Determination of Skin Burn Temperature Limits for Insulative Coatings Used for Personnel Protection
Workers often perform tasks on high temperature equipment and piping. As they move about this equipment they may have unintentional contact with the hot surfaces resulting in burns to the skin. Thermal insulation is generally installed on metallic equipment at 60°C (140°F) or higher for personnel protection (PP). Insulative coatings are an alternative to the use of traditional insulation for PP where strict heat retention is not required. Although the external surface of the insulative coating may heat up to temperatures greater than 60°C, it can have a threshold burn temperature that is higher than for the metal substrate because of the coating's lower thermal conductivity. This is a well known fact, but the perception of many plant personnel is that the coating surface must also be less than 60°C. This report presents work that validates the use of an insulative coating for PP using accepted instrumentation in accordance with ASTM C1055, C1057, and ISO 13732-1. Test variables included coating thickness, metal substrate temperature, ambient air temperature, surface roughness and hot vs. ambient coating application. In addition to determination of the burn thresholds, the results confirm that higher surface temperatures than 60°C are allowed for insulative coatings.
The Conduction of Heat To and Through the Skin and the Temperatures Attained Therein
A. R. Moxr, M.D., and F. C. Henriques, Jr., Ph.D.
A study of the reciprocal relationships of time and surface temperature with respect to the capacity of thermal exposures to destroy the epidermis of man were reported. This report concerns the pathogenesis and pathologic characteristics of cutaneous burns in relation to the duration and intensity of thermal exposure and to their susceptibility to organization, repair, and healing.
ASTM C1055 - Standard Guide for Heated System Surface Conditions that Produce Contact Burn Injuries
This guide has been developed to standardize the determination of acceptable surface operating conditions for heated systems. Current practice for this determination is widely varied. The intent of this guide is to tie together the existing practices into a consensus standard based upon scientific understanding of the thermal physics involved. Flexibility is retained within this guide for the designer, regulator, or consumer to establish specific burn hazard criteria. Most generally, the regulated criterion will be the length of time of contact exposure.
ASTM C1057 - Standard Practice for Determination of Skin Contact Temperature from Heated Surfaces . . .
This practice covers a procedure for evaluating the skin contact temperature for heated surfaces. Two complimentary procedures are presented. The first is a purely mathematical approximation that can be used during design or for worst case evaluation. The second method describes the thermesthesiometer, an instrument that analogues the human sensory mechanism and can be used only on operating systems.
OSHA interpretation letter dated August 19, 1998
John B. Miles, Jr. - Director, OSHA
. . . The personal protective equipment standard would apply to hot surfaces where the hazards have not been eliminated through engineering or administrative controls. This standard requires employers to assess the workplace to determine if hazards that require the use of PPE are present or are likely to be present. The employer must select and have affected employees use properly fitted PPE suitable for protection against these hazards, as well as provide employee training and conduct periodic inspections to assure procedures are being followed. Suitable thermal protection would be necessary to provide employees with thermal insulation from hazardous hot pipe surfaces.
Drilling Fluid and Health Risk Management
Drilling fluids are used extensively in the upstream oil and gas industry, and are critical to ensuring a safe and productive oil or gas well. During drilling, a large volume of drilling fluid is circulated in an open or semi-enclosed system, at elevated temperatures, with agitation, providing a significant potential for chemical exposure and subsequent health effects. When deciding on the type of drilling fluid system to use, operator well planners need to conduct comprehensive risk assessments of drilling fluid systems, considering health aspects in addition to environmental and safety aspects, and strike an appropriate balance between their potentially conflicting requirements. The results of these risk assessments need to be made available to all employers whose workers may become exposed to the drilling fluid system.
This document provides some general background on drilling fluids and the various categories of base fluids and additives currently in use. It outlines potential health hazards associated with these substances, looks at opportunities for human exposure presented by drilling operations, and introduces risk management methods and monitoring processes aimed at reducing the risk of harmful health effects. This guidance is evidence-based and aims to define and discuss best practices for reducing exposures and subsequent health effects through a risk-based management process. The document is designed to be of use to operator and drilling personnel, managers, Health, Safety and Environment managers, drilling fluid specialists, rig-site medical staff, and occupational health and hygiene professionals.
Effects of Drilling Fluid Exposure to Oil and Gas Workers Presented with Major Areas of Exposure and Exposure Indicators
E. Broni-Bediako and R. Amorin
Drilling fluid is any fluid which is circulated through a well in order to remove cuttings from a wellbore. They are used broadly in the oil and gas industry, on exploration rigs, and are critical to ensuring a safe and productive oil or gas well. During drilling, a large volume of fluids are circulated through the well and into open, partially enclosed or completely enclosed systems at elevated temperatures. When these drilling fluids are agitated during circulating process there is significant potential for chemical exposure to workers and subsequent health effects. This study seeks to identify major areas of drilling fluid exposure and health hazard associated with the use of drilling fluid. The study also presents some challenges in setting drilling fluid exposure standard which has always not been given the same attention or concern as effects and risk management of drilling fluid. Some exposure indicators are also presented.
Occupational Exposure Hazards Related To The Use Of Drilling Fluids Presented With Remedial Risk Management Guidelines.
Aud Nistov, Reagan Wallace James, et al.
The occupational exposure risk of chemicals to personnel during well construction operations is managed and controlled. The control of exposure of personnel to chemicals during well construction operations has not always been given the same focus as environmental issues. To some extent the reduction of environmental risks has also resulted in reduced health and safety risks. The containment of fluids for disposal, rather than immediate discharge may increase occupational exposure. It is important to conduct comprehensive risk assessments of drilling fluid systems that consider health, environmental and safety issues.
A significant quantity of the chemicals supplied to the well site are used during drilling operations. As a result, drilling operations give rise to the greatest occupational exposure to drilling fluids. In this paper the general background of drilling fluids and the various categories of base fluids and additives in use today are discussed. The paper examines trends in use, human exposure, best practices in fluid use, monitoring of health hazards and effects, and recommends some risk reduction measures.
HP/HT Challenges: Understanding and Managing Bottomhole-Circulating-Temperature Behavior in Horizontal High-Temperature Wells
While high-temperature (HT) wells have always presented drilling challenges, the recent activity increase in the Haynesville shale along the border of Texas and Louisiana presents an extreme environment for drilling equipment. Along with a high frequency of temperature-related measurement-while-drilling (MWD) and logging-while-drilling (LWD) failures, the profile and architecture of Haynesville wells have provided an opportunity to study and understand the thermal behavior of horizontal HT wells in general. Thereby, well-specific operational guidelines and planning considerations can be implemented to reduce the risk of downhole temperature- related failures.
Drilling fluid meets deep gas drilling challenges
Ron Bland, Greg Mullen (et al)
Developing deep shelf gas requires overcoming some formidable drilling challenges. Rigs capable of drilling to these depths are larger, more robust and more expensive. Penetration rates tend to be low, extending time on location and adding to drilling costs. The extreme pressures, temperatures and acid gas levels limit down-hole tool, material and fluid selection. These limitations will be so severe toward bottom that MWD/LWD tools will be unusable, meaning downhole annular pressure measurements used for pressure management will be unavailable. This places additional demands on the drilling fluid and temperature/hydraulic models as they become our best, if not our only, source for down-hole pressure information. These models are based on surface inputs and laboratory measured fluid properties under downhole conditions. During the planning stage for several potential record depth deep gas wells currently drilling, not only did this information not exist, laboratory equipment capable of operation at the required temperatures and pressures didn’t exist.
