Liu, Huixing (Southwest Petroleum Institute of China) | Fan, Jun (Chongqing Petroleum College, China) | Yan, Renjun (Sichuan Petroleum Administration, CNPC, Chian) | Yu, Zhongsheng (Chongqing Petroleum College, China)
Nowadays the use of air and gas as a circulating medium for drilling oil and gas wells is becoming an attractive practice because of its great advantage over conventional mud drilling. However, the occurrence of some troubles due to poor carrying capacity of cuttings in air/mist drilling is not uncommon. Meanwhile, the determination of air/gas injection rate desired to undertake air and gas drilling is also closely related to the actual moving regularity of cuttings in annulus. It is obvious that researches on migration rate and carrying capacity of cuttings within borehole are essential to air/mist drilling. Although there are some theoretical models for prediction of cutting migration velocity and therefore the carrying capacity of cuttings, experimental studies are also essentially important because of the complexity of actual liquid, gas and solid multiphase flow in wellbore and the uncertainty of theoretical models. In this paper, some experimental studies were performed to investigate the moving regularity and carrying capacity of cuttings in wellbore. Some comparisons between the testing results and theoretical models are also presented in the paper. It is seen that such a study is valid and effective in prediction of the migration velocity and analysis of the motion regularity of cuttings in borehole. Therefore, the required practical air injection rate to keep the necessary carrying capacity in air/mist drilling can be determined definitely.
In the past, tubing, casing and drill pipe recovery has been employed where chemical and explosive severing tools could not effectively sever the pipe.
A coiled-tubing-conveyed hydromechanical pipe cutting system has proven to be a viable alternative to pipe recovery when conventional severing systems are not effective. The system does not contain or require any hazardous materials, which makes it safer to use than conventional systems.
The pipe cutting system incorporates modular stabilizing devices that decrease the risk of the coiled tubing forces and the wellbore deviation from interfering with the cutting operation. The pipe-cutting mechanism uses several unique blade configurations that were designed specifically to address various metallurgical properties and dimensions. The cutting blades contain state-of-the-art cutting inserts, which were previously proved in various metal milling and cutting applications within subterranean wells.
A detailed description of the coiled-tubing-conveyed hydromechanical pipe cutting system, its operational function and a variety of case histories are discussed in this paper.
Electrical wireline-conveyed explosive jet and chemical cutters are currently the preferred choices for cutting pipe in slimhole wellbores.
Explosive jet cutters are used for severing common sizes of production tubing, drill pipe and casing. The cutting action is produced by a circular-shaped charge. Typically, this type of cutter leaves a flare on the severed pipe string. In order to perform subsequent pipe recovery operations, it is necessary to smooth the top end of the tubing left in the wellbore with an internal mill insert that is usually run with an overshot1.
Chemical cutters are designed to cut through one string of pipe while not damaging the adjacent string. They produce a flare-free and undistorted cut. The topside of the severed pipe can be engaged with an overshot without dressing with a mill1.
A wireline-conveyance operation provides several advantages when compared to using coiled tubing and threaded pipe. Wireline equipment can be mobilized and disassembled quickly; the wireline can be run in and out of a hole much faster; and the cost of a wireline operation is usually less than other methods.
The success rate can be reduced, however, when wireline-conveyed cutting tools are used for exotic applications such as cutting through plastic coated or corrosion-resistant alloys. High-density wellbore fluids, a greater-than-standard pipe wall thickness and distance between the cutter and the internal wall of the pipe also reduce the effectiveness of the wireline-conveyed systems. Another drawback is that the wireline systems are designed to cut only one string of pipe per operation. Therefore, several trips into the wellbore are required to separate multiple, adjacent strings internally.
