Most coiled tubing (CT) interventions are performed in a rigless environment. In fact, this is one of the important drivers for the widespread acceptance and continued growth of the technique for well servicing, especially in the offshore domain where the logistical costs are higher and operational challenges are more complex. Unlike land-based CT operations where integration is straightforward, the issues of equipment packaging for offshore integration is daunting. Overcoming limitations of crane-load lift capacity and deck space constraints are just part of the problem. Offshore CT units (CTU) are typically packaged as separate modules with components that require integration before any well intervention activity can begin. Rig up and operational efficiency are important design considerations for offshore CTU packages, but overall safety and regulatory compliance are of paramount concern. A new CTU configuration designed to meet the stringent demands of offshore CT operations was recently introduced. The design focused on key integration and HSE issues relating to the rig-up process. Results from more than 500 jobs performed during a 2-year period, in far eastern offshore environments indicated significant improvements in overall operational efficiency. In addition, the new designs met predefined HSE performance objectives, particularly during equipment rig-up phase. Introduction Since 2001, there has been a tremendous growth in the size of CTU service fleets. Based on an ICoTA survey, the total number of working CT units has grown from roughly 840 units in February 2001 to slightly more than 1,050 CTUs available worldwide in 2004. In March 2008, estimates for the global fleet size were reported at 1,500 units. During this period of growth, the scope of work for CT services also has continued to expand. This expansion brought some notable developments. First, the number of interventions increased in environments where standard CTU equipment packages were not intended to service, particularly in some offshore installations. The number of service quality incidents also increased, which resulted in several service delays. The failures are related to some degree to equipment packaging, but more so to the increased complexity in the performing these operations and to inexperienced younger service crews. Because most CTUs are provided by 3 or 4 large equipment manufacturers, the designs are very similar. Until recently, there was little need to radically evolve equipment designs. However, the well servicing environment is calling more and more for fit-for-purpose units, particularly offshore. From an equipment standpoint, addressing the challenges of offshore CT interventions currently is being approached in several effective ways and this has been the subject of previous discussions by Cochran (2008) and Andreassen (2004). The majority of these new equipment packages are customized insofar as specifications and features are concerned. However, the primary driver for customization is operational efficiency and overall safety.

Coiled tubing drilling (CTD) uses wireline inside coiled tubing (CT) for real-time downhole measurements and controlled actuation of the bottomhole assembly (BHA). In the CTD case under study, after several hundred thousand running feet, the wireline disconnected from its BHA anchor, resulting in lost communication and nonproductive time. By using the input of a CT integrity monitoring system based on magnetic flux leakage (MFL), it was shown that the CT experienced linear plastic elongation, resulting in the wireline being disconnected from the BHA anchor. CT pipe is fabricated from metal skelps joined together with bias welds. The pipe integrity monitoring system based on MFL was used from the first run of a CT string until its last run, before retiring the pipe. The system was originally designed to detect defects along CT string, but it can also analyze bias weld profile, which cannot be seen outside the tubing. Lengths of each metal strip were noted by comparing the distance between two bias weld points in the same run. CT elongation was then determined by comparing the length of each strip from initial and subsequent runs. This paper comprehensively studies CT elongation growth over each run and elaborates on the consequence of this elongation for CT operations using wireline or fiber optic cable (e.g., jeopardizing operations). The outcome from this paper helps to prevent recurrence by recognizing the root cause and modifying the slack management practices especially for this operation, which is sensitive to accurate slack calculation.

