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.
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 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.
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.
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.
Nondestructive Inspection of coiled tubing (CT) and coiled line pipe (CLP) is not only essential in assuring product quality, but also can be useful in determining physical attributes. In this paper are discussed some non-invasive methods that have been found to be useful in assessing these products.
Nondestructive Testing (NDT) offers some new, and several well-developed techniques for assuring product integrity in the coiled tubing (CT) and coiled line pipe (CLP) industries1,2 In this paper, we describe some of those NDT methods that may be used to test for potential problems in both new and used CT and CLP.
Many of the NDT methods used for casing, tubing, drill pipe and line pipe are applicable, with some minor modifications, to CT and CLP. Typically, electromagnetic and ultrasonic methods are employed, and are embraced in the Specification for Coiled Line Pipe3. Other methods are needed to detect or measure specific phenomena, such as accumulated fatigue, which are specific to coiled products.
This paper outlines some problems that have been solved and some recent results that have been obtained with coiled carbon steel tubulars. In many cases there are parallels with the inspection of typical OCTG and LP, while for others, some existing techniques that are used in other industries need to be evaluated for applicability to CT and CLP.
It is commonplace to use electromagnetic non-contact methods wherever possible because of the uncertain nature of the outer surface of the tubing, based upon concerns regarding an even transmission of ultrasound into and out of the tubing surface. Ultrasonic methods are used in special circumstances, such as tube-to-tube and pipe-to-pipe weld inspections. This paper will not cover existing in-line electromagnetic testing but rather some techniques and results that are currently being evaluated.
Requirements for Coiled Tubing and Line Pipe
In assessing the needs of the users of CT and CLP, one must look to how NDT methods can fit to CT and CLP specifications. Typically, the following questions need to be answered:
What are the most effective NDT methods to be used during tubing production, and at what sensitivity levels?
What are the most serious problems encountered in in-service performance of coiled tubular products?
What are the most appropriate NDT methods for detecting and measuring them?
Can fatigue in CT be measured?
How can fatigue and the results of NDT be combined to produce an accurate method of determining in-service tubular degradation?
Can radiography for weld inspection be replaced by other methods, such as ultrasound?
Can rapid prove-up methods evolve, so that new and in-service strings can be quickly verified?
What levels of qualification(s) and certification should inspectors hold?
This paper discusses some potential solutions.
Electromagnetic methods cover eddy current testing (ET), magnetic flux leakage testing (MFL), alternating current flux methods (ACFM), Barkhausen noise inspection, analysis of the hysteresis curve7, etc. Tubulars present a relatively special case because of symmetry, and are therefore often relatively easy to deal with by electromagnetic methods. Some examples are given below.
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 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.
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
Serious operational failure (SOF): 4 hr
Frequency of OFs defined as the sum of the Catastrophic, Major and Serious OFs per 1000 jobs (CMS/1000)
Impact of an OF on the treatment execution, determined by calculating NPT as a percentage of operational time.
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; a) Nozzle Type, b) particle size, c) fluid type, d) deviation angle, e) 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.
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 studies1-2, 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.
The flow loop shown in Figure 1 was used for this project. It was developed in a previous study1-2. 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.
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.
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.
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.