Wellbore Stability and Integrity Contributors Revealed by Thermal Modeling and Fluid Analysis
Robert Mitchell, Ronald Sweatman
Wellbore stability and integrity issues may be explained by combining thermal modeling and drilling fluid analysis to reveal changes in well conditions that are typically unknown during drilling and completion operations. These changes in fluid temperature, pressure, and density (FTPD) can have a significant effect on wellbore stability and integrity. This paper describes thermal modeling and drilling fluid analysis of non-circulated and circulated wellbores to identify non-traditional sources of instability and poor integrity. For example, in non-circulated wells that are static for many hours, differences between induced and natural temperatures combined with pressure conditions may lead to severe conversions from an over-balanced to under-balanced state resulting in pore fluid influx, cross-flow, collapse, and other severe wellbore failures. When circulating long, deep holes, modeling may show FTPD-related issues that aren't revealed by other means. Over-balanced and/or stable rock conditions may actually change to under-balanced pressure and/or unstable rock conditions. The consequences include kicks, solids beds from formation breakouts, flow after cementing, stuck pipe by hole collapse, and salt creep acceleration.
Drilling Operations in HP/HT Environment
Izhar Ahmad, Oleg Akimov, et al
The development of oil and gas assets is becoming more complex, with reserves being found in more challenging environments. Wells are being drilled to greater depths and in areas where the temperature gradient is higher. This has led to requirement for downhole equipment that can withstand temperature in excess of 302° F (150°C) and pressures in excess of 30,000 psi. Directional wells require measurement while drilling (MWD) and drilling systems that are reliable in these challenging environments. The problem with pressure is solved by seals to isolate equipment from the wellbore fluid and variations in materials and dimensions to withstand the pressure. The greater challenge is with electronic components in a high-temperature environment. Conventional drilling assemblies are generally rated to 302°F (150°C), which is far below the rating required for a high-temperature MWD and rotary steerable systems (RSS). New techniques were required in the design of MWD and RSS tools for high-temperature wells. This paper covers the work of one service company in the development of high-temperature drilling equipment that can be used in environments up to 350°F (175°C) and at pressures of 30,000 psi.The paper will describe the development of a new system that included an MWD system and an RSS capable of drilling wells at 350°F (175°C) and up to 30,000 psi. The authors will use detailed case histories to show how this system was used to provide a true step-change in performance in this challenging environment.
High-Pressure High-Temperature Fluids Modeling: One of the Crucial Keys to Ultra-Deep Gas Drilling
Amir Hosein Seddighin, Roxann Krishingee et al
Ultra deep gas reservoirs is becoming a common target in drilling for gas. Unfortunately most of these reservoirs are highly pressured and extremely hot and have posed a great challenge for the oil and gas industry. Due to the large amounts of hydrocarbon reserves in these areas and growing demands of global energy, operators are investing more time and money into these types of reservoirs.
Challenges such as lack of down hole measurement tools in higher temperature and pressure and drilling fluids behavior under HPHT conditions may result in the wellbore stability issues and well control difficulties which put the safety of the personnel and operations in jeopardy.
Proper drilling fluids selection and applying the right temperature and hydraulics modeling plays a crucial role in the success of these operations, and help to reduce/mitigate the risk of the operations and non productive time (NPT). This includes: ECD managements, Surge/Swab analysis, Bit hydraulics optimization, fluid compressibility analysis and all the other hydraulics and temperature factors affecting the operations.
This paper will take a look at successful applied modeling and fluids management methods based on proper data gathering and utilizing the best practices results in safe and successful drilling in such hostile environments.
Wellbore Heat Transmission
H.J. Ramey Jr.
As fluids move through a wellbore, there is transfer of heat between fluids and the earth due to the difference between fluid and geothermal temperatures. This type of heat transmission is involved in drilling and in all producing operations. In certain cases, quantitative knowledge of wellbore heat transmission is very important. This paper presents an approximate solution to the wellbore heat-transmission problem involved in injection of hot or cold fluids. The solution permits estimation of the temperature of fluids, tubing and casing as a function of depth and lime. The result is expressed in simple algebraic form suitable for slide-rule calculation. The solution assumes that heat transfer in the wellbore is steady-state, while heat transfer to the earth will be unsteady radial conduction. Allowance is made for heat resistances in the wellbore. The method used may be applied to derivation of other heat problems such as flow through multiple strings in a wellbore. Comparisons of computed and field results are presented to establish the usefulness of the solution.
Calculation of Formation Temperature Disturbances Caused by Mud Circulation
M.J. Edwardson, H.M. Girner, et al
Quantitative interpretation of electric logs requires knowledge of formation temperature. In this paper, methods are developed for computing changes in formation temperature caused by circulation of mud during drilling operations. The basis of the method is the mathematical solution of the differential equation of heat conduction. The solution of this equation is presented in a series of graphs. These graphs are used to determine formation temperature disturbance at various radii for arbitrary mud circulation histories. Example comparisons with field results show reasonable agreement. It is concluded that, in general, the temperature disturbances caused by circulating mud are small beyond 10 ft from the wellbore but are quite significant near the wellbore.
A Method for Calculating Circulating Temperatures
A.F. Tragesser, Paul B. Crawford, et al
A method has been developed to calculate wellbore temperatures during Mud circulation and the actual cementing operation to aid in the design of cement slurries. The method agrees within 10F with previously measured values. The calculation technique provides temperatures, as functions of time, at varying depths in both the casing and annulus. The technique also provides this information if a relatively cool cement slurry is pumped into the well immediately following circulation of hot mud. Circulating bottom-hole temperatures of brine and a bentonite mud were measured.
Additional Thermal Data for Porous Rocks--Thermal Expansion and Heat of Reaction
W.H. Somerton & M.A. Selim
Thermal expansions and beats of reaction of three typical sandstones were measured in the temperature range of 250° to 1,000°C. The significance of these data in subsurface heat-transfer calculations is discussed.
Linear thermal expansions were measured both parallel and perpendicular to the bedding planes. Volume expansions are reported as the perpendicular expansion plus two times the parallel expansion. Expansion behavior of the sandstones was found to be controlled by the expansion characteristics of the quartz content. Differential expansion of the quartz grains and other minerals included in the sandstones caused permanent de formation of the heated samples after they were cooled to room temperature. Structural damage resulting from heating is probably an important cause of the reduction of thermal conductivity of heated samples.
Measurements of heats of reaction were based on the known heat required for a-ß quartz inversion. Thermal reactions, which probably include dehydroxylation of clay minerals and decomposition of carbonate minerals contained within the samples, were found to require more than one-fourth of the amount of heat necessary to raise the temperature of the rock alone. In shales and limestones, the reaction heat could be substantially greater than that required from specific heat considerations alone.
The Heat Efficiency of Thermal Recovery Processes
For any rate of heat injection into a reservoir, the fraction of the heat remaining in it is independent of the recovery process, be it steam, hot water,or combustion.
Most of the information available on the heat efficiency of hot fluid injection processes, both water and steam, has been obtained from calculated temperature distributions in the pay zone and adjacent formations. The usual approach has been to write the heat balance equations in terms of the temperatures, and then to introduce whatever simplifications are necessary to help obtain an analytical or a numerical solution.
Calculation of Circulating Mud Temperatures
Charles S. Holmes & Samuel C. Swift
The mud circulation temperatures obtained by this simple analytical method can be used to predict logged bottom-hole mud temperatures, they can be used also as initial temperatures in predicting mud column temperature buildup after circulation is stopped.