Petronas Carigali Sdn Bhd (PCSB) is one of major oil and gas companies in South East Asia. It has had years of experience operating coil tubing unit (CTU) on relatively large oil and gas field platforms. Vast of field experience and project lessons learned have been captured, refined and eventually embedded in the company's CTU standard operating procedures. These have lead to zero lost-time incidents (LTIs) cases in 5 years of CTU operations particularly offshore Terengganu in South China Sea. The CTU operations are often complex and involve heavy lifting, weighty machineries, minimal deck space and long working hours. Hence, to achieve such a record through out the 12 months in a year with 2 units running concurrently is definitely something to be noted. In February 2009, PCSB embarked on it first barge mounted CTU operation at offshore Terengganu. The option was choosen to access marginal field with small platform deck space and limited crane capacities. These include the process of lifting heavy equipment from workbarge with 60 degree angle to a 50 ft high platform during high swell, having to mobilize crews back and fourth from workbarge to platform and rigging up in dynamic condition. Furthermore, it was the first time the work barge crews experienced such operation and communication constraints due to remote and weather conditions further complicated the situation. Knowing that field experience is almost zero for mounted barge CTU operations in PCSB fields, resources and time has been put to ensure that the HSE track record is intact. Starting with Project Risk Assessment (PRA) which involved all contractors and field operator personnel, the team then analyzed of the whole campaign chain. This paper will review PCSB project success experiences and lesson learns on how to do CT operation from Barge within small platform during moonson season with high level of safety.

PETRONAS Carigali Sdn. Bhd. (PCSB) operates a handful of small platforms at offshore Peninsular Malaysia, in the Malay Basin area, located in the South China Sea. Most of these platforms were designed with limited crane capacity of maximum 5 MT load and small deck space area that only suffice to accommodate slickline operations. After many years of production, the fields have started experiencing sand production, high water cut and a large skin factor. Thus, well interventions and treatments such as matrix stimulation, water shut off or sand clean out are required to sustain and enhance the production rate.Coil tubing (CT) well intervention is the most effective method to achieve these objectives. However, with limited platform facilities, it is a tremendous challenge to have big CT equipments catered on board. The solution to this is to have a minimal number of equipments on the main deck whilst the crane lifting will need to be done from the barge. CT operation with barge assistance was evaluated and finally opted for to execute the jobs at PCSB's small fields. Throughout the operation, only the coil tubing injector head, jacking frame and CT control cabin were erected on the platform whilst the remaining equipments were stationed on the barge.As this was the first CT barge assisted operation in the Malay Basin of South China Sea, two platforms were selected for the pilot campaign. The jobs objectives include water shut-off, wax and sand clean out that has a potential enhancement of 1000 bbl of crude. This paper describes the operational success stories, campaign preparation, proposed work programs, barge selection, jobs execution and project lessons learned.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractSand production is a major problem in the oil and gas industry. Loss of production, sand disposal issues, the need for routine cleanouts, damage to well jewelry, and stuck well accessories are the most common reasons for setbacks caused by sand production. The sand control methods yield the most desirable results when are implemented early in the life of a well before sand production becomes a problem because of the onset of water production or before formation damage occurs as a result of formation disturbances or subsidence. For the wells that start sand production at a later stage, workover with conventional gravel packing is one way to alleviate the problem, but such a costly undertaking is not always economically justifiable.The candidate field is located at offshore Terengganu in Malaysia and has been in production since 1982. The reservoir consists of several layers, including the unconsolidated (J-sand) layer. Well A, for which the initial producing intervals were isolated, was recompleted in the J-sand layer by March 2005 and started producing 250 BOPD. Unfortunately, the well could only produce for 3 months before it was shut-in due to severe sand production. The well had been shut in for 4 years and even after a series of coiled tubing operations to perform sand cleanout, it was not possible to flow the well for a single day.Because of the marginal reserves available and the high cost of mobilizing a workover rig to perform a conventional gravelpack completion, the operator chose to recomplete the well using a rigless technique that allowed the gravel pack to be placed through the existing completion tubing.To ensure the best possible perforation packing efficiency and annulus pack quality, the "vent screen and isolation packer" through-tubing gravel pack (TTGP) technique was used. After the TTGP operation, production stabilized at about 180 BOPD. This method can be considered for the wells that are shut-in because of severe sand production and the wells that are producing at restricted production rates due to sanding problems.