The limitations of wireline-conveyed cutters can be overcome for the specific applications noted above with a hydromechanical pipe cutting system (HPCS) that takes advantage of proven, downhole metal cutting technology. The HPCS is activated by weight or hydraulic pressure. It can be rotated by a downhole workover motor or from the surface using a rotary rig or power swivel. The HPCS provides the power needed to cleanly cut single or multiple strings of pipe downhole. Such non-distorted pipe cuts are especially beneficial when it is necessary to recover pipe that is stuck in open hole2.
Time is a critical factor for a successful pipe recovery operation. The quicker the fishing jar assembly can be employed the greater the chances of a successful pipe recovery operation. The clean top of the severed drillpipe left by the HPCS improves efficiency in employing the fishing assembly3.
Until the early 1990s, very few pipe-cutting operations were attempted using coiled tubing as a conveyance means4,5.
This paper examines the use of coiled tubing deployed thru-tubing inflatable packers in a straddle configuration. Many times this straddle option can be used to prolong the life of a well without the time-consuming and resource-sapping operation of having to perform a complete well workover. Couple the resulting economics with the operational advantages of not having to kill the well and a completion in situ inflatable straddle option may and has offered operators in the global oil and gas industry a very real and viable option.
During the course of this paper the inflatable straddle option is examined and discussed as is the operational deployment and options of such a system. Running a single trip straddle and running a multiple trip down hole assembled system are highlighted. Four case histories will be disseminated to provide a balanced opinion on the effectiveness of such a system. The four case histories include a chrome system to match the already installed completion metallurgy and the highlighted wells will vary in geometry up to that of a horizontal gas well.
The paper goes on to discuss the longevity of such a system with at the time of submitting this abstract one of the featured systems having been in position in a producing environment for in excess of five years.
There are many reasons for the requirement to run a straddle system into a wellbore. The most common application is the requirement to isolate a section of the wellbore while at the same time leaving the ability to access the wellbore below the isolated section. Some applications aim to isolate an upper or intermediate injection or production zone. Others need to isolate a damaged section of the wellbore or straddle a malfunctioning production packer. Still others provide a sealed velocity string or remedially install either flow control devices or sand control screens. A straddle option can provide the operator the option of prolonging the life of the well without the need of a workover. While a workover may well offer the most complete solution to the problem in hand there are reasons why a workover may not be the chosen way forward for the operator. These reasons may include logistics, equipment, time, matrix damage and cost, amongst many others.
For whatever reason, once a straddle option is selected, the choice of running an inflatable system will in all probability be based on the geometry of the wellbore. It would be very unlikely, for example, to select an inflatable system where a mechanical solution could be used.
The first deployment on coiled tubing of a thru-tubing inflatable element was undertaken in Alaska in 1986. Initial requests were to provide upper zone isolation in order to allow for coiled tubing treatment of the lower zone. In the intervening 15 years thru-tubing inflatable technology has advanced considerably with a market niche having been created. Today a thru-tubing inflatable tool exists for every known operation conducted on coiled tubing where more traditional remedial type tool systems exist.
It is now possible to plug, pack, squeeze, treat and straddle with an inflatable element on coiled tubing.
Fan, Jun (Chongqing Petroleum College, China) | Gao, Changliang (Shengli Oil Field, CNPC, China) | Taihe, Shi (Southwest Petroleum Inst., China) | Liu, Huixing (Southwest Petroleum Inst., China) | Yu, Zhongshen (Chongqing Petroleum College, China)
This paper presents an advanced dynamic model and computer simulator forunderbalanced drilling. The model is formulated based on the theory ofmultiphase transient flow referring to the drilling mud, water, oil, gas andsolid particles. All the important factors affecting underbalanced drillinghave been taken into account comprehensively in the model, including IPRrelation, physical properties and mass transfer behavior of fluids, flow regimeand phase migration features, geometry and deviation of wellbore as well as thedifferent operating modes which may be carried out in practical underbalanceddrilling.