A thorough knowledge of the mud temperature profiles developed during well drilling and profiles developed during well drilling and subsequent periods of well logging is helpful. Complete temperature profiles for the fluid in both the pipe and the annulus may aid in revealing information about downhole conditions. Accurate prediction of maximum temperatures to be encountered prediction of maximum temperatures to be encountered during drilling allows for precise mud selection and preparation. The mud profiles also give indication of formation characteristics of the rock contacted during drilling. The object of this investigation was to develop an analytical mathematical model that could be used to predict the mud temperature in the drill pipe and annulus during drilling at any depth in the well.
Temperature Distribution in a Circulating Drilling Fluid
A technique for calculating drilling temperature as a function of position and time shows that circulation lowers considerably the position and time shows that circulation lowers considerably the temperatures of both the bottom-hole fluid and the rock and that the maximum circulating fluid temperature occurs a fourth to a third of the way up the annulus.
Numerical Computation of Temperature Distribution in a Wellbore While Drilling
B. Corre, R. Eymard, et al
There is a need for determining temperature profiles in and around a wellbore during drilling profiles in and around a wellbore during drilling phases. A computer model has been developed. phases. A computer model has been developed. To take into account an evolutive geometry at the level of the tool, an adaptive grid refinement was used; it ensures a better physical representation. The unknowns are the temperatures at the center of each grid block and of each interface. The non-linear equations are discretised in finite-difference fully implicit scheme and solved by the Newton's method.
Complex rheological models are used to improve fluid mechanics' representation. At any location and time, the flow nature is determines and then pressure losses and convective heat transfer coefficients are calculated. Energy source terms are function of location and time.
Any flow history and drilling sequence nay be simulated. Typical drilling sequences are presented. This model has been used in order to design mud and drilling programs to ensure a better hole stability.
Determining Circulating Fluid Temperature in Drilling, Workover, and Well Control Operations
C.S. Kabir, A.R. Hasan, et al
Estimation of fluid temperature in both flow conduits (drillpipe or tubing and the annulus) is required to ascertain the fluid density and viscosity, and in turn to calculate the pressure-drop or the maximum allowable pumping rate for a number of operations. These operations include drilling, workover, and well control. During circulation, the inlet fluid temperature at the drillpipe/tubing is generally much lower than the bottomhole formation temperature. Consequently, in flowing down the drillpipe/tubing and up the annulus, the fluid continues to gain heat, thereby precipitating an unsteady-state heat transfer problem. The heat transfer rate for the fluid in the annulus depends upon the formation temperature from which it gains heat, as well as on the drillpipe/tubing fluid temperature to which it loses heat. Thus, the fluid temperature estimation becomes critical for high-temperature or geothermal reservoirs where significant heat exchange occurs or when fluid properties are temperature sensitive, such as for a non-Newtonian fluid.
In this work, we present an analytical model for the flowing fluid temperature in the drillpipe/tubing and in the annulus as a function of well depth and circulation time. The model is based on an energy balance between the formation and the fluid in the drillpipe/tubing and annulus.
Practical Advantages of Mud Cooling Systems for Drilling
Vincent Maury & Alain Guenot
Field cases studies of borehole stability showed that some failures were due to thermal effects, heating the upper part of open holes by mud circulation or reheating of the bottomhole when mud circulation cooling is stopped for instance.
A complete analysis of the thermal regime in boreholes was performed and as a consequence, cooling of mud appeared as a mean to mitigate these effects.
Series of tests were then carried out to check the practicality of installing such mud cooling systems. Many other advantages then appeared: decrease of the temperature of the borehole allowing better operation of the logging tools, better control of the mud rheology with less additives, extended use of MWD devices. But the most significant advantage is for the oil based suds which can be maintained at surface below their flash point, improving the safety of operations.
The paper recalls and summarizes the results of observations, measurements and studies performed to determine the feasibility of such systems. Operational results are given for several field cases with emphasis on safety. The use of these very simple devices, which have been field proven on typical and 150C wells, is now contemplated for future HP-HT wells,
Innovative Drilling Fluid Design and Rigorous Pre-Well Planning Enable Success in an Extreme HTHP Well
D.J. Oakley, K. Morton, et al
Drilling in the Qiongdongnan Basin, offshore China's Hainan Island Province,has often resulted in failure to reach desired objectives. Bottom hole temperatures up to 475°F, and pressures requiring mud weights up to 19.5lbm/gal equivalent, place severe limitations on the performance of drilling fluids and often contribute in failure to reach the desired drilling objectives.
Well Yacheng 21-1-4 was drilled in this basin with the COSDC semi-submersible rig Nanhai V and was spudded on 27th November 1998. TD of5,250 meters was attained on 20th May 1999 where the bottom hole static temperature was 414°F and the pore pressure was 18.5 lbm/gal equivalent. Logs were run to bottom without incident with no significant drilling fluid related problems and the primary drilling objectives achieved. The success is attributed to innovative, fit-for-purpose drilling fluids and rigorous pre-well planning over a 2-year period prior to the well commencing.
The paper describes the holistic approach to drilling fluid engineering for extreme well conditions. The development of innovative drilling fluids specific to these well conditions, and the rigorous laboratory testing necessary to generate detailed engineering guidelines, are described. Large-scale abrasion and pressure tests were also conducted. Modifications made to the rig design facilitated the management of drilling fluid properties at high density with high flow line temperatures. A portable drilling fluids laboratory, staffed with trained technicians, was installed on the rig to continually pilot test drilling fluid samples and treatments under simulated down-hole conditions. The importance of good communications and global technical support networks proved invaluable during the pre-well planning and for the execution phase of extreme high temperature and high pressure wells drilling.
Chemical and Thermal Effects on Wellbore Stability of Shale Formations
M. Yu, G. Chen, et al
A new three-dimensional wellbore stability model is presented that takes into account thermal stresses and the flux of both water and solutes from drilling fluids (muds) into and out of shale formations. Mechanical stresses around a wellbore placed at any arbitrary orientation in a 3-dimensional stress field are coupled with changes in temperature and pore pressure due to water and solute fluxes. The radial and azimuthal variation in the stress distribution and the "failure index" are computed to check for wellbore failure. This model accounts for the hindered diffusion of solutes as well as the osmotically driven flow of water into the shale. The model for the first time allows a user to study the role of solute properties on wellbore stability.
Results from the model show that a maxima or minima in pore pressure can be obtained within a shale. This leads to wellbore failure not always at the wellbore wall as is most commonly assumed but to failure at some distance inside the shale. Since the fluxes of water and solute, and temperature, are time dependent, a clearly time dependent wellbore failure is observed. The time to wellbore failure is shown to be related to the rate of solute and water invasion. Comparisons with experiments conducted with a variety of solutes on different shales show excellent agreement with model results.
Increasing Effective Fracture Gradients by Managing Wellbore Temperatures
Manuel Eduardo Gonzalez, James Benjamin Bloys, et al
Thermal effects on wellbore stresses can have a significant impact on effective fracture gradients. Changes in wellbore temperatures caused by various drilling operations provide for these thermal effects. For example, circulation on bottom usually results in lower bottom hole temperatures than the static geothermal temperature. This cooling effect reduces the wellbore stresses resulting in lower effective fracture gradients. Minimizing the cooling effect by increasing wellbore temperatures can increase effective fracture gradients and the corresponding pore pressure/fracture gradient margin avoiding costly lost circulation and additional unnecessary casing points.
