fluid flow. ECD ECD = 150.2Re Re Re ECD Poly. (ECD) Reynolds Number Figure 5.5 Behavior of ECD in annular flow with respect to Reynolds number ECD ECD = 150.2Re Re Re ECD Poly. (ECD) Annular Pressure Loss Figure 5.6 Behavior of ECD in annular flow with respect to Annular pressure loss 75

90 5.3 Parametric Equations for annular flow Above all the figures shows different relationship with the drilling fluid parameters and Reynolds number of the drilling fluid flow. Different equations can be generated with the help of drilling fluid parameters. These equations are generated on the base of Reynolds number of the drilling fluid flow. Since experimental data is taken as only for laminar fluid flow. Then, these equations will effective only within laminar region. Hence we can calculate these drilling parameters, by putting value of Reynolds number in given equations. Parameters Equation Flow Rate Q = 1E-07Re 3-2E-06Re 2 + 1E-05Re - 4E-06 Velocity V = 0.00Re Re Re Annular Pressure Loss P AF = 7.810Re Re Re Friction Factor F = 1E-05Re Re Re Re Re Re Equivalent Circulating Density ECD = 150.2Re Re Re Table 5.2: Parametric equations 5.4 Kinematics study of MPD Managed Pressure Drilling process distinguished by bottomhole pressure profile and equipment used in this process. Here in this dissertation work, it is tried to understand basics of managed pressure drilling through both experimental and modeling based investigation. For kinematics study, a mathematical model is developed by doing dimensional analysis of drilling parameters. Dimensional analysis gives four equations of dimensional less number. By these equations different relations can be generated. Here an equation is developed for pressure loss during circulation of the drilling fluid. 76

91 Chapter 6 Summary and Conclusion 6.1 Summary Managed pressure drilling with a constant bottomhole pressure is an adapting drilling method that increases the feasibility of successfully drilling wells with a narrow margin between the pore pressure and the fracture pressure. The narrow margin window exists in mature or depleted field and increases the chances of taking a kick and lost returns. The conventional well control method depends on mud hydrostatic pressure for primary control of the well. However, managed pressure drilling typically uses a mud weight that is less than the pore pressure gradient and utilizes the wellbore frictional pressures and back pressure to control the pore pressure. Then Hydraulics of MPD and Rheology of the drilling fluid becomes more important for controlling pore pressure and walking on pore pressure line as the requirement of managed pressure drilling. The objective of this dissertation work is to understand basics of managed pressure drilling, study of drilling fluid rheology modeling and determine governing relationship, while considering drilling fluid flows through a concentric annular pipe. As it was impossible to experimentally manage the pore pressure requirement, the above experiment was conducted on a horizontal pipe with a central insert of 10 mm. before carrying out the experimental work a theoretical model for MPD was developed using method of dimensional analysis. The relationship so develop where evaluated at different Reynolds number. The same set of the parameters where validated with the experimental results. Finally the parametric relationships are developed for flow rate, velocity, annular pressure loss and equivalent circulating density, as a function of Reynolds number. These parameters are used to calculating hydraulics of MPD and controlling annular pressure. 77

92 6.2 Conclusion Through the present dissertation work of modeling and experimental based investigation of manage pressure drilling it can be concluded a under: Managed pressure drilling is a newly adapting process that is improves the economy of wells. It reduces the non productive time by mitigating drilling problems. It is also useful for mature field or Brownfield environment. The aim of preparation of drilling mud is performed in drilling laboratory and prepared 9 ppg density, cp viscosity and 10 PH water base drilling mud for 20 liter water. Rheology data of drilling mud is taken on Fann-50 rheometer at different speed (R 600, R 300, R 200, R 100, R 6 and R 3 ) and rheology parameters like plastic viscosity, yield point, gel strength and apparent viscosity calculated. The rheological models like, Non-Newtonian, Bingham plastic, Power-law and Herschel-Bulkley have been evaluated for accurate representation of the wide range of shear stress/shear rate data. These models are confirmed to describe sufficiently the rheology of most non-newtonian fluids. Selection of the best rheological model has great importance in obtaining correct results for pressure drop and hydraulics of Managed Pressure Drilling. A simple and direct approach has been presented for selecting the best rheological model for any non-newtonian fluid according to the lowest EAAP criteria. The power law model is applied with high confidence to predict rheological properties and hydraulics calculations for water based mud. The experimental work is performed on a modified experimental setup and data is taken for concentric annular pipe flow. Annulus is provided by a 10 mm diameter rod. The mathematical model of annular flow created in terms of flow rate, velocity, annular pressure loss and ECD calculation. The model is created for laminar annular flow of power law fluid. In the mathematical model of drilling fluid flow, parametric relationship is developed in flow rate, velocity, annular pressure loss and ECD with the Reynolds number of the laminar fluid flow. 78