A specific numerical approach is adopted for solution of the theoreticalmodels and on the basis, an advanced computer simulator is developed forundertaking simulation, study and planning of underbalanced drillingoperations. The computer simulator differs from existing simulators because itis fully dynamical and interactive with users. Researchers and users can changedifferent operating modes according to their will at any time during simulatingprocess just as they are really performing an underbalanced drilling operation.The simulator can track all the complicated and complex conditions inunderbalanced drilling process, and all the related parameters and profiles ofparameter distribution along wellbore at any time can be shown dynamically.
Through a number of simulating computations, tests and verifications, it isshown that the model and simulator are valid and in accordance with actualdrilling practice under different and complicated conditions. It is of greatimportance for consummating underbalanced drilling theory and on the spotapplication. A typical simulation result and case study are also presented inthe paper.
In some areas at present, underbalanced drilling is becoming an attractivepractice in drilling some oil and gas wells due to its great advantages overconventional drilling technology for detection and protection of potentialoil/gas bearing formations and for the purpose of promoting drilling andproduction efficiencies.
To meet the requirements of underbalanced drilling, some specific knowledgeand technology are needed and a series of parameters must be determined beforeand in the drilling process to control the pressure in wellbore. The complexityon the study of underbalanced drilling basically lies in the difficulty indescription and understanding of the physical and chemical natures involvingthe co-current flow of mud, water, gas, oil and solid particles in borehole.The flow patterns (bubble, slug and annular flow), mass transfer and migratingbehavior of each phase, influx features of formation fluids and the circulatingmedium (mud, aerated mud, foam and air/mist) as well as different operatingmodes and many other factors may directly govern the process of underbalanceddrilling. Although researchers have studied the issue for many years and anumber of models and simulators have been developed available for computationof underbalanced drilling, there are still some unsolved problems in this area.Underbalanced drilling is actually a dynamic process, any change of inputtedparameter and operating mode may directly affect the distribution of pressure,velocity, phase condensate and mixture density along wellbore, and hence,finally affect the pressure balance between bottomhole and formations.
The objective of our work in the paper is to develop a comprehensive dynamicmodel and an advanced computer simulator to study the complicated dynamicprocess and investigate the varying regularities of each related parameter atany locations and time under complex conditions in a typical underbalanceddrilling practice. On the basis, through a series of tests and verifications,the model and simulator developed in the paper may be expected to put intofield application practically.
The paper describes a new coiled tubing conveyed drilling technique, were several new well bores are jet-drilled perpendicular from the mother well and into the reservoir formation. This technology is targeted for Enhanced Oil Recovery (EOR) in both existing and new field developments. The objective is to improve the production profile around the mother well, by penetrating the damaged skin zone, and connecting to possible hydrocarbon pockets left behind in the reservoir.
The Bottom Hole Assembly (BHA) is configured to jet-drill several slim laterals, all in one coiled tubing (CT) run. This through tubing operation has the potential to create up to ten, 50 m long, and 1-2 in. diameter laterals at the exact desired depth in the mother well. The BHA consists of two main parts; a casing drilling machine and a high-pressure hose and jet-nozzle. The hose is spooled from the BHA as the lateral is drilled into the formation.
The main issues presented in the paper are:
The new jet tool functional characteristics
The theoretical aspects of jet drilling; penetration mechanisms and self-induced nozzle pull force
Laboratory experiments (confirmation of theoretical models)
The jet drilling effect on improved well production (production simulations).
The technology is an attractive substitute or supplement to acid and proppant fracturing, perforating services and conventional sidetrack drilling.
An important issue when stimulating a producing or injection well is to control the exact placement and direction of the treatment. This may represent a challenge in conventional fracturing and acid stimulation methods. Stimulating low productivity zones exposed together with good productivity zones represent in many situations a problem, since the treatment is improperly diverted into the low productivity zones. The stimulation fluid tends to flow into the good zones, which in many cases were not the target for the stimulation. Furthermore, fractures may open pathways along the casing wall, causing zonal isolation problems in the well. A variety of diversion techniques have been developed in the industry today, in order to achieve improved stimulation control. The success of these techniques varies.
