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.
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.
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.
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.
Coiled Tubing (CT) cementing has been widely used and highly successful for remedial squeeze and plug back operations for over 20 year's[1,2,3].However, the vast majority of these wells were at deviations less than 90 degrees.
A long horizontal well in the Alpine field on the North Slope of Alaska was drilled early in the development phase and was out of pattern (Fig. 1).The well required a plug back and sidetracking to maintain desired off-take strategy (Fig. 2).The well was drilled to a total depth of 11,984 feet and completed with approximately 2,050 feet of 4-1/2" slotted liner inside the 2,210' of 6-1/8" hole.Near the middle of the horizontal section, the well's deviation climbed to a maximum of 96 degrees.
Cementing operations have long been recognized as a problem in horizontal wells.However, a search of the SPE online library identified only 5 papers that mentioned the challenge we faced while a search of "horizontal" yielded 5,534 hits.Although the 5 papers did discuss the problem and gave some general guidance to cement design consideration, there was little specific information on the "best practice" approach to Plug and Abandon (P&A) long horizontal wellbores.
Based on the successful CT squeeze program in Alaska, a team of engineers and field supervisors decided to use CT cement squeeze technology to seal the lateral portion of the wellbore and leave a cement base for subsequent sidetracking operations.This paper will discuss the details of this job including:
Cement design and testing
Tools and Equipment
Wellbore geometry and Placement details
Onsite Job Execution details
The operator, ConocoPhillips Alaska Inc., and partners in 1994 discovered the Alpine field.The Alpine field is located in the Colville River Delta a few miles south of the Arctic Ocean and approximately 70 miles west of the Trans Alaska Pipeline.The facilities are connected to the North Slope road system via ice road for approximately three months of the year.Aircraft provide the only mode of transportation at other times.Produced crude is transported to the Trans Alaska Pipeline via the East-West running Alpine and Kuparuk common carrier pipelines.
The reservoir was under-saturated at discovery with a gas oil ratio of about 850 SCF/Bbl.The produced oil gravity currently averages 39º API.As a result of the depositional environment and minor fault offset, excellent vertical permeability is observed and the productive sands are pressure connected across large distances.A "water alternating miscible gas" flood is being conducted in the Alpine reservoir.The field is developed with line drive patterns, utilizing horizontal producers and injectors in a one to one ratio (Fig. 2).
Given the high mechanical strength of the clean fine-grained Alpine sandstones, the operator elected to leave the horizontal sections on the wellbore uncased, to minimize the chance of formation damage.A 7.0" intermediate casing shoe is set just below the top of the producing formations at high angle.The uncased horizontal production hole typically extends 3000-4000 feet beyond the intermediate casing shoe.Production and injection tubing is primarily 4.5" although some lower rate wells are completed with 3.5" tubing.A production or injection packer is located a few hundred measured feet above the casing shoe.A typical Alpine well completion is shown in Figure 3.
While performing above expectations, this completion practice has proven to be a difficult environment to access.Early attempts at logging these wells using CT memory tools and conductor line tractors provided less than ideal results in reaching the TD in the extended horizontal open-hole sections.Drilling and formation debris and abrasive formations in combination with wellbore geometry limited our ability to reach the full measured depth of the lateral sections.Portions of open-hole lateral sections with fill or debris is not the only potential challenge to successfully cementing these wells; recent caliper logs suggest that the wells may also have sections that are washed-out or significantly out of gauge.
High Pressure High Temperature (HPHT) fields in the North Sea continue to both push, and ultimately extend, the boundaries of what can be safely and successfully achieved through intervention with coiled tubing (CT). Within the last six years successful CT deployed perforating operations have become relatively common. However, as more and more HPHT fields consider intervention operations, existing technologies are subsequently examined and re-examined to suit the particular well criteria and also the actual operating environment of the particular offshore installation.
This paper begins by discussing the types of equipment that are required for HPHT CT intervention. It then presents a number of recent case histories concerning CT interventions on HPHT fields. Three of these case histories involve different underbalance perforating operations. Case histories concerning cementing operations through CT are also discussed. The paper outlines the specific types of downhole equipment that are needed for these operations. This includes application of new equipment designs and novel solutions to both surface and downhole constraints.
