This paper presents the results from series of experiments performed to study the effect of coiled tubing (CT) curvature on friction pressure loss of nitrogen gelled foam fluids. A ?-in., 10 ft of straight tubing and four sets of coiled tubing with curvature ratio (r/R) values of 0.01, 0.019, 0.031, and 0.075 are used in the experiment. A set of tests are performed using 20 and 30 lb/Mgal xanthan gum as base fluid and 0 to 80% quality nitrogen xanthan foams. Friction pressure data are gathered by monitoring the pressure drop across a 10-ft straight section and a given CT simultaneously.All data are gathered at ambient conditions and at a system pressure of 1000 psi. It is found that the friction pressure losses of nitrogen gelled foams in CT are significantly higher than the straight tubing even at low Reynolds number.The extent of CT curvature determines the magnitude increase in friction pressure loss. Empirical correlations for the prediction of friction pressure loss of gelled foams in both the straight and coiled tubing are developed for laminar, transition and turbulent flow regime.These are based on the dimensionless quantities of Fanning friction factor and generalized Dean number.
Laboratory sulfide stress cracking (SSC) tests were performed on specimens taken from a QT-900 coiled-tubing test string in an attempt to define zones of acceptable sour service. SSC tests were performed at room temperature in brine fluid environments with HS partial pressures (PHS) ranging from 0.01 to 10 bars and pH levels from 2.8 to 4.5. In addition, the effectiveness of a new inhibitor for crack prevention was tested. SSC testing, which included NACE Method A tensile, four-point bent beam and slow strain rate test specimens, were performed on as-milled as well as fatigue-cycled tubing. Fatigue cycling of the QT-900 test string was performed on a pressure bending fatigue machine with tubing samples cycled from 33% to 75% of average tested fatigue life. Test specimens were taken from parent metal, bias weld, seam weld (ERW), and butt weld locations. As a result of this test program, acceptable zones of service in sour environments have been proposed although further testing may alter boundary locations.
The properties of the circulation fluid have a fundamental effect on solids transport. The shear stress at the solids bed and liquid interface, for a near horizontal wellbore, plays the key role in transport of the solids. The flow regime, geometric combination of hole/coiled tubing (CT) and eccentricity, also effect the rheological state of the liquid and have a significant impact on the solids transport efficiency. There is a need to differentiate between the superior solids suspension capabilities of the liquid and its hole cleaning efficiency produced when it is in motion. The most important concept is that, the greater the solids carrying capacity a fluid has, the more efficiently the hole can be cleaned.The challenge that presents itself is that once the solids fall and form a bed within the wellbore, how can the solids be re-entrained and transported out of the hole?
In this paper, solids transport studies with several bio-polymers were conducted with a sophisticated flow loop. These studies highlight that these types of fluids bring some advantages and disadvantages. The carrying capacity and suspension properties of these fluids are superior but were hindered by other geometric influences on the velocity profile. Solids entrainment and re-entrainment into the fluid, as would be expected, is difficult to achieve without mechanical assistance.However, excellent efficiency of the fluid can be obtained and this paper presents some of the conditions under which this is practically achieved.
For a typical fill cleaning process, the CT tags the top of the fill, and is run into the hole to a target depth while jetting into the solids (penetration stage). The hole is cleaned by; either circulating a clean fluid while keeping the CT stationary (circulation stage); or by pulling the CT out of the wellbore with continuous circulation (wiper trip stage); or by a combination of these stages.
In past studies[1-4], several fluids have been used to conduct solids transport tests. Fluids previously examined are: water; 0.25% (by weight) Xanvis and 0.25% HEC gels. Based on these studies the following conclusions have been drawn.
Horizontal Flow: The properties of the circulation fluid have an effect on solids transport. The shear stress at the bed interface for a near horizontal wellbore plays the key role in solids transport. Therefore, the flow regime, geometric combination of hole/CT and eccentricity also affect the rheological state of the liquid and have a significant impact on solids transport. Furthermore, there is a need to differentiate between the carrying capacity of the liquid and the hole cleaning effect produced by the flow.