This paper describes a technology that provides means for improved control of the EOR treatment. The technology provides real time signals, which acquires exact measurements of tool depth and direction. No pre-treatment activities, like pulling tubing (dependent on size), section milling and/or under-reaming is required prior to the jetting operation.
The tool will be a valuable supplement or substitute to conventional services like:
Conventional sidetrack, slim hole drilling.
The Jetting Technology Development Project - Definitions and Functional Descriptions
The tool is a coiled tubing conveyed electrical bottom hole assembly, designed and developed to create a number of laterals perpendicular to the mother well in one CT run. The laterals remain barefoot and are created by means of the jet-impact generated when pumping fluid at high pressure through the nozzle-head. The energy created when the fluid exits the nozzle-head is also providing the required forward force to pull the high-pressure hose into the lateral.
This case-history paper focuses on the evolution of a novel completion concept. The concept resulted from improvements in through-tubing vent-screen technology and the invention of a wireless casing collar locator (CCL) for coiled tubing (CT) operations. This completion method provides the following:
reduced completion costs
improved completion efficiency
extended completion life
reduced mechanical risk
improved reserve recovery rate
The invention of the wireless CT CCL was a key development that advanced this completion technique.
A new surface-modification agent (SMA) is at the core of this completion process. The SMA is a water- and oil-insoluble, resinous liquid additive that does not harden or cure under reservoir conditions. This additive is applied to proppant during the sand-control portion of the completion process to increase the cohesive forces between the proppant grains. The SMA provides the following advantages:
It can help increase pack permeability and porosity by up to 30%.
It helps control fines migration.
It decreases mechanical risk by helping stabilize the annular pack.
Tests have shown that using of SMA increases the critical flow velocity of the annular pack. It (1) allows the well to produce at higher rates without producing the sand from the annulus or (2) allows the operator to shorten the completion blank length at a given production flow rate, and (3) allows the length of the completion assembly to be reduced, providing flexibility that allows the completion method to be used on wells with closely stacked pay zones.
Before the development of CT CCL, operators had to use CT rigs with an electric line in the tubing to power downhole tools with perforating collar locators or gamma ray (GR) perforators. This system could triple or quadruple job costs. Wireless CCL allows accurate depth measurements with CT, making it possible to run guns and packers on CT with an existing GR CCL log as a reference. The CT CCL eliminates the need for e-line and reduces the completion time and daily spread cost. When the space limitations and the time required for repositioning the equipment for different phases of the operation are considered, the time associated with spotting equipment in offshore operations can be substantial. The CT CCL reduces completion time.
The following case histories describe economically successful jobs performed with these integrated services.
Over the past 5 years, emphasis has increased concerning the recovery of smaller segmented/stacked reserves in the Gulf of Mexico (GOM). The sands in these reserves are often stacked in various sized faulted blocks with reserves ranging from 0.75 BCF to 7 BCF. Fig. 1 (Page 6) illustrates the typical arrangement of these sands around a faulted structure. The use of 3-D seismic, directional drilling/logging technologies and better reservoir understanding has greatly increased the number of wells drilled through stacked pay zones. The single-trip vent-screen system has become a flexible, cost-effective, and viable completion method that is crucial for successfully harvesting stacked pay zones.
Rispler, Keith (Halliburton Energy Services, Inc.) | McNichol, Joanne (Halliburton Energy Services, Inc.) | Matiasz, Kevin (Halliburton Energy Services, Inc.) | Rheinlander, Mark (Quality Tubing, Inc.)
Coiled tubing (CT) erosion can occur during CT fracturing operations. Resulting wall loss and fatigue can limit CT life and prevent safe wellsite operations. An artificial neural network (ANN) has been successfully developed for accurately predicting wall loss resulting from erosion.