Lessons learned from each of the case histories will be presented together with an overview of the requirement that HPHT fields and the related CT intervention technologies are moving towards. Conclusions will be drawn from these different case histories and a discussion presented on the potential extension for CT intervention in HPHT environments.
Drilling and workover rigs use a drawworks to pull up on the tubulars deployed into a well. The drawworks is attached to a mast or derrick, which in turn is supported by the ground or a floating vessel. The tubular's weight is not transferred to the wellhead.
Coiled Tubing uses an injector head, instead of a drawworks, to pull and push tubing in and out of a well. The injector is generally mounted directly onto the wellhead, unavoidably transferring some of the reactive loads to the wellhead.
These loads can be very substantial. They not only include the tubing's weight in the well but also loads generated by the Coiled Tubing on surface, that tubing which is being bent and pulled sideways. Often additional support is required to at least partially isolate these loads from the wellhead. This paper identifies the various loads that Coiled Tubing imparts to a wellhead and how support mechanisms provide protection to the wellhead.
Coiled tubing (CT) is being pushed to the limits of its capability by the more complex and challenging nature of wells currently being drilled. Either the yield limits are being approached because of the extremely deep high pressure, high temperature (HPHT) wells, even with the use of 100,000-psi strength CT, or the reach capability is being surpassed by the long step out of horizontal wells. To accurately predict the results of such an intervention, the planning phase must include detailed modeling combined with previous experience.
This paper will describe the theoretical effect that static friction would have on CT well interventions and compare this with the actual values found through the analysis of data recorded real time on the same wells. Static friction will be quantified in a number of HPHT wells and the resulting effect on the force required to pull out of hole will be presented. Testing performed to evaluate the static friction through the stripper will also be presented. These values will be used to help ensure the CT well bore friction is accurately quantified.
This paper will discuss the development of abrasive cutting technology deployed via coiled tubing for cutting production tubing, drill pipe, drill collars, exotic stainless steel completion components, single strings of casing and multiple strings of casing.This technology is performed utilizing a sealed bearing, positive displacement motor and a cutting head along with conventional coiled tubing tools and conventional coiled tubing.This technology gives operators an additional tool when severing of the drill string or production tubing is required.
Additionally the paper will discuss perforating tubing and casing using abrasives, particularly in horizontal wells where conventional wire-line operations are not possible.
The paper will discuss:
Utilizing a positive displacement motor to perform abrasive cuts via coiled tubing,
Design and testing phases of the abrasive cutting system,
Initial field runs to prove the viability of this technology,
Total jobs completed to date,
Lessons learned throughout the process,
Where this technology leads from here.
The paper will also discuss future applications for this technology which include cutting casing for plug and abandonment programs, permanent packer retrieval, and abrasive perforating all deployed via coiled tubing.
Surjaatmadja, Jim Basuki (Halliburton Energy Services Group) | East, Loyd E. (Halliburton Energy Services Group) | Luna, Jose Balbino (Halliburton Energy Services Group) | Hernandez, John Oliver Estalilla (Halliburton Energy Services Group)
The use of coiled tubing (CT) in fracturing was uncommon until a few years ago. Its applications have usually been limited to small jobs, and in reality, CT stimulation treatments have often been limited to acid placement treatments. With the inception of hydrajet fracturing technology, the use of CT has become more popular. Historically, CT fracturing methods were limited to placement of small fractures in the formation, and in some acidizing situations, near-wellbore damage-bypass methods.
CT technology has progressed until now it is used to place large fractures, some reaching over 600-ft half-lengths. Obviously, in most formations, such fracture sizes would not be possible with fluid delivery originating from the CT alone, so the use of the annulus to deliver the primary fracturing fluid becomes vital. This paper discusses the knowledge gained from recent field applications that have used this new annular path hydrajet-fracturing technology. Unique features of this technology are presented. Added benefits, such as the ability to deliver large proppant volumes, will be a focal point of this paper.
Case studies involving placement of multi-fracture treatments in three wells treated with this procedure will be discussed. Production improvements experienced in these wells will also be presented.