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Abstract Coiled tubing is usually used to conduct acid pickle treatments. The purpose of the treatment is to prevent pumping damaging materials into the formation prior to the main acid job. In this case, the acid is pumped down the coiled tubing, and then flowed up through the tubing-coiled tubing annulus. Pickling is a process of flow with heterogeneous reactions occurring with mill scale (Fe3O4) and other contaminants at both the inner wall of the production tubing and the outer surface of the coiled tubing. Pickling is an essential part of well stimulation treatments if the main treatment fluids (acidizing, fracturing, gravel packing, etc.) are to be bullheaded. However, it appears that traditional pickle practices are overestimating the required acid volume and/or concentration. Field data indicated that excessive acid volumes are used for tubing pickle because large returns of unreacted acid are usually recovered on the surface. In this paper, mechanisms to explain the behavior of acid contact with the tubing are presented and a model for predicting acid consumption and dissolution of tubular contaminants is developed. The model includes reactions of acid with mill scale. A system of non-linear partial differential equations is developed and the equations are solved numerically to predict the concentrations of major species as a function of axial position along the tubing and in the effluent from the well during flowback. Field application included pickling of low-carbon steel tubing (11,900 ft of 5.5-inch C-95) using coiled tubing. A slug of 5,000 gals of 20 wt% HCl with additives was used. Samples were collected from the treated well during the flowback of pickling treatment. The model was used to predict the concentrations of various species in the well flowback samples. Model predictions for acid, chloride ion, and total iron concentrations were in good agreement with field results. In addition, the model proved to be a valuable tool in optimizing future pickling treatments. Introduction Scientists and engineers working on chemical treatments to enhance well performance usually focus on reservoir characteristics, fluid placement, fluid compatibility, and thermal stability. Less attention, however, is given to potential formation damage that might occur if the contaminants present in the well tubulars invade the formation. Several studies were conducted to identify the type and amount of contaminants present in well tubulars.[1–4] Pipe dope and mill scale were identified as main contaminants present in the production tubing.[5–8] Invasion of these materials into the target zone can cause severe formation damage. Therefore, it is always recommended to minimize the amount of pipe dope used and to clean well tubulars prior to any chemical treatments, especially if these chemicals will be bullheaded. The types of fluids used in pickling treatments depend on the type of contaminants. Xylene and similar organic solvents are used to dissolve the organic portion of pipe dope. Hydrochloric acid is used to remove acid-soluble material present in the pipe dope (mainly zinc), and mill scale. Selection of acid additives depends on temperature, type of tubular, and the fluids that will come in contact with the acid. It should be noted that environmentally friendly pickling fluids were introduced over the last few years, with positive field results. [9,10]
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.54)
Abstract Coiled tubing (CT) is widely associated with underbalanced drilling technologies. Especially in depleted reservoirs, drilling need for underbalanced and extended reach wells is increased where CT is widely used. In this work, optimization of volumetric requirements for liquid and gas phases is investigated in long horizontal and inclined sections of CT applications for underbalanced drilling. A mathematical model is introduced in order to predict the flow characteristics of multiphase flow through an annulus. Flow patterns and frictional pressure losses are evaluated using the experimental data of a wide range of liquid and gas flow rates recorded at a field-scale annular flow loop with common CT drilling dimensions as well as circular pipes. Practical curves are developed for determining the optimum flow rate combinations for CT applications using the developed model. A sensitivity analysis is also conducted on underbalanced and CT drilling parameters on pressure drop and flow patterns. Introduction Two-phase flow is the flow phenomenon of two different fluid phases flowing simultaneously through a conduit. Generally, liquid and gas phases are the components of this commonly encountered flow type. Since 1950's, the flow problem of two-phase fluids has been the subject of research in many different engineering practices. In petroleum industry, the applications of two-phase flow start from drilling and continue till the refining process. In depleted reservoirs, underbalanced drilling techniques are required in order to prevent any possible formation damages. This enhanced technology diminishes the risks of contaminating the reservoir. Thus, in order to determine the design parameters