This paper presents a case history in which ANN technology was used to successfully manage tubing strings during CT fracturing operations. During these operations, wall loss affects CT pressure ratings, tensile strength, and fatigue, all of which are critical performance parameters used for determining CT life and identifying a safe operating envelope. An ANN can predict erosional wall loss and quantify critical performance parameters for specific applications.
Hydraulic fracture-stimulation treatments performed through CT provide a cost-effective method of stimulating wells in which producing intervals have multiple stringers. This technique is being successfully applied in many areas and is being used on a daily basis in the shallow gas fields of southern Alberta. Fracturing operations in these shallow gas fields typically require a 2 3 /8 -in. (0.203-in.) QT-900 tubing string that is 2,625 to 2,789 ft (800 to 850 m) in length. The zones targeted for stimulation are located at depths of 984 to 2,362 ft (300 to 720 m). Typical treatments involve three to eight stages in which a total of 110,231 to 220,462 lb (50 to 100 tonnes) of proppant is pumped. In addition, most treatments involve the use of a gas-assist with either carbon dioxide or nitrogen added to the stimulation fluid.
Operating within the safe working envelope of the CT is critical to the success of these operations. Wall loss from erosion affects operational CT parameters, and previously identified patterns of erosion 1 required a better understanding of this phenomenon. Three of the 35 strings used during CT fracturing operations performed in the year 2000 were evaluated for wall loss. Magnetic wall-loss detection was performed with Hall-effects sensors. The strings were measured at 82-ft (25-m) intervals and at 30° intervals around the circumference of the string. The data from one string clearly indicate maximum erosion loss on the outer radius of the pipe and minimal wear on the inner radius of the pipe ( Table 1). Wall thickness for all three strings is plotted in Figs. 1, 2, and 3. The wall loss from the tests demonstrates a repetitive pattern similar to those previously identified. 1 Pipe thickness affects critical CT operating parameters, including fatigue, internal pressure capacity, and tensile/compressive loading. A method for accurately predicting erosion could help operators use traditional CT pipe-management simulators to effectively manage CT fracturing strings.
Using an ANN to Develop a Wall-Loss Model
Several technical papers have been written about the development of ANNs. Neural nets have been given many different names, including black boxes, empirical models, universal approximators, and parallel models. The basic function of an ANN is to map data from one multidimensional space to another. Fig. 4 shows an example of a simple ANN with three inputs, two hidden layers with two neurons in each layer, and one output. The example has 12 unknown weights. The weights must be determined so that the inputs can be properly mapped to the corresponding outputs.
ANNs are constructed of neurons organized in layers. An ANN can consist of a single layer or multiple layers, and each layer consists of one or more neurons. Artificial neurons receive, consider, and calculate input from other sources. This information is then displayed by an algorithmic process or transfer function. The number of layers, neurons in each layer, and connecting transfer functions depend on the problem that must be solved.
This paper provides an explanation of the concept of the AG-itator, presents field performance results and examines the potential use of the tool in CT (Coiled Tubing) drilling and workover operations. The tool has been widely used as a solution to the major problems associated with slide or oriented drilling. The concept of the tool is based on reducing friction and providing accurate weight transfer to the bit. Typical applications include; sliding with a PDM-PDC combination where previously difficult or impossible; overcoming motor stalling problems; increasing ROP and extending the length of oriented intervals. The technology is to be developed as a CT tool and is expected to be particularly useful, as CT operations are characterised by constant non-rotation and high levels of friction. These two factors ultimately lead to helical buckling which can limit the effective reach of CT drilling or workover operations.
The fluid action of the tool creates pressure pulses that generate an axial force of approximately 15,000lb at a frequency of 16Hz (refer to Fig 1). These pulses gently oscillate the bottom hole assembly (BHA), reducing friction and improving weight transfer. In this way, weight is transferred to the bit, continuously and accurately without harsh impact forces. It has been demonstrated that the tools' fluid action is benign, as it has not damaged the bit, tubulars or more sensitive equipment such as MWD/LWD. Consequently, standard downhole equipment can be used with the tool.