A consistent conclusion from the published references indicates that for a horizontal/near horizontal wellbore, hole cleaning is more efficient if a low viscosity fluid is pumped in a turbulent flow regime rather than a high viscosity fluid in a laminar regime. These previous studies are consistent with this trend and included a comparison of water, 0.25 % (by weight) HEC and 0.25% Xanvis polymers. The amount of solids that can be transported by a given volume of liquid is dependent on the rheological properties of the liquid. Xanvis and HEC polymer based fluids are more effective than water in terms of carrying capacity but unable to efficiently erode a stationary bed. (It is essential to keep in mind that CT is usually circulating the cleaning fluid at ‘low' flow rates). In general, it is not possible to achieve in-situ velocities in a casing or open hole that are high enough to exceed the critical deposition velocity.
As the number of deepwater installations increase, so will the number of coiled-tubing (CT) operations that are needed to support these deepwater fields. This need will grow significantly as rigs on spar platforms and tension leg platforms (TLP) are eventually demobilized for work on new installations, leaving CT as the most economical option for performing future well maintenance on these platforms.
The need to operate without a rig is a critical factor in the success of future coiled-tubing work in the deepwater environment. Rigless operation is complicated by the fact that each platform type has its own unique heave-compensation issues that must be addressed for an effective CT operation to take place.
An additional challenge to deepwater CT operations has been the assembly and installation of tension lift frames or heave-compensated jacking frames. This equipment is typically cumbersome and time-consuming to install and has many safety-related risks associated with the installation of coiled-tubing components.
A new coiled-tubing heave-compensation system has been created to address issues associated with rigging up and operating coiled tubing on deepwater installations. This system was designed with particular focus on operational safety and efficiency to meet the complete range of floating platform coiled-tubing deployment scenarios. There are three primary modes of operation. As a stand-alone system, it can operate as a heave-compensated jacking frame; with a rig, it can operate as a standard tension lift frame or as a self-compensating tension lift frame. The adaptive heave-compensation system uses automated process control to maintain wellhead loads within the American Petroleum Institute-specified allowable stress limits. A specially designed proprietary titanium flex joint incorporated in the system reduces the effect of lateral loads and bending moments transmitted to the wellhead.
The total heave-compensation package is composed of three skids (injector tension frame, blowout preventer (BOP) tension frame, and hydraulic power unit). The injector, gooseneck, and all well control equipment come preassembled within the injector and BOP tension frames. This improves the overall efficiency of the rig-up and eliminates most safety issues associated with the rig-up/rig-down process. The heave-compensation system not only improves the efficiency of the rig-up process but also makes tool changeouts more efficient.
The initial field test data and the associated job case history establish the benefit that this new heave-compensation system has brought to the deepwater market.
Santhana, Kumar (Petroleum Development Oman) | Van Gisbergen, Stan J. (Schlumberger) | Harris, Jeremy (Schlumberger Oilfield Services) | Ferdiansyah, Erik (Schlumberger Oilfield Services) | Brady, Mark Edward | Al-Harthy, Salah | Pandey, Arum
This paper describes new methods to economically improve production levels in one of the mature fields of Petroleum Development Oman. This field had been developed by infill drilling programs, which were suspended in early 2001 to review the development strategy.A reservoir management team set a challenge to effectively conduct logging operations and quickly utilize the data collected to identify and avail of optimization opportunities, thus maximizing the production of the wells whilst lowering overall costs.The optimization activity consisted of clean-out, saturation logging, perforation and stimulation. These activities were carried out either with coiled tubing only utilizing conventional practises and e-line coiled tubing, or with the combination of coiled tubing and hoist through multiple well entries. Both of these methods were successfull in that they resulted in incremental net oil production but at relatively high costs.
This paper presents a methodology which enables clean-out, logging, stimulation and perforation with one coiled tubing intervention, which includes a plastic coated "e-line" coiled tubing, coiled tubing perforating head and new perforation technology.All systems are in complete compliance with the most stringent safety criteria.The new method has a considerable time and cost savings impact, and this is fully illustrated in this paper with field trial case histories, in which a multi-disciplinary team effectively targeted the most suitable zones for perforation and stimulation using a state of the art self diverting, non damaging, acid system.Technical and economic comparisons are made with conventional practices.The methodology is currently being employed in this field and is potentially applicable to other fields.
