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Abstract This paper describes a conceptual design of a subsea well intervention unit. The Intervention Service Unit (ISU) is a fit for purpose monohull vessel. Focus on operational efficiencies and cost reduction has been important in the design phase, while prioritizing solutions, which minimize health, safety and environmental (HSE) exposure. Scope of work for the ISU is wireline operations, coiled tubing and pumping services, subsea equipment installation and maintenance, well clean-up, testing and coiled tubing drilling. High operability in harsh environment, such as the northern North Sea, is a major design parameter. The general section of the paper explains the basic engineering execution and the overall specification structure of the concept, from the generic Functional Specification through the more detailed Building Specification. Some of the challenges which were identified and the unique solutions developed, are described. This includes work over open water and at elevated levels, splash zone issues, handling of heavy loads on a moving structure, amongst others. Introduction The importance of sub sea production is increasing. The most substantial reserves found over the last few years are in offshore environments. The oil and gas industry is facing a challenge because recovery rates from sub sea wells are lower than from wells with dry wellheads. One of the reasons for the reduced well efficiency is low intervention frequency as a result of high intervention costs. Numerous initiatives aimed at resolving this issue have failed. The ISU design team has been disciplined to cover only the defined scope of work for the unit, in order to:Secure optimised HSE solutions Design for high asset utilization, but not trying to cover all market needs Minimize capital investment Minimize operational costs by a fit for purpose and efficient topside arrangement. A new concept must be price competitive. The past has proven that it is not possible to continue the argument that price can be disregarded as long as efficiency is higher. The price can be divided into three main categories, the fixed cost component, the variable cost component and the profit element. The fixed costs include cost of capital and other costs running whether in operation or not. The unit cost to the service provider for this component can be derived from capital investment and other fixed costs, divided by asset utilization rate. This shows the need for focus on asset utilization as well as on capital investment.
- Europe > North Sea (0.54)
- North America > United States > Texas (0.29)
- Europe > United Kingdom > North Sea (0.24)
- (3 more...)
- Research Report (0.34)
- Overview (0.34)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Health, Safety, Environment & Sustainability (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea production equipment (0.91)
Abstract Coiled Tubing was introduced to the Karachaganak Field in 1997 as part of a package of technical enhancements designed to improve field productivity. Initially planned only for acid stimulation work during the summer, the service has been extended into an all year round support to the Workover, Stimulation and Well Service programs. Examples of the type of operations performed are described. These include tubing cutting, cleaning and acid washing as required to remove tailpipes during workovers. Fishing to clean up old wells prior to the workover. Inflatable packer isolations for acid stimulation and wellhead repairs. Introducing a new service, such as coiled tubing, to any location, presents an interesting challenge. Developing and applying the techniques within the service, particularly on an established, corrosive, gas/condensate production field with old, high rate, well stock, located in a remote area with extreme weather conditions, challenges the technical application of Engineers, operators and support services. Introduction The Karachaganak field was discovered in 1979 and is located in the Uralsk region of West Kazakhstan (Fig 1). This large gas and condensate field is a micro-fractured carbonate formation; pay height 100 to 600 meters at 4050 to 5250 meters true vertical depth with an oil rim. The structure is sealed with a salt layer that varies in thickness across the field from 10 meters to 4000meters. The field covers an area of 500 square kilometers and contains over 1200 million tonnes (9.4 billion barrels) of oil and condensate and more than 1350 billion cubic meters (48 tcf) of gas. Limited field production commenced in 1984. The reservoirs are Permian and Carboniferous in age and comprise low permeability limestone and dolomite. The reservoir fluid can be classed as highly corrosive, with high levels of both Carbon Dioxide (7.5%) and Hydrogen Sulfide (5%) see appendix 1 for further details. Karachaganak Integrated Organisation (KIO) participants are BG International (32.5%) AGIP (32.5%) Texaco (20%) and LUKOIL (15%), operating in Kazakhstan as Karachaganak Petroleum Operating b.v. (KPObv.) under a production sharing agreement since 1995. A major investment is underway to expand the field production facilities. Planned peak production after 2006 is estimated at 37000 tonnes (290000 bbls) of oil per day and 70 million cubic meters (2.5 bcf) of gas per day. The ability of the operating contractor to provide well stock for this expansion by working over old wells, drilling new wells and stimulating wells, has been enhanced by the introduction and development of coiled tubing techniques to the field well operations. Initial Coiled Tubing Services Well Operations requirements for the field can be split into four key components:-Well maintenance Well preparation for workover Workover and completion Stimulation. In the next few years vertical and horizontal deepening of existing wells and new well drilling are programmed. The utilization of coiled tubing will increase still further (Fig. 2). A single 1¼" coiled tubing unit was introduced to the field operations in 1996. This was part of an overall technology improvement programme agreed within the contract with the operator. Coiled tubing was identified as a means to increase production through stimulation improvements, mainly by washing the perforations with Hydrochloric Acid and removing drilling and workover damage. Field operations are limited by extremes in temperature (+40C in summer -40C in winter), site access to wells, logistics and technical support. In view of this the initial stimulation work was carried out in the form of a summer campaign. The scope of the initial coiled tubing services was designed to support only the stimulation component of the well operations requirements.