accurately, the flow behavior of aerated fluids should be well known. Another important usage of two-phase flow takes place during the transportation of the produced oil and gas via the pipelines. Since the oil and gas fields are mainly in remote onshore areas or in offshore, the pipeline systems are of great importance. Reliable engineering calculations should be carried out as the overall distances of these pipeline systems are considered. With the improving technology, the innovative methods demand for the better understanding of two-phase flow systems. As in case of CT drilling combined with underbalanced techniques in extended reach wells, the flow problem becomes more complicated when compared with single-phase flow of drilling mud in conventional drilling. When this wide range of application of two-phase flow in petroleum engineering is considered, the appropriate determination of flow parameters of two-phase fluid systems becomes highly important. The focus of this study is the flow of two-phase fluids through concentric annuli, i.e., horizontal and highly inclined sections of wellbores. Literature review Through the investigation of two-phase flow phenomenon, extensive theoretical and experimental studies have been carried out. The proposed models can be grouped into two categories; namely general models and mechanistic models. The early models developed for two-phase fluid systems were flow pattern independent. These general models ignored the complex flow configurations, named as flow patterns, and treated the two-phase flow as a single-phase fluid flow or as a flow of two separated fluids. The most important models are proposed by Wallis [1], Lockhart and Martinelli [2], and Duns and Ros [3]. These general models are the starting points through the progress of modeling two-phase fluid flow. The later studies focused on the determination of flow patterns. The flow mechanism of two-phase fluid systems was examined independently for each flow pattern. Then, governing flow equations were proposed for a given flow pattern. These models were called mechanistic models. As the knowledge of flow behavior of two-phase fluid systems has improved, comprehensive and unified models were developed.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Overview > Innovation (0.34)
Abstract This paper reports the field results obtained from application of a system that provides both pre-job modeling capabilities and real-time monitoring of maximum stress levels in the entire intervention stack, from the wellhead to the injector assembly.In addition, the paper documents the dynamic movement capabilities recently incorporated in the model and validation of the model calculations. Introduction Reference 2 discusses an intervention riser safety system which has become known as the ? (Zeta) Safety System.This paper documents further development and testing that has been done with this system.The system is composed of two basic components:?model - a numerical dynamic simulation model which models the stresses in an intervention stack. ?gauge - a lubricator spool, instrumented with fiber-optic strain gauges, is placed in the intervention stack. It measures axial force, internal pressure, and bending moments in the spool. The initial coiled tubing (CT) field application of this safety system was performed to satisfy several primary objectives, including:Validation of modeled calculations versus field data measured by independent devices Sensitivity of the field stress measurements provided by the system Confirmation that system design and calibration is sufficiently robust for routine field applications The ability to accurately model dynamic movement of two independent structures was driven by increased utilization of floating structures (TLPs and Spars) being deployed in deepwater projects.The tethered topside structure typically exhibits some amount of horizontal displacement in a figure-eight pattern as a result of wave motion, with the wellhead exhibiting a similar displacement pattern but with differing frequency and amplitude.The intervention stack may experience increased stress levels when each end of the rigid lubricator/riser assembly is attached to these two independently-moving bodies.A dynamic modeling capability incorporated in this model addresses these field conditions. In addition, offshore intervention stacks are becoming taller to accommodate offshore floating structure size, and often pass through multiple deck surfaces that constrain lateral stack movement.This can create a condition whereby conventional safety limits are exceeded.While counter intuitive, removal of lateral stack constraints may actually increase the safety of a given stack.Another finding is that the maximum stack stress may occur in situations where no CT hanging weight is applied to the stack. The pre-job modeling capabilities of the system are used to optimize intervention rig-up design and to determine the probability of exceeding pre-set safety limits during the operation.During the field operation, real-time stress values provided by the system enable informed decisions, rather than a judgment call, to be made if maximum stress levels are approaching unsafe limits.