Lesinszki, Allan (Talisman Energy Inc.) | Stewart, Clarence (Talisman Energy Inc.) | Ortiz, Avel (Schlumberger) | Heap, David (Schlumberger Well Services) | Pipchuk, Douglas A. (Schlumberger) | Zemlak, Kean James (Schlumberger)
Multilateral wells provide optimal recovery of reservoir pay and can become more prolific with stimulation or cleanout treatments.Downhole tools exist that index and allow the coiled tubing string to find and enter additional legs; however, they function using flow rate modulation.Any additional tool component beneath the multilateral tool that requires high pressure will suffer in performance because of the indexing multilateral tool.This technical paper addresses the performance of a new system that allows the indexing tool to find the lateral and then effectively treat the reservoir through the stimulation tool at the end.The entire cycle can be repeated for all laterals in the wellbore.
The results of field tests using this multilateral jetting system were similar to what was seen in yard tests perform at test facilities in Rosharon TX.Field tests showed that operating parameters produced clear indications that the system was operating correctly.All legs were efficiently and effectively treated to improve well production.Additionally, this system reduced the number of trips into the well from three to one, resulting in a 50 % reduction of time at the client's well site.
A key element of maximizing injection and withdrawal rates in gas storage fields is minimizing skin damage of the completions.A highly efficient completion technique can reduce the number of storage wells required to produce and refill a storage zone.It also reduces the cost of installation and operation of the compression equipment required to achieve commercial injection and withdrawal rates.The current completion methodology involves conventional overbalanced drilling through to the target zone.Casing is run and cemented from TD with communication to the reservoir achieved by perforating.Skin damage is typically reduced by flowback and acid stimulation of the well to remove drilling mud and filter cake.A different approach utilizing underbalanced vertical deepening, or "well finishing" with coiled tubing was employed in the Huntsman Storage Field, Nebraska and the Sayre Storage Field, Oklahoma in an effort to further reduce skin damage.The wells were conventionally drilled and cased to the cap rock of the storage zone then the final stage of drilling to TD was performed underbalanced by a coiled tubing unit.The storage zone was completed openhole.
The United States contains over 3.8 tcf of natural gas in over 400 storage reservoirs which acts as a buffer between steady production and seasonal fluctuating consumption.A key component of gas storage operations is maximizing the deliverability of a storage field either by increasing the number of wells or by improving the injection / withdrawal efficiency of individual well completions.This paper compares the conventional completion approach with the underbalanced well finishing technique.A comparison of initial well productivity, injectivity and withdrawal performance and total well cost is used to determine the most efficient completion technique.A total of seventeen wells completed in two separate storage fields using the underbalanced approach provides a large pool of data for detailed comparison with the hundreds of storage wells drilled and completed overbalanced.
Approximately 69% of gas storage reservoirs are sandstones and 27% are carbonates.The remaining 4% is a mixture of salt caverns and coals.  This case history focuses on sandstone gas storage reservoirs.High deliverabilities (injectivity and productivity) which make a formation ideal for gas storage are a characteristic of highly permeable (up to 1000 md) or fractured formations.Individual fields may have deliverabilities from 10 mmscf/d to 1.0 bcf/d.This very feature that makes reservoirs suitable for gas storage also makes them susceptible to damage from drilling fluids invasion and filter cake plugging.
An example is the Huntsman Field, located on the northeastern flank of the Denver-Julesburg Basin.This field is part of a northwest trending anticline. The zone of interest is the Third Dakota "J" Sand at a depth of 4,850 ft. The majority of the reservoir is a channel sand of moderately to well sorted, fine grained sandstone interbedded with thin shale lamina. The surrounding floodplain consists of ratty sand, silt, and mudstone.The "J" Sand storage formation is 50 to 80 ft thick with porosities ranging between 18-22% and permeabilities ranging between 25 to 1,250 md.
Complacency has little place in coiled tubulars. Here we describe the new techniques that are under investigation for both CT inspection and seamless CT production. The possibility exists to make tubulars by cold compression and to join by microwave sintering methods and amorphous bonding. The probability now exists to monitor all joining processes via the nondestructive acoustic emission technique, advanced ultrasound, and to eliminate the conventional tube-to-tube butt weld.
Fatigue life has always been a contentious issue. FLEXOR TU04 now predicts life with outer surface defects present, and is based on real data taken in a CTMRC study. Results of assessment of strings are given. Further, a non-contact NDE method exists for fatigue assessment, so that totally non-contact methods exist for the entire spectrum of CT evaluation.