- Asia > Kazakhstan > West Kazakhstan Region (1.00)
- North America > United States > Texas > Dawson County (0.25)
- North America > United States > Mississippi > Marion County (0.24)
Abstract The excessive friction pressure loss due to the small tubing diameter and the curvature (which believed to cause secondary flow) of coiled tubing (CT) often limits the maximum obtainable flow rate in CT operations. This paper presents an experimental study of drag reduction performance of several polymer solutions in coiled tubing using a sophisticated full-scale coiled tubing test facility for an industry-university joint research project. The facility includes of seven reels of coiled tubing with diameters of 1", 1–1/2", and 2–3/8", fluid mixing and pumping equipment, and data acquisition system. Fluids investigated include water and solutions of polymers currently used in the well drilling and completion industry - Xanthan gum, partially hydrolyzed polyacrylamide (PHPA), guar gum, and hydroxyethylcellulose (HEC). Experimental results showed that the amount of friction drag reduction differs significantly among the different types of polymers at various concentrations. Data interpretation and analysis revealed that the CT diameter and the CT-to-reel drum diameter ratio are important geometrical parameters affecting drag reduction. The flow data indicate that the onset of turbulent flow in CT is suppressed in the polymer solutions. This paper introduces the concept of the modified drag reduction envelope for flow of polymer solutions in coiled tubing. Introduction Coiled tubing has found many applications in the petroleum industry which include drilling (CTD), cementing, wellbore cleanout, acidizing and hydraulic fracturing, etc. But, the excessive friction pressure loss due to the relatively small tubing diameter and the tubing curvature (which is believed to cause secondary flow) of the coiled tubing often limits the maximum obtainable fluid injection rates. A recent experimental investigation indicates that the frictional loss in coiled tubing is significantly higher than in straight tubing. One way to increase the injection rate and reduce pumping cost is to use drag reducing additives (or drag reducers). It has been found that typical drilling and completion fluids, usually polymer solutions, exhibit some drag reducing property. Therefore, it is of practical importance to investigate the drag reduction properties of these solutions in coiled tubing. There has been extensive research on drag reduction phenomena with dilute polymer solutions, soap solutions, or suspensions in straight pipe flow. But no information on drag reduction of polymer solutions in CT is available. In this study, extensive experiments using a full-scale coiled tubing test flow loop have been conducted for the joint industry research project - the Coiled Tubing Consortium at the University of Oklahoma. This paper presents the experimental results and the characteristics of drag reduction performance of typical drilling and completion fluids tested in the coiled tubing. Major factors affecting drag reduction performances are also discussed. Literature Review Frictional pressure in turbulent flow can be drastically reduced by adding small quantities of certain long chain polymers to the solvent such as water. This phenomenon is called drag reduction. Generally, credit is given to Toms for being the first to observe the phenomenon, therefore, drag reduction is also called Toms phenomenon. Toms was investigating the mechanical degradation of high polymer solutions in pipe flow. It was found that a solution of polymethyl methacrylate in monochlorobenzene required a lower pressure gradient than the solvent alone to produce the same flow rate. Several references that appeared in the petroleum literature indicate the importance and potential applications of drag reduction to this industry. Savins reported pipe flow tests using a number of synthetic and natural polymeric materials and three tubing sizes. Factors affecting the drag ratios were studied. He also compared the test data with Dodge-Metzner friction factor correlation and observed the "diameter effect".