This paper presents results from leak-off tests taken at various temperatures which demonstrate the thermal effect on formation stress. This paper also examines the effects of operational factors on wellbore temperatures to minimize the cooling effect and/or increase effective fracture gradients. Software developed for thermal simulation of various drilling operations was used to perform the analysis.
HPHT Drilling Fluid Challenges
Ronald G. Bland, Gregory Alan Mullen, et al
Accurate knowledge of drilling fluid behavior under actual conditions is required to maximize operational efficiency and to minimize cost and drilling fluid related risks on extreme high-pressure / high-temperature (HP/HT) wells.
This paper identifies and discusses the major HP/HT drilling fluid challenges, recent innovations in fluid viscosity measurements under HP/HT conditions, drilling fluid designs stable to extreme HP/HT conditions, and other considerations in HP/HT drilling.
Drilling Wells With Narrow Operating Windows Applying the MPD Constant Bottom Hole Pressure Technology—How Much the Temperature and Pressure Affects the Operation's Design
Maurizio Antonio Arnone & Paco Vieira
Narrow pore / fracture pressure gradient margins (operating window) is translated as a real drilling hazard scenario, where a slight change in the bottom hole pressure conditions can lead to an increase the Non Productive Time (NPT) due to the time spent in solve a possible fluid losses and/or gas kick situation, or even worst, dealing with occurrence of blowouts. In specific and non rare cases, deep formations with small gap between pore and fracture pressure are un-drillable with conventional drilling practices because the frictional losses pressure (difference between the dynamic and static pressure) is greater than the existent operating window. Constant Bottom Hole Pressure (CBHP), one of a number of variants of Managed Pressure Drilling (MPD) enables "walking the line?? between pore and fracture pressure gradient. The objective is to drill with a fluid that bottom hole pressure is maintained constant, whether the fluid column is static or circulating. The loss of annulus flowing pressure when not circulating is counteracted by applied surface backpressure. The basic of Constant Bottom Hole Pressure (CBHP) methodology is to accurately determine the change in bottom hole pressure caused by dynamic effects and compensate with an equal change in annular wellhead pressure. The bottom hole temperature as well as the hydrostatic head of the drilling fluid column increases with the well depth and both parameters have opposing effect in the resultant static and dynamic equivalent density. An increase in the hydrostatic and dynamic pressures increases the equivalent fluid density due to compression but an increase in the temperature causes a reduction in the equivalent fluid density due to thermal expansion. Conventionally, these parameters considered together results in a cancellation of effects. In the reality, this assumption should be carefully reviewed. The effect of temperature in annular pressures, on a MPD CBHP operation through narrow operating windows, can not be ignored due to the potential impact. Precise estimation of static and dynamic equivalent fluid densities is of essential importance for a successful MPD CBHP operation through narrow operating windows.
Modeling Thermal Effects on Wellbore Stability
Duc Anh Nguyen & Stefan Z. Miska
Field evidence indicates that the thermal regime in wellbore considerably affects the wellbore stability in directional and horizontal wells. However, the temperature effects have not been investigated thoroughly in existing literature, and the effects of drilling fluid flow and various heat sources on the behavior of formation temperature profiles during different operations are often neglected. The affected formation temperature in the vicinity of the wellbore could result in different formation rock behaviors and consequent wellbore stability problems. This study is conducted to examine the effect of temperature on the stability of the near wellbore region, taking into account the heat transfer between formation and flowing drilling fluid with the consideration of mechanical friction and associated heat sources.
A new model is proposed that is applicable to directional and horizontal wells. The model incorporates thermal effects due to the drag forces created from the contacts between drillpipe and casing/formation during drilling and tripping operations. It is then utilized in a number of configurations of directional wells to study temperature profiles behaviors and their effects on wellbore stability. It is observed that the drilling fluid temperature is noticeably under-predicted by existing literature, and in some cases it can easily exceed the geothermal formation temperature if mechanical friction is taken into account. The formation temperature profile near the borehole region is also found to be considerably affected when wellbore heat transfer is considered, as opposed to the constant wall temperature approach in existing literature. These differences alternate the temperature induced stresses and consequently change the mud weight window for wellbore stability prediction.
Understanding and Managing Bottom Hole Circulating Temperature Behavior in Horizontal HT Wells - A Case Study Based on Haynesville Horizontal Wells
Donald Keith Trichel & John A. Fabian
While HT wells have always presented drilling challenges, the recent activity increase in the Haynesville shale located across the border between Texas and Louisiana presents a unique and extreme environment for drilling equipment. Not only is there a high frequency of temperature related MWD/LWD failures, the profile and architecture of Haynesville wells has provided an opportunity to study and better understand the thermal behavior of horizontal HT wells in general. Through improved understanding, well specific operational guidelines and planning considerations can be implemented to ultimately reduce the risk of downhole temperature related failures.
This paper discusses a Haynesville horizontal well case study where temperature simulations were compared and calibrated to actual downhole temperature measurements taken while drilling. After calibration of the model was established, a series of simulations were conducted to investigate the sensitivity of bottom hole circulating temperature to choices of drilling systems, fluids systems, mud cooling systems and well design.
Meeting the Ultrahigh-Temperature/Ultrahigh-Pressure Fluid Challenge
Guido De Stefano, Emanuel Stamatakis, et al
Ultrahigh-temperature/ultrahigh-pressure (uHT/uHP) conditions have a different definition, depending on the region, the operator, and the service company. In this paper, the definition used for uHT/uHP fluid performance is that the fluid be able to perform above 500°F and 30,000 psi. This paper describes the development of innovative drilling fluids that are specific to these well conditions. When bottomhole temperatures exceed 400°F, the design and engineering of drilling fluids can be challenging. Drilling fluids that destabilize can cause a variety of fluid-control problems that could lead to drilling and completion issues. With invert-emulsion fluids, the major challenges encountered with these conditions are related to the thermal degradation of the emulsifier and wetting package that can lead to gelation and syneresis. Another challenge is fluid loss that is related to the emulsion stability and to the degradation of the fluid-loss-control additives. Finally, efficient control of the rheological properties--critical to the success of any well--also can be challenging when effects from emulsion instability, filtration-control degradation, and rheology-control-additive degradation are coupled with increases in drilled solids, rapidly leading to rheological instability. This can manifest itself as high-fluctuating rheologies and gelation or the loss of rheological properties that can give rise to sag of weight material, both potentially leading to associated well-control problems. The paper describes the development of the new fluid system designed for such uHT/uHP environments (highlighting the chemical differences) and compares the test data of the system with more-conventional high-temperature/high-pressure (HT/HP) invert-emulsion fluids. Data are presented that show the stability and performance of the new fluid with extended exposure to temperature > 500°F, demonstrating a tolerance to various contaminations and showing the rheological behavior and stability to 600°F and 40,000 psi.