It is argued that accurate weight transfer improves drilling performance in several ways (1) PDC bit life can be extended as the bit is prevented from constantly spudding into the formation. Additionally, both roller cone and PDC bits can be run without the risk of damage to bit teeth or bearings; post run bit characteristics have shown that no damage to the bit occurred as a result of impact forces. (2) Higher levels of WOB can be achieved using lower off hook weight. (3) There is reduced drill pipe compression as weight is transferred effectively and not dissipated at points where the BHA or drillstring hangs up. (4) Tool face control is enhanced. (5) Gross rates of penetration are increased.
Applications for the technology exist in all modes of drilling but usage appears particularly beneficial in non-rotating drillstrings and BHAs. Such applications are increasingly common as well profiles become more tortuous and the limits of extended reach and directional drilling are reached. Run data shows that the tool is a simple way of extending the reach and capability of conventional steerable assemblies. Accurate weight transfer and exceptional tool face control have been logged using PDC bits, even in significantly depleted formations after large azimuth changes. Intervals have been extended and drilled with higher ROPs while problems associated with setting and maintaining tool face have been minimised. The technology is compatible with MWD systems and is a viable means of extending targets whilst improving ROP, reducing rock bit runs and lowering the risk of differential sticking. Before assessing the use of the technology to extend the reach of CT BHAs, it is worth looking at field performance.
Extending the reach of Conventional Steerable Assemblies - A Case History in the Dutch sector of the North Sea
The 5 7/8" section of a development well was to be drilled in the Silverpit, Lower Slochteren and Westphalian formations in the Dutch Sector of the North Sea. The drilling objectives for this section were to build inclination from 42° to 84° at the top of the Lower Slochteren, and then to maintain a tangent before dropping angle to TD. The measured depths were recorded as 3,645 and 4,373 metres respectively. Subsequently, a sub-horizontal drain of 85° was to be drilled by a BHA incorporating the AG-itator (Refer to Fig 4). The purpose of using the technology was to provide accurate weight transfer to the bit during slide drilling, thereby minimising motor stalling, the BHA hanging up and to make tool face orientation easier.
This paper discusses recent coiled tubing (CT) cement squeeze planning and operations conducted in the Casanare Field in Colombia. Zonal isolation for gas shutoff was identified as a critical factor to help reduce the GOR for wells that would otherwise shut in due to gas handling limits of the production facility. The planning phase included a cement laboratory audit that was used to identify the reason for discrepancies of the cement design between the laboratory conditions and the full scale mixing trial. Voltage variation during laboratory tests was identified as a major factor which affected the mixing energy. Another source of discrepancy between the laboratory results and the sample batches with field equipment was the amount of energy imparted to the system by use of centrifugal pumps. Cement design properties were critical to achieve sufficient thickening time and filter cake quality in the presence of relatively high reservoir temperature and reduced formation pressure. Discretionary disposal of several batches of cement was required until those design parameters were met. Communication and crew training were fundamental to identifying and resolving problems, especially in an area that had not yet conducted this type of operation.
Normal laboratory tests were conducted that included all standard measurements of thickening time, density, fluid loss and rheology as well as a comparison of sample batches mixed with field equipment. The tests were used to define the slurry to be used in the field. However when the initial 2 batches of cement were mixed on location, they were rejected because they were out of range for fluid loss and filter cake thickness and hardness. A target of 5 API units was used to obtain consistency needed to duplicate field conditions (Figure 1). Although the filter cake height curve begins to stabilize at 2.5 API units, the fluid loss volume does not begin to stabilize until approximately 4 API units have been reached. A laboratory audit was conducted to identify the nature of the problem. It was determined that laboratory mixing procedures only yielded an actual value of 0.5 API units due to problems with the local voltage supply during the slurry preparation (Table 1). The laboratory tests were performed again with the same amount of additives as the original blend (but with 5 API units mixing energy) and found the range of error created by the voltage discrepancy yielded a fluid loss of 92 ml/30 min (155% greater than the target value) and a filter cake of 2.28 inches (240% more than the target value). This is due to a minimum amount of shear energy needed by the slurry to properly activate the chemical reaction of the cement and additives.