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
Abstract 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. Introduction 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 damage. 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 Fatigue Coiled-tubing is always plastically deformed when it is used for well operations. 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.
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > Texas > Dallas County (0.28)
Abstract The impact of an operational failure during a coiled tubing (CT) intervention is typically more severe than that of other failures because of the nature of the activity. Failure of the tubing or any component of the well intervention process in a live well scenario can compromise well control and/or the safety of personnel. Statistics on causes of CT operational failures (OFs) indicate that a majority of these failures can be attributed to human error. Incorrect actions, or the lack of action, are very difficult to predict and therefore a major challenge to control. Running CT in and out of the well involves a high degree of human interaction and human fatigue, and short periods of inattention during this process are not uncommon.
During such activities, inattention can lead to actions that damage, kink or part the CT, with potentially disastrous results. Other causes for OFs include unintentional tensile overloads, overpressuring, runaways and other such events.
An electric over-ride device, developed for installation in the hydraulic circuitry of a CT unit, allows setting of limits on all pertinent operating parameters of the injector head. Setting equipment limits for weight, velocity and pressure gives the operator an extra set of eyes, greatly increasing operational safety and efficiency of the treatment.
This paper discusses OFs caused by human error and presents case histories that contributed to the conclusion of which parameters require control. The over-ride device used in the control process is discussed in technical detail, and case histories demonstrate the impact of its use on overall safety and service quality in the CT industry.
Introduction CT material failures have been an industry focus for some time. Comprehensive research in the failure mechanisms of the tubing steel has made the behavior of low-carbon steel fairly well known, and this behavior is well documented. CT failures are typically very serious, but they are not the only failures to consider. Total system improvement through better service quality is obtainable through an investigation of all failures associated with CT well interventions, including those caused by equipment failure or human error.
A database of companywide, in-house service quality statistics on OFs is used to identify problem areas. Data are drawn from worldwide CT operations for 2000 that represent a cross section of CT activites in the industry; shallow to deep land operations, arctic operations, offshore platform operations and deepwater work.
Coiled Tubing Failures
OFs that do not lead to injuries are not systematically or consistently tracked and reported across the industry. Unlike safety statistics, which are readily available in a standard format, service quality statistics are still very much organization specific and therefore do not allow for industry benchmarks.
Schlumberger has defined and adapted mandatory service quality indicators for all product lines. These are grouped in the following categories:Severity of the OF based on nonproductive time (NPT) and financial loss
Catastrophic operational failure (COF): NPT >48 hr and/or loss >$500,000
Major operational failure (MOF): 12 hr
Abstract As fields are becoming more mature and improved reservoir interpretation is identifying so-called "By-passed" hydrocarbons, more sidetracks will be required. Selecting a well to reach a certain target in the reservoir can be a long task as a number of issues have to be considered. Using an auditable process for selecting the optimum sidetrack method and the best wellpath to reach a certain target can take a drilling engineer several months on a multi well development. In order to optimise this process all of the relevant parameters have to be considered. An automated system using a database now allows quick identification of the correct sidetrack method and selects the most suitable wellpath for the sidetrack. This fully transparant method starts with the reservoir target and then works through all the issues associated with the well selection process. This paper describes the Candidate Selection Methodology, examples of the criteria utilised to evaluate the suitability of the Drilling Technique and examples of the speed of Selection for a candidate Well and the output of the process. Background As the North Sea Fields mature pockets of oil are becoming isolated and are decreasing in size. Because of this conventional methods are reaching their economic threshold. Increasingly operators are looking to alternative methods to exploit this stranded oil. Techniques such as Coiled-Tubing Drilling, Through Tubing Rotary Drilling, Hydraulic Workover Drilling as well as conventional drilling are being considered. The competent selection of the best method or combination of these methods from an operational, drillability and commercial perspective is now a necessity. In a multiwell field development where often 40 or more wells are drilled, selecting the best sidetrack candidate is a complicated task. Wells have to analysed on their function i.e. injectior or if producer then the relative worth and water cut should be considered. The well then has to be able to reach the selected reservoir target and then the mechanical aspects of the well have to be reviewed based on the drilling method selected. In order to facilitate this whole process a software system was developed which now allows a geologist or a reservoir engineer to select a target and provide