Study on the Volumetric Behavior of Base Oils, Brines, and Drilling Fluids Under Extreme Temperatures and Pressures
Mario Zamora, Sanjit Roy, et al
Drilling-fluid densities vary significantly over wide ranges of temperature and pressure, a concern that is particularly critical in deepwater, Arctic, and high-pressure/high-temperature. The variations can affect well integrity, well design, regulatory compliance, and drilling efficiency. Drilling-fluid densities depend on the compressibility and thermal expansion of the fluids(liquids) and solids used in their formulation. Suitable pressure/volume/temperature (PVT) correlations for these fluids previously have been fairly inaccessible, primarily because of continually changing base fluid sand blends, and the lack of readily available test equipment. This study was conducted to measure the volumetric behavior under extreme temperatures and pressures of a broad range of the oils, synthetics, and brines currently used in industry to prepare oil-, synthetic-, and water-based drilling fluids. It follows a recent study that successfully qualified the commercially available test equipment. For the most part, tests for this study were run at temperatures from 36 to 600°F and pressures from atmospheric to 30,000 psi,ranges that generally exceed those provided in other published studies.Correlation coefficients are provided for reference and to demonstrate their use in a compositional, material-balance model to accurately predict drilling-fluid density as a function of temperature and pressure. Tests run on field drilling fluids are included to demonstrate how these data can be used in procedures and software to predict equivalent static density and hydrostatic pressure during drilling operations.
Handbook of Best Practices for Geothermal Drilling
John Finger and Doug Blankenship
This Handbook is a description of the complex process that comprises drilling a geothermal well. The focus of the detailed Chapters covering various aspects of the process (casing design, cementing, logging and instrumentation, etc) is on techniques and hardware that have proven successful in geothermal reservoirs around the world. The Handbook will eventually be linked to the Geothermal Implementing Agreement (GIA) web site, with the hope and expectation that it can be continually updated as new methods are demonstrated or proven.
HPHT 101: What Every Engineer or Geoscientist Should Know about High Pressure High Temperature Wells
Arash Shadravan & Mahmood Amani
The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells.
Multiwell Thermal Interaction: Field Data Validation Of Transient Model for Closely Spaced Wells
Albert R. McSpadden, Alex Gunn, et al
Wellbore temperature logs and associated field history data from an HPHT condensate North Sea platform are presented which validate the accuracy of a transient model of multiwell thermal interaction. The model is an updated version of previous work which simulates transient thermal interaction or "cross-heating?? between closely spaced wells of a template. Multiwell thermal interaction alters final wellbore temperatures as well as formation temperatures in the inter-well zone and also further out from the well template. The multiwell thermal model is shown to converge closely in very characteristic fashion to two different logged and measured temperature profiles over a vertical depth range of 3000 ft.
The empirical data including field history represents a unique opportunity to study and understand this important topic. Prior to this current work, industry discussion of multiwell thermal interaction or "cross-heating?? has been largely anecdotal. Model validation against field data is necessary to achieve a full understanding of the physical system and to provide confidence in the predictive capability.
Modeling of wellbore and formation temperatures for closely spaced wells has not been widely examined in the industry literature. The current work presents an improved methodology based on standard industry techniques. The method employs standard industry thermal-hydraulic modeling software and a fully transient finite-difference time-domain (FDTD) model in a loosely-coupled, iterative analysis. The iteration scheme is achieved by coupling of the standard analytical solution for the isolated single-well temperature scenario with the solution in the formation for the cross-heating scenario.
Analytical Model To Predict the Effect of Pipe Friction on Downhole Fluid Temperatures
Aniket Kumar (Halliburton) | Robello Samuel
The advent of deviated, horizontal, and extended-reach drilling has led to increased frictional forces acting between the drill string and the wellbore wall. Wellbore mechanical friction attributable to pipe rotation or to torque and drag plays a significant role in drilling operations and is considered to influence the downhole temperatures of the drilling fluid. An analytical model to estimate the influence of this pipe friction will help in providing a better physical insight to understand the downhole borehole conditions as well as in realizing the effect of its underlying parameters. This study aims to develop a simple mathematical model to analyze the heat generated downhole from the drill string and borehole contact and then predict its influence on the temperature of the drilling fluid during a drilling operation at any depth inthe well. The model presents a steady-state solution for heat transfer between the drill string and the fluids in the drill pipe and annulus, as well as for heat transfer between the annular fluid and the formation. The heat generated from friction has been modeled by use of the torque acting on the drill string as a result of contact forces. A linear temperature gradient for the formation and a constant borehole-wall temperature has been assumed to simplify the model. Frictional pressure losses in the drill pipe, in the annulus, and across the bit have been incorporated in the model because they contribute to the heat generated downhole. The temperature profile of the drilling fluid has been estimated both in the annulus and inside the drill pipe for the entire well profile under consideration.
This paper will present the derivations of the generalized heat transfer model and its validation by use of two practical drilling scenarios.
Analytical Downhole Temperature Model for Coiled Tubing Operations
Silviu Livescu & Xiaowei Wang
The detailed modeling of temperature and friction for coiled tubing operations is especially important in extended-reach wells. Although the fluid flow through the coiled tubing and annulus, downhole temperature, and the coiled tubing mechanical friction inside the well are crucial during coiled tubing operations, a mathematical model that captures all these effects does not currently exist.
In a separate study, we propose a new temperature-dependent coefficient of friction relationship, based on an extensive in-house experimental data set. In this study we implement this relationship in a thermal well flow model. The model includes transient single-phase mass, momentum, and energy balance equations for the coiled tubing and annulus. Heat exchange between tubing and annulus and between annulus and formation as well as heat generated by coiled tubing mechanical friction while sliding inside the well are included in the model. Frictional pressure drops due to the fluid flowing downwards through the tubing and upwards through the annulus are also included in the momentum equations. The formation temperature is assumed to be geothermal. Although the model is aimed specifically at coiled tubing operations, it can easily be extended to multiphase flow and other applications where wellbore flow in tubing and annulus is important.
Temperature-Induced Uncertainty of the Effective Fracture Pressures: Assessment and Control
Koray Kinik, Andrew Krzysztof, et al
The constant bottom-hole pressure (CBHP) method of managed pressure drilling (MPD) maintains wellbore pressure above the wellbore stability or pore pressure and below the fracture pressure. It is common practice to perform frequent dynamic formation integrity/leakoff tests (FIT/LOT) to measure the fracture pressure. Several authors addressed the uncertainty in the measured value of the fracture pressure caused by mud compressibility and thixotropy. Moreover, field evidence indicates considerable variations in the effective fracture pressures resulting from varying wellbore temperatures.
This paper presents a mathematical model, validated with field data, to estimate the effective fracture pressure (EFP) from the leakoff test data. The model accounts for the effect of mud compressibility and thixotropy, and considers the effect of transient wellbore temperatures on the geomechanical rock stresses. The study also presents application of quantitative risk assessment (QRA) to represent the probability density distribution of EFP associated with the uncertainties in the input paramaters. The method was demonstrated with two examples from the Gulf of Mexico. The study shows that the operational parameter–“pumps off” time, and two formation properties-Young’s modulus of elasticity (E) and thermal expansion coefficient (αT) contribute most to the uncertainty in EFP. Moreover, a log-normal distribution of the EFP indicated a strong effect of temperature variation. It is also concluded that the uncertainty resulting from the temperature effect could be minimized by conducting the test after a characteristic 60-minutes pumps-off period.
Temperature model provides information for well control
Eirik Karstad, Bernt S. Aadnøy
The aim of this article is to show how to derive exact temperature information from a well during drilling and circulating operations so that more-accurate information can be provided to drillers and engineers during well-control situations.
This article presents a field case demonstrating the applications of the model. The derived model is an important tool for interpreting mud ballooning effects so that actual bottom-hole pressures (BHP) can be more exactly determined.