Advanced ultrasonic methods are given for conventional and ADB joining methods. Finally an untethered robotic method for inspection of tubulars from the ID is introduced, and recent data are presented; this method is applicable to risers, refinery tubing, and other hard-to-inspect tubulars.
Seamless Coiled Tubing?
The possibility of making seamless (SMLS) tubing would eliminate the seam weld and the presence of the internal seam-weld flash.
The Penn State U and Dennis Tool (Houston) have been working on the production of SMLS tubing to ASTM 606/607 chemistries and 316L. Work in this area is proceeding under DoE contract DE-FC26-02NT41662 with the PSU as the principal contractor. The technique currently employs cold compression of the appropriate powdered metal, and it was originally proposed to manufacture from a slurry by application of 7 GHz microwaves (Fig 1a). An early example of a 1-ft. sample of 316L that was made from a slurry by cold compression is shown in fig. 1B. This sample tested for tensile strength as follows: YS = 41.9 kpsi, TS = 51.2 kpsi, YM = 17.6 Mpsi. Pieces were also tested using ASTM G311 and G1112 and performed well.
The cost of remedial work on marginal gas wells suffering from water unloading problems can be prohibitive, especially in an offshore environment.The expected financial return often does not justify the rig costs associated with pulling and running a new completion, while the formation damage caused by many well-killing methods can reduce the production potential of already marginal wells.
A Coiled Tubing velocity string can often prove a quick and cost-effective method of assisting in water unloading.The ability to work in live well conditions avoids damaging the formation, making it an ideal solution in many cases. However, the limited lifespan of carbon steel strings in corrosive environments calls for a different solution.The next option is often to run and hang off a chrome tubing string with a snubbing unit, which makes running corrosion-resistant tubing in live well conditions possible.However, the higher costs and increased time associated with a snubbing unit reduce its attractiveness.
The unconventional operational procedure of running corrosion-resistant jointed tubing with Coiled Tubing equipment has been used on few occasions to combine the benefits of Coiled Tubing and snubbing interventions. Although generally restricted to relatively short tailpipes, this method has on occasion been extended to running full velocity strings.The limited tensile load capacity of the externally flush threads has limited the length of the string in some cases.
A solution to this problem where a complex string is run in two independent sections has been applied in the field to increase the total velocity string length to 4115m.
The paper discusses the design and execution of the operation where Coiled Tubing and jointed tubing were used as a complex velocity string in order to restore production on a gas well, while retaining the full functionality of the downhole safety valve.Particular attention will be paid to the design of the string, which had to be tailored to remain within the operating envelope of the externally flush thread.
Today's drilling environments require a CTD bottom hole assembly (BHA) be designed to perform in harsh environment. These include drilling in Underbalanced conditions (UB), challenging formations and high temperatures. This paper details findings from Coiled Tubing Drilling (CTD) operations in Alaska, Algeria and Sharjah.
These challenging operations required a complex CTD BHA that should be capable of withstanding temperatures in excess of 150°C (300° F), severe vibrations, over-speeding of motors, high-performance positive displacement motors (PDM's), nitrogen intrusion in BHA and PDM elastomer as well as many other challenges.
As a result, the CTD BHA was engineered to meet these various challenges. For example, in order to reduce (or better manage) BHA dynamics under extreme vibration levels, a multi-axis vibration sensor was used to optimize the BHA with weight and flexible bars. This permitted the driller to monitor vibration levels in real-time and adjust drilling procedures and parameters (WOB, mud flow, use of circulating sub, etc.) to reduce excessive vibrations. The BHA also had to address telemetry issues and, on the Sharjah nitrogen-drilled wells, an E-line CTD BHA was employed as it was the only way to transmit MWD/LWD data in the multiphase mud flow.
The paper will also describe some of the special BHA features like multi-cycle circulating sub use, ECD/pressure management, high-speed motor use and more. And the results of these efforts will be documented with performance and vibration graph comparison.
In the previous two years, drilling processes on the Sharjah and Alaska wells were significantly improved for increased footage per day and lower overall well costs. As a result, these projects have been recognized as economic successes and the findings from these wells can be applied to optimize the drill string and drilling parameters for enhanced performance in other challenging environments.