the drilling engineer with a suitable target well. This elliminates a significant amount of time in the well planning process and allows infill wells to be planned better and faster. Development When initially designing the operation of the Well Analysis and Selection Process (WASP), the goal was to design a structured approach to planning Specialist Drilling Techniques and choosing the best candidate wellpath in order to achieve a successful operation. There was little experience throughout the North Sea with regard to these operations so it was essential that sidetracks planned using these techniques did not overlook crucial information. By automating the whole process, the Candidate Well selection can be mapped out. During the first stages of development, the tool was a spreadsheet listing the important information that could effect the success of the operation. Each element was given a complexity score dependent on the results obtained. The criterion was separated into two main sections one dependant on the condition of the existing well and the other, dependent on the engineering requirements for the proposed sidetrack. By mapping out each step taken, finding the best candidate/target option became faster and the process was transparent. If any of the information changed regarding the wells or a proposed sidetrack, then it was easy to go back and retrace the steps taken. The Well Analysis and Selection Process (WASP) is now a fully automated system using an Access Database and visual basic scripting. Well Analysis and Selection Process The Well Analysis and Selection Process (WASP) program (fig.1) was designed to provide a systematic and efficient technique of selecting possible candidate wells for Through-tubing Sidetracks using Specialist Drilling Techniques. The program compares various techniques such as Coiled-Tubing Drilling, Through-tubing rotary Drilling, Hydraulic Workover Unit Drilling as well as conventional Drilling Methods. The WASP program applies a systematic approach to select the best possible candidates within a well portfolio for a specified target. The candidate wells are then ranked by complexity. By automating the process the time taken to select these wells is significantly reduced and unsuitable candidates are rejected automatically in the early stages of the process. The WASP program runs in four stages:Find Wells within a given distance from a reservoir target. Operability - assess the complexity of access through existing completion and kicking-off from a selected point in the well. Drillability - assess the complexity of drilling from the kick-off point to the specified target using a specific drilling technique. Results - a ranked comparison of the overall Operability and Drillability results.
- Europe > United Kingdom > North Sea (0.87)
- North America > United States > Texas (0.68)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Etive Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/21a > Cormorant Field > Etive Formation (0.99)
- (5 more...)
Abstract Wiper trips are the current field practice to clean the hole for coiled tubing drilling or sand clean out operations. A wiper trip can be defined as the movement of the end of the coiled tubing in and out of the hole, a certain distance. In order to clean the solids out of the wellbore, a proper wiper trip speed should be selected based on the operational conditions. There is no previously published information related to the selection of the wiper trip speed. In this study, numerous laboratory tests were conducted to investigate wiper trip hole cleaning and how the hole cleaning efficiency is influenced by solids transport parameters such as;Nozzle Type, particle size, fluid type, deviation angle, multi-phase flow effect. The results indicate the following:Compared with stationary circulation hole cleaning, the use of the wiper trip produces a more efficient clean out. For a given operational condition, there is an optimum wiper trip speed at which the solids can be completely removed. Nozzles with a correctly selected jet arrangement yield a higher optimum wiper trip speed and provide a more efficient clean out. The hole cleaning efficiency is dependent on the deviation angle, fluid type, particle size, and nozzle type. Correlation's have been developed that predict the optimum wiper trip speed and the quantity of solids removed from and remaining in the wellbore for given operating conditions. The wiper trip provides an advantage for hole cleaning and can be modeled to provide efficient operations. Introduction Solids transport and wellbore cleanouts can be very effective using Coiled Tubing techniques, if one has the knowledge and understanding of how the various parameters interact with one another. Poor transport can have a negative effect on the wellbore whether it is for coiled tubing drilling or cleanouts, which may cause sand bridging and as a result getting the coiled tubing stuck. Coiled Tubing can be a very cost-effective technology when the overall process is well designed and executed. The highly deviated/horizontal well has placed a premium on having a reliable body of knowledge about solids transport in single and multi-phase conditions. In our previous studies, a comprehensive experimental test of solids’ transport for the stationary circulation was conducted, which included the effect of liquid/gas volume flow rate ratio, ROP, deviation angle, circulation fluid properties, particle size, fluid rheology, and pipe eccentricity on solids transport. Based on the test results the data was analyzed, correlation's were developed, and a computer program was developed. In this study, the wiper trip hole cleaning effectiveness was investigated with various solids transport parameters such as, deviation angle, fluid type, particle size, and nozzle type. Based on these test results, an existing computer program was modified and adjusted to include these additional