Development and Testing of Insulated Drillpipe
J.T. Finger, A.T. Champness, et al
This article describes the theoretical background, laboratory testing, and field testing of IDP, including structural and thermal laboratory testing procedures and results. We also give results for a field test in a geothermal well in which circulating temperatures in IDP are compared with those in conventional drillpipe (CDP) at different flow rates. A brief description of the software used to model wellbore temperature and to calculate sensitivity in IDP design differences is included, along with a comparison of calculated and measured wellbore temperatures in the field test. There is also analysis of mixed (IDP and CDP) drillstrings and discussion of where IDP should be placed in a mixed string.
Development and Application of Insulated Drill Pipe for High Temperature - High Pressure Drilling
J.T. Finger, A.T. Champness, et al
Extremely high temperatures (>400 °F), exceptionally high pressures (>15,000 psi), exceedingly hard rock, and highly corrosive gases all combine to create a very hostile environment for well drilling and completion activities in search of deep gas resources. These conditions can lead to material and electronic failures, increased wear on equipment, and increased technical and safety risk due to an inability to monitor downhole conditions. High downhole temperatures historically have either driven the cost of reaching deep gas reservoirs to a level that makes their development uneconomic or have prevented access altogether through equipment failure.
One approach to dealing with these issues is simply to control the temperature of the downhole environment so that existing drilling technology can more easily survive. The application of insulation to drill pipe could provide a means to deliver a much cooler drilling fluid to the bottomhole assembly, allowing these components to successfully function in a more favorable environment.
Critical Requirements for Successful Fluid Engineering in HPHT Wells: Modeling Tools, Design Procedures & Bottom Hole Pressure Management in the Field
Erhu Gao, Odin Estensen, et al
This paper presents developments in the management of drilling fluids for use in high-pressure, high-temperature (HPHT) wells, especially a process that includes both a methodology for the management of bottom hole mud pressure and the use of modeling software that enables it, The developments have contributed to the success of four HPHT wells in the UKCS Central Graben. This paper discusses three essential elements for successful fluid engineering during HPHT drilling operations.
- an accurate hydraulics program coupled with a temperature simulator
- procedures for design and planning
- bottom-hole pressure management in the field
Accurate Estimation of Equivalent Circulating Density During High Pressure High Temperature (HPHT) Drilling Operations
E. Ataga, Joel Ogbonna, et al
Error in equivalent circulating density estimation can be disastrous because of the narrow margin between pore and fracture pressure in HPHT wells. High temperature conditions cause the fluid in the wellbore to expand, while high pressure conditions in deep wells cause fluid compression. Failure to take these two opposing effects into account can lead to errors in the estimation of bottom-hole pressure on the magnitude of hundreds of psi.
This study involves the development of a simulator called HPHT-Density Simulator to simulate the wellbore(drillpipe and annulus) during circulation as well as the temperature and pressure profiles of a wellbore during circulation.
A Bingham plastic model was incorporated into a simulator called HPHT-density Simulator which was developed using Visual Basic to simulate the wellbore during circulation. The developed HPHT-density Simulator program interface is executed with a series of user forms,which will accept data pertaining to the wellbore, drilling fluid and formation parameters and return the temperature profiles in the wellbore and formation, pressure losses in the wellbore and ECD of the circulating fluid. The user can navigate between forms and input data at leisure using the "back?? and "next?? input bottons. Once values of all the necessary parameters have been entered into the program, the results are displayed on a "results?? forms.
The successful simulation of HPHT-Density Simulator shows a significant difference in the equivalent circulating density and bottom hole pressure profile for fluid circulation parameters of a Niger Delta well when the rheological properties were assumed to be constant as compared with when temperature-pressure varied. This can be adapted to drilling operations and thereby preventing downtime arising from kicks, blow-outs, lost circulation and formation damage due to wrong estimation of equivalent circulating density while drilling within narrow margin between pore and fracture pressure in HPHT wells.
Thermal Modeling of Drilling into Steam Chambers
Tyler James Hallman, Ron R. MacDonald, et al
Steam assisted gravity drainage (SAGD) is an oil recovery technique utilized for the production of bitumen. Two horizontal wells are used; low pressure superheated steam is injected into the upper well thereby reducing the insitu oil viscosity and mobilizing the fluid which is produced from a lower well. On occasion wells need to be drilled into or close to existing steam chambers associated with the SAGD wells. When drilling such wells the drilling fluid temperature may become excessively high, endangering personnel at surface, as well as exceeding the borehole stability, bottom hole assembly and/or drilling fluid temperature limits. A thermodynamic model of the drilling circulating process was created to predict the wellbore, mud return and formation temperatures. The model may be used to outline drilling procedures and enable wells penetrating or proximal to the steam chamber to be drilled safely.
The transient thermodynamic model was created with Landmark's WellCatTM and calibrated by matching predicted drilling fluid temperatures with actual drilling data obtained during the drilling of several cold wells. The calibrated model was used to predict the formation temperature of several hot wells for which drilling data was available. The model was also used to investigate the drilling fluid and wellbore temperatures during the drilling a generic well. This model may be applied for planning the drilling of future hot SAGD wells to ensure the drilling fluid temperatures are not prohibitively high, to calculate necessary cooling capacity at surface and delineate trip speeds/circulation rates necessary to avoid high temperature fluid being circulated to surface.
For instances in which the formation temperature was known the mud return temperature could be matched to within ±1°C. For the cases in which the formation temperature was being estimated by matching the predicted mud return temperature to the actual drilling data the formation temperature was predicted to approximately ±20°C. Formation temperatures of the wells reviewed range between 7° and 200°C. The generic drilling scenarios which were modeled demonstrate that, depending on the formation temperature and the well depth, it is possible for the mud to return to surface at temperatures approaching and potentially exceeding 100°C resulting in the water component of the mud flashing to steam. When entering a hot wellbore, tripping in slowly as well as circulating during the trip may be required to cool the wellbore and avoid returning excessively high temperature mud to surface.
A small number of SAGD wells have been drilled into steam chambers. The model allows this limited experience to be expanded in a controlled manner. The model may be used for planning of future drilling operations by predicting mud temperatures in a variety of drilling scenarios especially with regard to safety concerns. In addition, the need for employment of mud coolers or specific trip procedures can be evaluated. The approximate accuracy of the simulation software employed is also demonstrated.
Frontier Geothermal Drilling Operations Succeed at 500°C BHST
Saito Seiji & Sumio Sakuma
The Japanese government-funded geothermal exploration Well WD-1A reached 3729 m at total depth, where the bottomhole static temperature is more than 500°C. A trajectory correction run was carried out with a positive displacement motor and measurement while drilling tool where the formation temperature is greater than 350°C. The combination of large surface mud containers and sufficient mud cooling equipment were used to cool return mud from the well. A top drive system was used to cool the bottomhole assembly while running each drillpipe stand in the hole. A borehole dynamic temperature experiment and drill bit tests were carried out in this well.
Simulation of Time-Dependent Wellbore Stability in Shales Using A Coupled Mechanical-Thermal-Physico-Chemical Model
R. Freij-Ayoub, C.P. Tan, et al
The interaction of the drilling fluid with the formation rock is a key factor that determines the time-dependent stability of wellbores in shale formations. The analysis of wellbore stability in shales requires modelling of various coupled processes that are dependent on the relative properties of the drilling fluid and formation pore fluid. These processes include mud pressure penetration, thermal diffusion, chemical potential mechanism and poroelasticity. These processes affect the formation pore pressure, stresses and deformation. The critical drilling fluid properties include mud type, weight, temperature, and type and concentration of free ions.