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (0.70)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (0.49)
Abstract A mathematical model and a numerical analysis of the cuttings transport with foam in horizontal wells have been presented earlier. The model has been incorporated into a computer program and used for finding a closed form critical foam velocity (CFV) correlation. The new CFV correlation can be used to predict minimum foam flow rate required to remove, or prevent the formation of stationary cuttings beds on the low-side of the highly deviated and horizontal wells. Effects of key drilling parameters (i.e. drilling rate, annular geometry, foam quality, bottomhole pressure and temperature) on the critical foam velocity have also been investigated. Numerical examples are presented to illustrate how the CFV correlation can be used to determine required gas and liquid flow rates at the downhole conditions. Introduction When planning or drilling highly deviated or horizontal wells, one of the key parameters which must be determined is the minimum drilling fluid velocity required to transport drilled cuttings up to surface and the keep hole clean. This minimum fluid velocity is called the "critical fluid velocity" (CFV). If insufficient flow rate is used, cuttings will deposit on the low side of the wellbore and form a large stationary bed which result in severe drilling problems such as high drag and torque, hole packing-off and stuck pipe. It is, therefore, crucial to know the CFV when planning and drilling a deviated well so that the adequate and economical drilling equipment can be selected and optimum parameters determined. Examples of critical fluid velocity (or critical flow rate) correlations for drilling with conventional (incompressible) drilling fluids have been presented by Luo et al., and Larsen et al. Optimization of hole cleaning in horizontal wells becomes even more complex when compressible fluids such as foam and aerated mud are used as drilling fluids. Foam is favorably used as a drilling fluid in many horizontal wells because of its low density, superior cuttings transport ability and stable flow characteristics with low tendency of slug formation. Good cuttings transport ability of foam has been demonstrated in the field, although formation of stationary cuttings beds has been reported by some experimental studies. In this study, a critical foam velocity (CFV) correlation has been developed by using the Li and Kuru model presented earlier. The effects of foam quality, borehole size, horizontal well length, bottomhole pressure (BHP), and temperature on the CFV have been analyzed and the results are presented in this paper. Mathematical Model of Cuttings Transport with Foam in Horizontal Wells Recently, Li and Kuru developed the transient multiphase flow model of cuttings transport with foam in horizontal wells. The brief description of the model is given in the following section. Model Description The conservation of mass relationships for foam fluid and solid phases are given by equations (1) and (2) respectively.Equations 1 and 2 In equations (1) and (2), ?sf and ?ss represent the rates of change of mass of foam and solid particles per unit volume of the wellbore due to the mass transfer between layers, and sf denotes mass influx rates of water, oil and gas from the reservoir per unit volume of the wellbore.
- North America > Canada (0.94)
- North America > United States > Texas (0.69)
Abstract An experimental study of cuttings transport with foam at intermediate angles has been conducted in a full-scale Low Pressure-Ambient Temperature (LPAT) flow loop at The University of Tulsa. An anionic surfactant was used in these water base foam tests at a concentration of 1% v/v. Air was used as dispersed fluid. Rheological tests were conducted to obtain flow curves for foams with 70% and 80% qualities in 2", 3" and 4" pipes. A simulator was developed to predict pressure, flow velocity, specific volume expansion ratio and foam quality along the wellbore based on the volume equalized power law model. Tests were conducted to determine the effects of inclination angle, foam quality, foam velocity and rate of penetration on cuttings transport. Results from this study show that the in situ cuttings concentration ranged, according to the inclination angles, from 4.8% to 14.6% for 45 degrees, 14.3% to 22.3% for 55 degrees and 8.5% to 25.7% for 65 degrees. It is shown in this study that the transport of cuttings (in terms of cuttings concentration) has a better performance with foams of low quality. For a given inclination angle and similar foam flow conditions, increasing the rate of penetration from 20 ft/hr to 44 ft/hr can lead to an increase in the in situ cuttings concentration of up to 7%. A new correlation for the ratio of the cuttings bed area to the cross sectional area of the annulus as a function of dimensionless numbers (Ar, Re, Fr, Ss and ?) was developed and allows for pontential practical applicaitons. The differences between the calculated and measured values are within a range of ±17%. Introduction Foam has a variety of applications in the oil and gas industry. Particularly, foam can be used as a lightweight drilling fluid in under balanced drilling applications. Drilling with foam has been shown to provide significant benefits including increased drilling rate, minimization of lost circulation, reduction of differential pipe sticking and reduced formation damage. Foam also has potential applications in deepwater drilling operations. The rheological behavior of foams plays a key role in determining the efficiency of cuttings transport in drilling operations. Although great efforts have been made to model the rheology of foams, there is an apparent disagreement among investigators in selecting the best model for describing the flow behavior of foam. Due to the complexity of foams, the resulting models frequently contained parameters that are difficult or impossible to measure and hence of limited applicability. Valko et al. introduced the "Volume Equalized Principle" based upon the concept of constant friction factor (Reynolds Number) along the flow line. In practice, the principle states that all shear stress-shear rate data points obtained from isothermal experiments under different geometries and qualities (due to different volumetric inlet gas/liquid ratios or quality changes along a pipe) lie on a single curve if both the shear stresses and shear rates are volume equalized. Under this concept, the volume equalized rheological models are written as below: Power Law Volume Equalized:Equation 1 Bingham Plastic Volume Equalized:Equation 2 Hershel-Bulckley Volume Equalized:Equation 3 Saintpere et al. reported that the Herschel Bulkley number can be a good indicator of carrying capacity. They suggested that the dimensionless parameter "characteristic time" provided an estimate of the necessary circulating time for hole cleaning. They also observed the worst hole cleaning efficiency at angles between 40° to 60°. Martins et al. conducted experimental and modeling studies to predict cuttings transport performance in horizontal and inclined wells. Results show that an increase in total flow rate helps bed erosion and higher liquid flow rates always result in better hole cleaning.