The other problem identified was a discrepancy in the mixing energy as the result of using the centrifugal pump to circulate the slurry after it had reached the target density with all the cement additives. Use of the centrifugal pump on the mixed slurry for as little as 12 minutes was found to decrease the thickening time of the slurry from 7.3 hours to 4.0 hours. This variation of thickening time was determined to be independent of use of additives since it was repeated with the same results both with and without cement additives.
Buenos Aires Y-7
The first well planned for a cement squeeze, Buenos Aires Y-7 (Figure 2), was scheduled for conversion to gas injection with a workover and would limit the risk associated with the coiled tubing operations. During initial well preparation, two cement slurries were discarded on site because they did not meet field quality control guidelines for rheology or fluid loss. Operations were aborted to review the quality control problems including an audit of the cement laboratory that indicated the local electrical supply variation as a cause of the discrepancy. A new cement design was tested and verified with a trial blend using field equipment.
This paper offers a critical review of the capabilities and limitations of coiled tubing as used in matrix stimulation. A method to determine the effective reservoir thickness that can be treated, as a function of coiled tubing size, wall thickness, yield strength, length and well depth is outlined. The method allows the user to push the boundaries of coiled tubing applications to its practical limits.
Coiled tubing is an established technology that has become indispensable to the petroleum industry. However, it is often used only for utilitarian tasks such as spotting fluids or circulating debris from wellbores. The complete domain of coiled tubing capabilities and limitations is not always taken into account during the design and planning process of drilling, completing and operating oil and gas wells. A lot of stimulation work has been done through coiled tubing, with little thought given to how effective the stimulation job will be, beyond simple placement of acid across the perforations and marginally into the formation at low injection rates. Mediocre stimulation jobs may be performed with coiled tubing, when better design work could result in more effective stimulation and lower zone-by-zone skin values.
For design and execution of any CT operation, it is important to understand the pressure and tension limits of the coiled tubing. As coiled tubing strings age, the maximum allowed operating pressure available may decrease. Larger CT sizes are in demand for new service requirements, pushing the technology closer to the tube material performance limits. Factors that affect safe operating life of a coiled tubing string are bending cycle fatigue, corrosion, pressure and tension limits, diameter and ovality limits, and mechanical damage2. CT is now in use in wells at greater depths >20,000 feet) and wellhead pressures >10,000 psi), pushing material limits even further.
In addition to coiled tubing capabilities and limitations, formation characteristics should be well understood. Ideally, formation properties such as porosity, permeability, lithology, mineralogy and acid response curves would be available for all significant target zones. With proper job design and zone isolation, the net formation thickness that can be effectively treated with a particular coiled tubing unit can be determined.
Coiled-tubing is always plastically deformed when it is used for well operations1. Since the shipping spool and work reel must be sized to accommodate transportation and CT unit configuration needs, the tubing must be bent beyond its yield radius of curvature and plastic deformation becomes unavoidable. For each trip into and out of the well (1 cycle), the coiled tubing is bent 6 times. Repeated coiling and uncoiling result in tensile and compressive stresses, beyond the yield strength of the CT material. This plastic deformation leads to cumulative and regressive changes in the material, known as fatigue and eventually fatigue failure occurs. Even though this fatigue is very real, there is no way of measuring it non-destructively. To ensure safety of operations, therefore, it is vital to understand the nature of fatigue, model coiled-tubing-life and set limits for coiled tubing use as it ages. Various methods exist, to estimate when coiled-tubing should be removed from service or downgraded to a lower category of service application. References 1 through 5 discuss these methods in detail.