Numerical simulations are conducted to model the effect of coupling the various processes on wellbore stability in shales. The simulations used a finite element code SHALESTAB that solves the specific coupled differential equations which describe these processes. It is found that the use of a cooler drilling fluid with a higher salt concentration and the appropriate mud density, viscosity and surface tension reduces the formation pore pressure and helps to enhance the stability while the use of a hotter drilling fluid with a lower salt concentration and less favourable mud physical characteristics has the reverse effect. The coupled simulations show that incorporating the chemical potential and mud pressure penetration mechanisms, depending on the mud properties, can reduce the formation pore pressure. For an effective assessment of wellbore stability in shales, the analyses need to take into account these complex coupled time-dependent processes.
Innovative Drilling Fluid Design and Rigorous Pre-Well Planning Enable Success in an Extreme HTHP Well
D.J. Oakley, K. Morton, et al
When bottomhole temperatures exceed 400°F, the design and formulation of drilling fluids can present a host of problems. Drilling fluids destabilize under such extreme conditions, possibly causing wellbore instability, well control problems, and ultimately loss of the well. Operators and service-company responses to this risk are well documented.1,2,3,4,5The critical issues are:
- High-Temperature Gelation: This can occur in both water- and oil-based drilling fluids. In water-based drilling fluids (WBM), gelation under prolonged static conditions at temperature is caused by clay (bentonite) flocculation and is compounded by the thermal degradation of chemical thinners, a drop in pH and an increase in the filtrate loss. In oil-based drilling fluids (OBM), the interaction of colloidal particles (clays and fluid-loss additives) and breakdown of emulsifiers may cause gelation.
- High-Temperature Fluid Loss: Regardless of the type of drilling fluid, the static and dynamic fluid losses usually increase with temperature and are affected by gelation and thermal degradation of synthetic polymers.
- Rheological Property Control: High-density drilling fluids, by definition,have high volume fractions of weight material formulated to maintain hydrostatic pressure and well control. Properly controlling the rheological properties in the field depends on efficient solids-control equipment and high-performance drilling fluid additives. Small increases in colloidal-sized drilled solids can rapidly escalate the fluid's rheological properties, leading to unacceptable pressure losses, drilling fluid gelation, and excessive swab and surge pressures. Conversely, low rheological properties promote poor hole cleaning, sag of weight material, and a non-uniform density profile in the annulus that can promote drilling fluid losses to the formation or potential well control problems.
HPHT Drilling Fluid Challenges
Ronald G. Bland, Gregory Alan Mullen, et al
Accurate knowledge of drilling fluid behavior under actual conditions is required to maximize operational efficiency and to minimize cost and drilling fluid related risks on extreme high-pressure / high-temperature (HP/HT) wells.
This paper identifies and discusses the major HP/HT drilling fluid challenges, recent innovations in fluid viscosity measurements under HP/HT conditions, drilling fluid designs stable to extreme HP/HT conditions, and other considerations in HP/HT drilling.
Developing HP/HT prospects can require overcoming some formidable drilling challenges. Rigs capable of HP/HT drilling are larger due to requirements such as hook load, mud pumps, drill pipe and surface mud capacity to name a few. Due to these requirements, these rigs are more expensive. HP/HT wells, by definition, require a higher density fluid which typically requires high solids loading. High solids loading, the resulting higher pressures, combined with the competency of rock at depth, lead to low penetration rates, extending time on location and added drilling costs. In extreme cases, pressure, temperature, and acid gas levels can limit the selection and function of down-hole tools and fluid selection. These limitations can be so severe that MWD/LWD tools become unusable, rendering down-hole annular pressure measurements used for pressure management, unavailable. This places additional demands on the drilling fluid and temperature/hydraulic models as they become our best, if not our only source for down-hole pressure information. These models are based on surface inputs and laboratory measured fluid properties under down-hole conditions. During the planning stage for several potential record depth deep gas wells currently drilling or recently TD'd, not only did this information not exist, laboratory equipment capable of operation at the required temperatures and pressures didn't exist.
Down-hole pressures are commonly calculated using TVD (true vertical depth) and surface measured mud weight reported from the rig. While this approach is adequate for less demanding wells, critical applications such as HP/HT and deepwater wells require adjustments for the pressure and temperature driven compression and expansion characteristics of the whole drilling fluid. These compression and expansion effects are quantified in fluid PVT measurement under expected down-hole conditions which, until recently, ranged from 15 psi/75°F to about 20,000 psi/350°F which covered industry needs. HP/HT drilling pressures and temperatures, however, can far exceed this envelope. Figure 1 illustrates isobaric PVT results on a commonly used base-fluid.
Methane Hydrate Production from Alaskan Permafrost
Anadarko Petroleum Corporation & DOE/NETL
The goal of the project was to develop technologies for drilling and recovering hydrates in arctic areas. The specific objectives were to drill, core, and test a well through the hydrate stability zone in northern Alaska.
The Hot Ice well was drilled during the 2002-2003 and 2003-2004 winter drilling seasons, at a location approximately 20 miles south of the Kuparuk River Oil Field Center and about 40 miles southwest of Prudhoe Bay, Alaska. The well was drilled as part of a 2-year, cost-shared partnership between NETL, Anadarko Petroleum Corp., Maurer Technology Inc., and Noble Engineering and Development. It was drilled to test an Upper West Sak potential hydrate accumulation, based on updip hydrate shows in nearby Cirque and Tarn wells.
The Hot Ice well was drilled to a total measured depth of 2300 feet. The base of permafrost was encountered at 1263 feet, and the Upper West Sak target interval was encountered from 1463-1540 feet, just one foot higher than anticipated. Although the Upper West Sak sands lie within the theoretical Hydrate Stability Zone, and they have very good reservoir quality, they did not contain any hydrate. Instead of hydrate, the project team encountered free gas and water in the target interval.
The project successfully developed and demonstrated for the first time a number of innovative technologies, including Anadarko’s Arctic Drilling Platform, a mobile hydrate core analysis laboratory, a new application of a continuous coring rig, and a revolutionary drilling mud chiller. The research team also acquired a 3D Vertical Seismic Profile at the well, which resulted in very high resolution images of the subsurface, and possible indications of hydrate updip and east of the well site. Analyses of the core, log, and seismic data from the well indicate that the hydrate in this region occurs in patchy deposits and may require a high methane flux from the subsurface in order to form more continuous drilling prospects.
Alaska North Slope Gas Hydrate Reservoir Characterization
BP Alaska & DOE/NETL
The goal of this project is to characterize the large in-place methane hydrate resource on the Alaska North Slope (ANS) and to conduct field and lab studies to determine the potential for methane, produced from hydrate, to become a viable part of the overall energy supply.
The most atypical design criterion for this well is the requirement to minimize the disruption of the thermal regime through the gas hydrate stability zone. This element was critical to the entire evaluation program and especially to the recovery of relatively undisturbed cores from the interpreted gas hydrate-bearing interval. Previous drilling results utilizing chilled mud were reviewed and thermal flux computer models were run. It was concluded that the target temperature for mud going down hole was 2º C. An analysis of the market and availability of qualified rental mud chillers resulted in the selection of Drill Cool Systems Inc. to install and supply a modular mud cooling system like the one used during operations of the 2002 Mallik gas hydrate program.
Offshore Drilling & Well Testing of a HPHT Gas Well: A Case Study
Prerak Hitesh Shah, Harsh Tusharbhai Pandya, et al
With exploration in harsh environments and consequent high pressure and temperature conditions, the calculation of reservoir properties has become complex and thus the changes in pressure transient response need to be understood and appreciated by taking appropriate challenging measures.