Abstract Extensive aerated mud experiments were performed in a unique field-scale elevated pressure and elevated temperature flow loop (6" × 3.5" annular test section, 73 ft length, horizontal configuration without drillpipe rotation). A view port was installed to observe flow patterns in the test section. Two nuclear densitometers were used to measure steady state mean void fraction. During test runs, the liquid and gas phase flow rates were in the range of 50–250 gal/min and 50–150 scf/min, respectively. For all the test runs, measurements of pressure drop and average liquid holdup over the entire annular section were carried out. The two-phase flow patterns were identified by visual observations through the view port. Stratified and slug flow were the two flow patterns observed over the range of the chosen test matrix. The presence of slug flow does not justify many existing simulation practices, which assume a homogeneous gas-liquid flow. A mechanistic model has been developed for aerated mud hydraulics based on conservation equations and existing two-phase pipe flow correlations. An extensive sensitivity analysis is presented to quantify the influence of mud properties and flow parameters on the bottom-hole pressure. Comparisons between the predictions of the model and experimental measurements show a satisfactory agreement. The present model is particularly suitable for the design of underbalanced coiled tubing applications. Introduction Coiled tubing has been shown to be a technically feasible method of drilling both oil and gas wells. One of the best applications of coiled tubing drilling technology is underbalanced drilling, to counteract the reduced weight on bit and annular velocities compared to conventional drilling. In some applications, aerated mud drilling has been recognized as having many advantages over conventional mud drilling, such as a higher penetration rate, less formation damage, reduced lost circulation, and lower drilling cost. Maintaining an optimum combination of liquid and air flow rates is important in aerated mud drilling operations. A useful prediction of the optimum combination requires knowledge of the flow pattern and determination of the properties of each phase under borehole conditions. Dukler and Hubbard developed a two-phase flow model based on phenomenological observations. Their study contributed a great deal of understanding about the mechanisms involved in hydrodynamic of slug flows. Based on their observations, Dukler and Hubbard defined an idealized slug unit and suggested a mechanistic model. It is the basis for a detailed mathematical model, which is capable for predicting hydrodynamic behaviors of slug flows, including the length, velocity, holdup and pressure distributions. A mathematical model for slug flows was developed by Ozawa and Sakaguchi based on the law of conservation of mass and momentum. This model predicts the position of a slug nose and tail, and pressure drop across the slug nose. The predictions showed a satisfactory agreement with experimental data. It was suggested that their approach could be used to study transient two-phase slug flows (solid-liquid or solid-gas flows). A Lagrangian approach was used by Gilchrist and Wong to study slug growth and acceleration effects associated with horizontal slug flows. The slug structure comprised of three sub-volumes: a liquid slug with entrained gas bubbles; a liquid film with a zero gas void fraction; and a gas bubble with zero liquid holdup. Mass and momentum equations were developed for the liquid slug and liquid film sub-volumes. An equation of state was used to formulate the changes in pressure in the gas bubble. A system of ordinary differential equations was coupled and solved simultaneously by a 4th order Runge-Kutta method. The simulated results for a particular slug unit showed fluctuations in the average slug velocity and void fraction in the liquid slug, and growth in the slug length as it traverses in a pipeline. Gomez and Shoham developed a mechanistic model for steady-state two-phase flows. The model is applicable for inclination angles from horizontal to vertical. The model predicts flow patterns, pressure drop, and liquid-holdup for stratified, slug, bubble, annular and dispersed bubbly flows.