parameters and their effect on wiper trip hole cleaning. Experimental Setup The flow loop shown in Figure 1 was used for this project. It was developed in a previous study. The flow loop has been designed to simulate a wellbore in full scale. This flow loop consists of a 20ft long transparent lexan pipe with a 5-inch inner diameter to simulate the open hole and a 1–1/2" inch steel inner pipe to simulate coiled tubing. The flowloop was modified and hydraulic rams were installed to enable movement of the tubing (see figure 2). The inner pipe can be positioned and moved in and out of the lexan to simulate a wiper trip. The loop is mounted on a rigid guide rail and can be inclined at any angle in the range of 0°–90° from vertical. When the coiled tubing is in the test section, circulating the sand into the test section and build an initial sand bed with an uniform height cross the whole test section. Then pull the coil out of the test section with a preset speed.
- Well Drilling > Pressure Management > Wellbore pressure management (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
Using an Artificial Neural Network to Develop a Wall-Loss Model for Coiled Tubing Fracturing Operations
Rispler, Keith (Halliburton Energy Services, Inc.) | McNichol, Joanne (Halliburton Energy Services, Inc.) | Matiasz, Kevin (Halliburton Energy Services, Inc.) | Rheinlander, Mark (Quality Tubing, Inc.)
Abstract 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. Introduction 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 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. 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.
- North America > Canada > Alberta (0.54)
- North America > United States > Texas (0.47)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
Abstract This paper describes the various steps involved to safely suspend a HPHT well and to repair a number of leaks in the production tubing. The tubing leaks were the result of corrosion and occurred over a two hundred meter interval. Thorough analysis and associated difficulties to resolve this problem lead to the approach of cementing the tubing in place. Thus allowing the operator to test this gas well and increase the knowledge of the reservoir to develop this field. The process and solution will be described in great detail and will serve as the basis for similar problems in the future. Introduction. The exploration group of the operator uses coiled tubing as a means to abandon exploration wells, which have been tested. The deep gas wells have high bottom hole static temperature and pressures and significant H2S and CO2 properties. Any operation in these wells cannot be considered to be routine and need to be planned in great detail. After going through a learning curve, the current technique of squeezing the perforations off with cement through coiled tubing is well established and has become a standard mode of operation. Being comfortable with the cementing practices, it was felt that cementing the tubing in place, followed with a cleanout for full bore access could safely repair the tubing. Background. This well was originally drilled end 1997 and tested on two formations (Buah and Amin) in 1998. The well was then suspended with the perforations cemented over the lower formation (Buah) and a deep-set plug in the top nipple at 4297.6 mahbdf. The Amin perforations were left open. The well bore was filled with CaCl2 kill brine, with a density of 13.5 kPa/m, the tubing retrievable sub-surface safety valve (TRSSSV) shut and a back pressure valve (BPV) installed in the well head. In September 1999 the well was re-entered with the aim of acidizing and consequently re-testing the lower reservoir (Buah) for gas inflow and reservoir performance. The deep-set plug was found to have been leaking, which resulted in half the tubing to be filled with gas. Debris was found on top of the plug and several attempts were required to pull the plug. An injectivity test was performed followed by a cement squeeze on the upper reservoir (Amin) into the perforations to isolate that reservoir. Milling with coiled tubing then started past the upper formation. After milling past the upper formation, a gas influx was observed into the tubing and a small pressure increase was observed on the annulus (~5500 kPa). A series of injectivity tests were performed with brine, which indicated significantly higher level of injectivity than expected (up to 200 l/min at a tubing head pressure of 7000 kPa) into the upper formation. During this period no change was observed in the annulus pressure. Although not optimal, the test programme did allow for a small influx from the Amin when re-testing the Buah so no further action was required at that moment in time. After completing the milling operation to beyond the old perforations of the lower reservoir (Buah) the reservoir was re-perforated. Going through the final checks before producing the well, it was observed that the annular pressure increased to 18,000 kPa with gas coming to surface. The testing operations were suspended and the tubing and annulus were killed by lubricating 13.5 kPa brine in the annulus. With the well stable, a flow test indicated that the pump rate on the annulus of 260 liter per minute (l/min) with the annulus and tubing pressure at a constant 4000 kPa. At this point the decision was taken to abort the test and suspend the well again. See appendix A for a well schematic. Securing the Well. A common practice for this operator is to suspend exploration wells that have been production tested, with a cement plug set with coiled tubing. Since the original plan was to test the lower reservoir and to shut off the upper reservoir a sand plug was placed across the lower reservoir and the upper reservoir perforations were re-squeezed with cement. This suspension allowed another possibility to isolate the Amin from the Buah in case of further attempts to access the reservoir later.