The paper deals with the various challenges arising when dealing with the drilling and testing of HPHT gas wells with Hydrogen sulfide and Carbon dioxide, located in Krishna Godavari (KG) Basin and the difficulties faced while executing it. The paper focuses on the experience while drilling the reservoir with a different mud program and mechanical failure caused by HPHT conditions & highly corrosive environment. The paper also highlights the preference of SOBM over WBM while drilling the reservoir section. It also describes the learning process as the exploratory well campaign progresses from one well to other. It briefs about the challenges while performing MDT as per the program in these high temperature environment. The paper briefs about the decision involved in selection of proper grade tubing, elastomer, packer, flowhead equipments, DST tools & explosives in this HPHT environment along with Hydrogen sulfide & Carbon Dioxide. In any gas well testing, exhaustive amount of data over the requisite period of time are necessary; data redundancy necessitates redressing of equipments. The biggest challenges faced by industry are high temperature rather than high pressures, so making metallurgy an important basis of consideration. It also highlights about the method followed during correlation of prospective zones using different logs.
Corrosion Failures In Plate Heat Exchangers
R.L. Turissini, T.V. Bruno, et al
Corrosion failures in plate heat exchangers arc discussed with reference to equipment design, service conditions and materials of construction. Included are case histories that illustrate service experience.
Plate heat exchangers are chosen over shell-end-tube exchangers for applications requiring superior heat transfer efficiency and compactness, and lower weight. Efforts to maximize their inherent advantages drive plate heat exchanger design toward the use of thin plate sections that require highly corrosion-resistant materials, and narrow flow passages that are conducive to fouling.
Plate heat exchangers in general require extensive scaling along the edges of the plate. Consequently, crevice corrosion may occur under gaskets or adjacent to seal welds. Localized corrosion maybe either initiated or aggravated by the leaching of harmful ionic species into crevices from polymer gasket materials. Stress-corrosion failures are also encountered, particularly at cold formed corrugations incorporated into some designs to contain gaskets or to improve heat transfer coefficients.
The Effect Of Temperature On Pressure Losses During Drilling
H.B. Butts & B.R. Hise
The determination of circulating pressure is critical to the analysis of rotary drilling operations. Without knowledge of the actual pressures occurring in the system, it is sometimes difficult to prevent a gas kick or fractured formation. Rotary drilling hydraulics is concerned with a determination of these pressures and thus, is a very important part of drilling engineering. The most important phase of rotary drilling hydraulics is the calculation of the frictional pressure losses during mud circulation through the system. It is commonly known that formation temperatures increase with depth -- normally one to two degrees per hundred feet. The frictional pressure losses depend upon the mud's flow properties which are pressure losses depend upon the mud's flow properties which are a function of temperature. So, the pressure losses in both the drill pipe and annulus vary just as the temperature does.
The Temperature Prediction in Deepwater Drilling of Vertical Well
Petroleum engineers are interested in subsea temperatures to better understand geo-mechanisms; such as diagenesis of sediments, formation of hydrocarbons, genesis and emplacement of magmatic formation of mineral deposits, and crustal deformations. Petroleum engineers are interested in studies of subsurface heat flows. The knowledge of subsurface temperature to properly design the drilling and completion programs and to facilitate accurate log interpretation is necessary. For petroleum engineers, this knowledge is valuable in the proper exploitation of hydrocarbon resources.
This research analyzed the thermal process in drilling or completion process. The research presented two analytical methods to determine temperature profile for onshore drilling and numerical methods for offshore drilling during circulating fluid down the drillstring and for the annulus. Finite difference discretization was also introduced to predict the temperature for steady-state in conventional riser drilling and riserless drilling.
A Comprehensive Model for Circulating Pressure Loss of Deep-water Drilling and Its Application in Liwan Gas Field of China
Yujia Zhai & Zhiming Wang
Considering the special wellbore configuration and operating environment of deep-water drilling, a comprehensive model for circulating pressure loss of deep-water drilling is established. Based on fluid mechanics theory and heat transfer theory, wellbore temperature and pressure of riser section are calculated and a coupling approach is proposed. Comprehensive factors that affect circulating pressure loss of deep-water drilling are considered in this study. These factors are mud properties, flow regime, drill pipe rotation, drill pipe eccentricity, cuttings bed, tool joints, BHA (Bottom Hole Assembly), drill bit and surface pipeline. The model is applied to Liwan gas field of China. The results show that the data calculated by this model match the field data very well and the model can provide references for designing deep-water drilling hydraulic parameters.
Investigation on the Effects of Ultra-High Pressure and Temperature on the Rheological Properties of Oil-Based Drilling Fluids
Chijioke Stanley Ibeh
Designing a fit-for-purpose drilling fluid for high-pressure, high-temperature (HP/HT) operations is one of the greatest technological challenges facing the oil and gas industry today. Typically, a drilling fluid is subjected to increasing temperature and pressure with depth. While higher temperature decreases the drilling fluid’s viscosity due to thermal expansion, increased pressure increases its viscosity by compression. Under these extreme conditions, well control issues become more complicated. Also current logging tools are at best not reliable because the anticipated bottom-hole temperature is often well above their operating limit. The literature shows limited experimental data on drilling fluid properties beyond 350°F and 20,000 psig. The practice of extrapolation of fluid properties at some moderate level to extreme-HP/HT (XHP/HT) conditions is obsolete and could result in significant inaccuracies in wellbore hydraulics calculations.
This research is focused on developing a methodology for testing drilling fluids at XHP/HT conditions using a state-of-the-art viscometer capable of accurately measuring drilling fluids properties up to 600°F and 40,000 psig.
Experimental Study of the Effect of Temperature on the Flow Properties of Normal Oil Based Muds in Niger Delta Formation
O. Adekomaya, D. Anifowose, et al
The behaviour of the drilling fluids under high temperature is extremely important for drilling deep wells. Most commercial oil base drilling fluid systems have limitations such as reduced rheology and filtration control if the fluid is exposed to higher temperature for prolonged periods of time. Formulating a drilling fluid system that can adequately withstand drilling in a high temperature environment is very challenging but very often little attention is given to proper fluids design. In this research, a normal oil based mud suitable for Nigerian formation was formulated and was aged under high temperature conditions for 16 hours. The effect of aging on the properties of drilling fluids was studied. From the study, it is concluded that rheological changes in drilling fluids have many effects on the degree of efficiency with which a fluid performs its primary functions and it is important that efforts are made to minimize these detrimental effects.
Modeling the Effects of Temperature and Aging Time on the Rheological Properties of Drilling Fluids
F Makinde, A Adejumo, et al
The rheological properties of drilling fluid change owing to elevated temperature and aging time and these in effect, cause problems in drilling deep wells. A laboratory investigation of the effects of temperature and aging time on the properties of water-base drilling fluid is made with Fann Model 800 HighTemperature, High Pressure (HTHP) Viscometer. It is evident from the findings that effective viscosity, plastic viscosity and yield point decrease steadily with increase in temperature for all values of aging time. It is observed as well that viscosity at a given temperature decreases with increase in aging time and the aging effect are diminishing as the aging time increases especially for the effective viscosity and yield point. It is also observed from this study that viscosity, yield point, gel strength and shear stress at a given shear rate decrease with increase in temperature and aging time. Finally, this paper presents a predictive model equation good enough to analyse trends and predict future values for effective and plastic viscosities.