- Research Report > Experimental Study (0.50)
- Research Report > New Finding (0.40)
Abstract This paper describes a system for monitoring the maximum stresses in an intervention wellhead, BOP lubricator/riser, and injector structure. In some offshore cases the wellhead itself may be moving, causing stresses in the intervention structure. In other cases the injector support system may allow some side-to-side movement, causing stresses in the structure. This system measures the bending moment, bending direction, axial load and internal pressure at one or more points in the structure. A real-time finite element analysis is then performed by the system to determine the maximum stress in the structure. The system displays the bending moment, bending direction, axial force, and internal pressure to the operator. It also displays the maximum stresses along the length of the structure, and warns the operator when the stresses exceed a safety limit. This paper describes the development and testing of this system. Introduction As intervention systems become more complex, the length, pressure rating, axial loads and bending moments being applied to a riser/lubricator structure become more complex. It is not unusual for the entire structure to be over 50 ft high, and to be swaying significantly during a job. A crane is often used to hold the structure vertically in tension, while guy supports (wires or chains) are typically used to hold the structure to minimize lateral movement. However, the hanging weight of the coiled tubing (CT) may be much greater than the crane can support. Thus the structure is in compression, and the potential for buckling exists. The IRISS system was developed to monitor the stresses in such a structure. Measurements are made at one point in the structure using the IRISS gauge. A finite element model is then used to calculate the stresses throughout the structure, using the real-time measurements from the IRISS gauge. If the maximum stress exceeds a safety limit for that component of the structure, the monitoring system warns the operator, and presents him with information about the bending and/or buckling, so action can be taken to stabilize the structure. IRISS Gauge The Challenge A device was needed to measure the axial force, bending moment and bending direction in an intervention lubricator/riser structure. This can be done by measuring the axial strain at multiple locations around a section of pipe in the structure. Accurate measurements of the temperature of the pipe are also needed to compensate for temperature changes. The pressure in the pipe can be measured directly or can be calculated based upon hoop strain measurements at the same location as axial strain measurements. However, the components used in an intervention structure typically have a thick wall thickness. For example, a 4 1/16", 10,000 psi lubricator has an internal diameter (ID) of 4.0625", and a minimum outside diameter per API specification 6A of 5.75". Assuming a yield stress of 75 Kpsi, this lubricator can withstand an axial force of 975 Klbs before it will yield. If a small axial force of 1 Klb is applied to this lubricator, the axial strain will only be 2.6 × 10, or 2.6 µe (2.6 micro-strain). Conventional steel foil strain-gauge technology is typically used to read strains ranging from 200 µe to well over 3,000 µe. It is possible to read small strains in the range of ±1 µe with this technology with special instrumentation. However, this instrumentation is difficult to calibrate and maintain, and require electrical components in an area where hydrocarbons may be present. The challenge in developing this device was finding a method of measuring strains as small as ±1 µe that could be ruggedized to endure the field environment. Fiber Optic Strain and Temperature Gauges The IRISS uses an extrinsic Fabry-Perot interferometer strain measuring technique to measure the axial and hoop strains as well as the temperature of the pipe. Figure 1 shows a sketch of this equipment used for this measuring technique. Light is sent from the light source through a coupler and out through two fibers. One of these fibers is a reference fiber, which reflects back the light exactly as transmitted. The second fiber goes to a cavity type strain sensor.