- Asia > Middle East > Oman (0.68)
- North America > United States > Texas (0.46)
- Asia > Middle East > Oman > Buah Formation (0.98)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Amin Field (0.93)
Abstract The original through-tubing window milling procedure was designed to run through 4–1/2" tubing, milling a window in the 7" casing below the tubing tail. The window was milled off a pre-set mechanical whipstock that was set on electric line before the coiled tubing unit was moved over the well. It generally took 2 to 3 mill runs before an effective exit window was obtained in the 7" casing. The goal of the project was to obtain an effective one-trip window exit. The milling assembly had to reduce the torque and work effectively with minimal weight on bit to allow deployment on 1–3/4", 2" and 2–3/8" coiled tubing. By milling the window in one trip versus 2 trips, approximately 12 hrs of rig time could be saved. Introduction Coiled tubing (CT) sidetracks (see Fig. 1) currently account for 50–60% of the total sidetracks constructed on the North Slope of Alaska. Approximately 75% of the CT sidetrack operations are conducted utilizing a mechanical whipstock through 4–1/2" tubing (3.82" ID), exiting through the 7" or 5–1/2" liner. The window milling operation accounts for 10–20% of the time spent on CT drilling operations. Conventional carbide mills used initially were very aggressive, causing numerous drilling motor stalls as the milling process was initiated. Equipment failures (motor rotors, stators and drive shafts) were directly related to the aggressive carbide mills and the effects of sinusoidal buckling. Two-Assembly Window Milling Operations Previous to this project, the 3.80" exit windows were cut in using a process that employed two bottom-hole assemblies (BHA's). Based on the proposed directional drilling plan, the whipstock depth was selected to avoid casing collars, corroded casing and troublesome shale intervals. The mechanical whipstock was set at the predetermined depth using an electric line (0.625" OD, 7-conductor line) logging unit. In high angle wells, coiled tubing was used to deploy the whipstock.After the whipstock was set, the CT unit was moved over the well and the milling operation commenced. Bottom hole assembly #1 was made up to mill the 3.8" OD exit window:3.80" OD Baker Carbide Dimple Mill (See Fig. 2) 2–7/8" positive displacement motor (pdm) 3–1/8" drill collars or 2–3/8" tubing (60 ft) Circulation sub (ball drop) Disconnect sub (ball drop) Coiled tubing connector or crossover to drill pipe. Seawater with polymer sweeps was used in milling the landing profile and the exit window. BHA #1 was run in the well and milled the profile nipple inner diameter from 3.725" ID to 3.80" ID. (Landing nipples are positioned 30–60 ft below the production packer.) Minimal weight on the mill reduced the risk of backing off tailpipe. (See Fig. 1.) After milling through the landing nipple, the assembly was run in the well to the preset whipstock. The window milling operation started off the mechanical whipstock. Due to the aggressive nature of the carbide mill, starting the window was the most critical part of the milling operation. After numerous motor stalls, milling/drilling proceeded to approximately 6 feet below the casing exit point. The average rate of penetration (ROP) while milling the casing was 1–2 feet/hr. After no further milling progress could be made or after 6 ft of new formation had been drilled, BHA #1 was pulled from the well.