93 The kinematics modeling of the managed pressure drilling also developed in which parametric relationship is developed in terms of density, viscosity, RPM, flow rate and pressure loss etc. An experimental setup also designed for validation of kinematics modeling. The Managed Pressure Drilling process is distinguished by its hydraulics, kinematics of drilling and equipments. Here in this dissertation work, I have tried to explore managed pressure drilling process by rheology modeling, annular flow modeling and kinematics modeling. 6.3 Scope of the future work The Managed Pressure Drilling process is the newly developed technique. So there can be lot off research work for future prospects. Through the present dissertation work following point can be recommended for future work. Further research into the different parameters of managed pressure drilling is needed to see the exact effect that these parameters have on the pressure-gradient window. Different variations of managed pressure drilling also needed research work in challenging environment like HPHT and Depleted field. Through this dissertation work further study for calculating bottomhole pressure and hydraulics of MPD can be done. Further kinematics study of MPD can be done with the help of developed experimental setup. 79

94 Appendix A1. Preparation of drilling mud: Description of drilling mud contents: For 20 liter water Bentonite (15 ppb) = 850 gm Barite = 100 gm Soda ash (1 ppb) = 40 gm Caustic (0.5 ppb) = pallets A2. Drilling mud s properties: Density ( ): Density of Drilling mud = 9 ppg or = Kg/m 3 Ph value: Ph value of Drilling mud = 10 Viscosity ( ): Viscosity measurement through Quart funnel viscometer Quart funnel reading for Drilling mud (t) = 30.3 sec Quart funnel reading for water = 25 sec = (gm/cm 3 ) (t - 25) = ( ) = cp or = Pa.s Rheology Calculation: Plastic Viscosity (PV) = = = 3 cp 80

95 Yield Point (YP) = 300 PV = = 4.5 lbf/100 ft 2 Apparent Viscosity = = 10.5 / 2 = 5.25 cp Consistency factor (K) = 1.07 ( n ) = 1.07 ( ) = 0.39 lbf sec n /100 ft2 Gel strength = Max. Dial reading at 3 rpm = 3.5 lbf/100 ft 2 Flow behavior index (n) = 3.32 log ( ) = 3.32 log (10.5/7.5) = Yield Stress = (2 3 rpm) 6 rpm = (2 3.5) 4 = 3 lbf/100 ft 2 A3. Annular flow calculation power law fluid The annular flow modeling of power law fluid is quite different from Newtonian fluid flow. There is requirement of some calculation of effective diameter, hydraulic diameter, and power law functions like Y, Z and G. this study the calculation is for For n = and k =

96 Where D i = 0.10 m and D o = 0.35 m Y = 0.37n = Y = = 1 1. Z = G = The effective diameter is defined as follows: A4. Description of experimental setup: Length of the annular pipe = 1 m Diameter of the annulus pipe = m Diameter of the core pipe = m = m 82

97 A5: Dimensional analysis drilling parameters Pa m 3 /s Pa.s Drill string rotation = ω rad/s Kg/m 3 Drilling depth = d m Rate of penetration = r m/s Objective function Kick OBD (A5.1) MPD (A5.2) Kick UBD (A5.3) Kick Number of Parameters (m) = 7 Number of Fundamentals (n) = 3 Number of Dimensionless products (π) = 7 3 = 4,,, 0 Here, it is assume that rate of penetration, depth and density of the drilling fluid are strong functions for MPD, again let the repeating variables are d, r, and Δρ. Then dimensionless π s equations will be as follows. 83

98 Repeating variables = d, r, and Δρ Other variables = Δp, ΔQ, µ, ω π 1 = (d) a (r ) b (ρ) c Δp = (L ) a (L T -1 ) b (M L -3 ) c M L -1 T -2 π 2 = (d) a (r ) b (ρ) c Q = (L ) a (L T -1 ) b (M L -3 ) c L 3 T -1 π 3 = (d) a (r ) b (ρ) c µ = (L ) a (L T -1 ) b (M L -3 ) c M L -1 T -1 π 4 = (d) a (r ) b (ρ) c ω = (L ) a (L T -1 ) b (M L -3 ) c T -1 π 1 M 0 = c + 1 c = - 1 L 0 = a +b - 3 c - 1 a = 0 π 1 = T 0 = -b 2, b = -2 π 2 M 0 = c, c = 0 L 0 = a + b - 3 c + 3 a = - 2 π 2 = T 0 = -b - 1, b = -1 π 3 M 0 = c + 1, c = - 1 L 0 = a +b - 3 c - 1, a = - 1 π 3 = T 0 = -b 1, b = -1 π 4 M 0 = c, c = 0 L 0 = a + b - 3 c, a = 1 π 4 = T 0 = -b - 1, b = -1 84

99 A6 Experimental Setup for Kinematics study of Managed Pressure Drilling 85

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