Abstract This paper will discuss a purpose written fully 3D Finite Element Analysis (FEA) model which analyzes the bending of pipe inside a wellbore. The yielding and residual curvature of CT can be included in this model. The model is also able to calculate the onset of buckling. This paper presents the equations and methodology used in the development of the model. Results from the model are compared with analytical solutions currently in use. Examples studies performed with the model are presented. Introduction Several types of numerical methods are currently used by various models to calculate the behavior of pipe inside a wellbore or pipeline when subjected to axial and torsional loads. The most common type of model is a "soft-string" model which calculates the forces on the pipe sequentially, beginning at one end with a known force and calculating in increments to the other end. These models are accurate and useful for many types of problems. However, they do not include the bending stiffness of the pipe itself in their analysis. There are some types of problems in which the bending stiffness is important. So called "stiff-string" models are much less common than the soft-string models. Stiff-string models do include the bending stiffness of the pipe. Special stiff-string models have been written for solving special problems, such as drilling bottom hole assembly (BHA) analysis. Some of these models use finite difference and finite element analysis techniques. Reference 1 discusses the various model types. Of the numerical modeling techniques, finite element analysis (FEA) is usually considered to be the best. However, there are several challenges in implementing FEA has kept it from being the most common type of tubing forces model. Most numerical techniques are either a "bottom up" or a "top down" calculation. An FEA solution solves for all the unknown displacements of the pipe in the wellbore simultaneously. One of the biggest challenges for any stiff-string model is knowing at a specific point if the pipe is touching the wall of the wellbore or not. If not, the pipe is free to move. If it is touching, some wall contact force (WCF) is being applied to the pipe. It is challenging for any numerical technique when any sudden change or step function exists. This is possibly the biggest challenge for implementing an FEA tubing forces model. This challenge, and several other challenges were overcome in the development of this model. The following sections will outline the FEA equations used, and discuss how the various challenges were overcome. Then example studies are presented showing how the model is used. Finite Element Model Local Element Stiffness Matrix Figure 1 shows a single beam element, i, in its local coordinate system. The x axis of the local coordinate system runs through the center of the beam. The y and z axis are defined as shown. Note that small characters x,y and z are used to denote the local coordinate system. At each end of the element there is a node. Nodes are shared between two adjacent elements for connectivity. This element has node number n on one end and node n+1 on the other end. Each node may move in 6 ways, known as degrees of freedom (DOF). 3 of these DOF are displacements, u, along the local x,y and z axis. The other 3 DOF are rotations, ua, about the three local axes. Note that the double arrows shown in Figure 1 represent rotation about that axis. Figure 2 shows two elements, i and I+1, with their respective local coordinate systems, connected at node n, and located in a global coordinate system X,Y and Z. The global X coordinate is defined as pointing downward, toward the center of the earth. The nodes are placed on the centerline of the wellbore, as shown. The inclination, a, of each element is the average of the wellbore inclinations at the two adjacent nodes. Likewise, the azimuth angle, ?, (not shown) is the average of the wellbore azimuth angle at each node.
Abstract Special care must be taken to maintain the integrity of the coiled tubing when performing subsea well intervention from a light vessel without the use of a riser. In these cases the coiled tubing will act as a riser with respect to withstanding the external loads from waves, current and vessel motions. To avoid local buckling of the coiled tubing as it enters the subsea lubricator it is important to keep the vessel positioned such that the bending of the coiled tubing is kept as small as possible. This paper will outline a method for estimating the optimal set point for the vessel position during riser less coiled tubing operations. The method is based on a combination of measurements and analytical methods for description of the structural behaviour of coiled tubing and the subsea stack. The analytical method developed is compared to simulations using commercial riser analyses software. Introduction With the increasing number of subsea wells, there is a need for more cost-effective intervention methods. While platform wells are commonly intervened as often as 2–4 times a year, subsea wells are in general only intervened if absolutely necessary, i.e. in case of barrier failure or dramatically reduced production. The main reason for this is the cost and difficulty associated with subsea well intervention. To significantly reduce the subsea well intervention cost, systems that can be used efficiently from a dynamically positioned (DP) monohull vessel is required. Riserless wireline intervention tequniques has been developed over a number of years [1–3], and can now be considered mature technology. Subsea wireline systems are used on a routine basis, at least in the North Sea, and several rental systems are available in the market. While wireline is suitable for well diagnostics such as production logging or sampling tools, remedial operations such as running plugs, straddles, stimulation and perforation are more efficiently performed with coiled tubing, especially in highly deviated and horizontal wells. This is the motivation for development of a riserless coiled tubing system. One of the challenges in developing a riserless coiled tubing system is controlling the behaviour of the coiled tubing. The coiled tubing will act as a riser with respect to withstanding the external loads from waves, current and vessel motions. To avoid buckling and excessive stress on the coiled tubing it is important to keep the vessel positioned such that the bending of the coiled tubing is kept as small as possible, i.e. at surface and subsea where the coiled tubing enters the lubricator system. System Description A riserless coiled tubing system is described in [4]. The two novel features of this system compared to previous solutions [5] is the use of tensioned coiled tubing between the vessel and the wellhead and a new lubrication system where the lubricator is placed above the coiled tubing injector, Figure 1. The Well Barrier Packages and X-mas tree adapter shown in the figure are conventional. By mounting the lubricator above the injector package, the bending moment on the X-mas tree adapter is considerably reduced, and tool string deployment and retrieval is considerably simplified compared to a surface type coiled tubing system where the injector needs to be lifted off when changing toolstrings.
- North America > United States > Texas (0.46)
- Europe > United Kingdom > North Sea (0.34)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/25 > Argyll Field > Zechstein Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/25 > Argyll Field > Trias Group (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/25 > Argyll Field > Rotliegend Formation (0.99)
- (27 more...)
Abstract Coiled Tubing Drilling, grown significantly in recent years, is normally associated with high angle to horizontal and extended reach wells. It is, however, in these applications that hole problems become more troublesome because of inefficient cuttings removal. Among the many parameters affecting efficient cuttings transport in Coiled Tubing Drilling are pump rates, well dimensions, fluid properties, solids sizes, solids loading and hole inclination. Several attempts have been made to determine the optimum operating range of these parameters but complete and satisfactory models have yet to be developed. The purpose of this paper is to provide a critical review of the state of the art on efficient cuttings transport during Coiled Tubing Drilling, present the critical parameters involved, establish their range according to what is observed in practice and propose a different approach for predicting the minimum suspension velocity. Finally the laboratory system that has already been set up is presented. Its primary purpose is to allow the gathering of good quality data, missing from the literature, which could enhance our understanding of the flow of solid - liquid mixtures in annuli. Introduction The advantages of Coiled Tubing Drilling (CTD) are numerous and have been indicated and proved in practice by a large number of investigators. A significant drawback is the difficulty for efficient cuttings transport primarily because the pipe is not rotated. Cuttings transport during drilling (either conventionally or with Coiled Tubing) has a major impact on the economics of the drilling process. Inefficient hole cleaning from the cuttings can lead to numerous problems such as stuck pipe, reduced weight on bit leading to reduced rate of penetration (ROP), transient hole blockage leading to lost circulation conditions, extra pipe wear, extra cost due to additives in the drilling fluid and wasted time by wiper tripping. These many problems have prompted significant research into cuttings transport during the past 50 years. Excellent reviews on the subject have been given in the past. Pilehvari et al. state that fluid velocities should be maximized to achieve turbulent flow and mud rheology should be optimized to enhance turbulence in inclined / horizontal sections of the wellbore. Turbulent flow of non-Newtonian fluids needs much more work and should be extended to include pipe rotation and dynamics for conventional drilling. Future work should focus on getting more experimental data, validation of fluid models, cuttings transport mechanistic models verified by comprehensive experimental data. Azar & Sanchez conclude that a combination of appropriate theoretical analyses (complete free body diagrams, accurate rheological models, accurate annular flow models), experimental studies (extensive testing concentrating on individual variables or phenomena), statistical modeling (rheological models, unstable cuttings transport conditions), and high - tech research facilities (accurate measurement of pertinent variables, analysis of video to develop flow pattern maps) will be necessary for further progress. While many cuttings transport problems were addressed quite successfully for conventional drilling in vertical, inclined and horizontal wells in the past, the increase in activity of CTD has called for renewed interest into cuttings transport problems in horizontal and highly inclined annular geometries with no rotation of the inner pipe. In recent years there have been several theoretical, semi-theoretical and experimental investigations for assessing the important parameters for efficient cuttings transport in highly inclined and horizontal geometries during CTD or conventional drilling but not taking into account the rotation of the inner pipe.
- Europe (1.00)
- Asia (0.68)
- North America > United States > Texas > Dallas County (0.28)
- Research Report > New Finding (0.66)
- Overview (0.66)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)