TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater production in mature fields is a common situation. In many mature areas, every barrel of oil is being produced with six to ten barrels of water. The production of water results in increased operating expenses along with other water related well problems like scale, fines migration, sand face failure, water loading in wellbores etc.

Sand Jet Perforation (SJP) is a process which uses a high velocity jet of abrasive sand laden fluid to cut through the casing, cement and into the formation jetting pressure and cutting time can be varied to achieve maximum penetration. The process begins by using Coiled Tubing to convey, accurately position and operate the sand jet perforating tool with integral casing collar locator (CCL). The sand jetting assembly perforates the zone; the CT is moved uphole to allow an optimum fracture treatment to be pumped down the casing/CT annulus. Based on the difference in depth of the perforation interval between the zones to be fractured, the underflush volume for fracturing treatment is calculated to place a sand plug in order to isolate the zone at the end of the treatment. If this is not sufficient, the sand used for perforating the next zone is allowed to settle to form additional plug height. An added advantage of using this technique includes washing off the extra sand (if any) using Coiled Tubing in the same run, which leads to saving significant amount of time and eliminates the need of setting up expensive packers to achieve zonal isolation in multi-zone wells. With conventional wireline perforations, about 12 to 15 zones were usually fractured in a month in the Raniganj Coal Bed Methane (CBM) Block, India. The application of the above technology, made it possible to fracture more than 38 zones in a month. The process ensured that each zone received a positive zonal isolation and optimized fracturing treatment leading to cost effective and quality fracturing treatments. This paper highlights the sand jetting perforation process for achieving maximum penetration, advantages of the technique for fracturing in CBM wells and the planning involved placing sand plugs for achieving optimized and economic stimulation treatment.

A significant limitation in the application of coiled tubing technology is the ability of the coiled tubing to push. Push may be required to move a heavy bottom hole assembly (BHA) along a highly deviated or horizontal well. Push may simply be required to push against the drag forces induced by the coiled tubing's own weight, as it is run into a well. Either way, it is often important to know how far coiled tubing can be pushed into a well, or what weight/length of BHA can be pushed to a certain depth. Accurate modeling is required to avoid a costly mis-run with coiled tubing that fails to get to the necessary depth. Recent projects carried out offshore Brunei illustrate how critical accurate force modeling is and how small well factors can greatly affect the depth that coiled tubing can reach. This paper will also demonstrate how difficult it is to infer down hole drag conditions from surface readings unless the coiled tubing is nearing its point of maximum reach. Introduction An in-depth, theoretical engineering treatment of the buckling of tubulars supported within larger tubulars is not the subject of this paper. Other works have shown the theory behind this behavior1,2,3,4,5,6. This paper focuses more on the observed response of coiled tubing seen during specific campaigns of work and makes comparisons with an established, proven coiled tubing simulator. The campaigns involve running long lengths of perforating guns into newly drilled and completed horizontal wells. The guns were all run on coiled tubing, the perforating conducted in the balanced or underbalanced condition, using down hole formation isolation valves to deploy the guns in and out of the wells. Computer simulation modeling results are used to illustrate and quantify the effects seen during the actual work programs. The observations will show the following:Small changes in down hole conditions are not reflected significantly on the surface weight indicator, when the coil is an appreciable distance away from its maximum attainable depth.The same small changes in down hole conditions reflect significantly on the surface weight indicator, when the coiled tubing nears its final maximum attainable depth.Refining a computer simulation model using field data from shallow depths does not permit accurate estimation of what the maximum attainable depth will be.Estimation of chemically derived drag reduction effects, from weight readings at depths distant from the maximum attainable depth is inaccurate. Overview of the behavior of Coiled Tubing in Compression It is useful to have a simplified model in mind when considering what is happening when coiled tubing (or any other tubular) is pushed or placed under compression. Perhaps the simplest scenario to envisage is a perfectly straight section of coiled tubing, being pushed along a perfectly straight, horizontal well bore. This, of course, is a totally improbable scenario but is still valid for the purpose of creating a picture of the generic behavior of coiled tubing. Initially, as the coiled tubing enters the straight well, it simply runs along the low side of the well, the drag on the coiled tubing being equal to its own weight multiplied by the coefficient of friction between the coil and the well, µ. As the coil extends deeper into the well, the total weight of coil in the well increases and so, therefore, does the force required to push it. At a critical point, the coiled tubing will buckle; it will go from being perfectly straight, to form a spiral. In the same way that a small diameter rod will bow if a large compressive load is placed upon it, the coiled tubing will bow until it hits the inside wall of the well. The coiled tubing is prevented from bowing out a significant distance because the inside surface of the well cannot move. So our theoretical length of coiled tubing suddenly flips from straight to spiraled where the compressive load exceeds the critical buckling load for the coil. In this scenario, only the end being pushed will spiral as the compressive load at the free end remains under the critical compressive load.

Whilst the coiled tubing technology continues to emerge as a versatile solution in the industry, it is often perceived as an expensive option by many operators. Offshore coiled tubing operations are usually more challenging than land CT operations due to involvement of several additional issues like requirement of Support Vessel, tighter equipment lay-out, higher lifting capacity requirements on site, sensitivity to weather/sea conditions etc. which may also have significant cost implications. With the expanding drilling limits in respect of operating depths, well trajectories, down hole pressures, hole sizes and other operating environment, the resulting wellbores are becoming increasingly challenging to down-hole service operations. The inability of the conventional ways of down-hole intervention like slick-line and e-lines to service such wellbores is opening up newer dimensions for coiled tubing applications. To cater to these increasingly challenging expectations, the coiled tubing size is gradually expanding and the length is extending, both demanding higher lifting capacities and bigger space on location. There are various ways offshore coiled tubing operations can be managed, in some cases, even without a support vessel. However more often a support vessel is required for running smooth operation. There are various types of support vessels available in market from tiny little workboats to highly sophisticated service vessels. The economics of any support vessel strategy are often mistaken; a low cost vessel may not necessarily be an optimized solution in terms of the overall economics of operations. In continuous operations, it is also common to see that sometimes the rate of coiled tubing servicing over takes the rate of generation of work-load, thereby creating the situation of resource idling. The present work demonstrates an analytical approach in formulating the right strategy on support vessel for offshore coiled tubing operations. It compares and evaluates various alternative modus operandi of running offshore coiled tubing operations and work its way up to identify the most appropriate strategy in terms of overall economics and safety considerations. The work also evaluates the sensitivity of this strategy on several technical, operational, organizational and environmental parameters, which commonly surround the actual working environment. Background The present work describes a process of resolving the right support vessel strategy for offshore coiled tubing operations based on analytical modeling and our relevant past experience in south East Asia region. A brief out-line of the operating environment on which most data used in this work are based, is described below.Water depth ranging from 30 feet to 100 feet.Limited lifting capacity availability on offshore structures, usually 2 to 5 tons.Typical offshore structures composing of well platforms which have moderate sized work decks and usually accommodate about ten conductors and well jackets which are small tripod structures usually accommodate a single or a few conductors in some cases. Due to extensive presence of brown fields in the region, there has been a steady rise in the requirement of coiled tubing works over recent years. Common application includes but not limited to wellbore clean-outs, matrix acidizing and fracturing applications, water control treatments, CT conveyed through tubing perforations, horizontal well treatments, logging, manipulation of down-hole flow control devices, CT fishing applications etc. Since the lifting capacity available at offshore locations is usually very limited, a self erecting crane package is commonly utilized to undertake heavy lifts. These cranes are usually modular type cranes which consist of individual low capacity (LC) and high capacity (HC) crane modules. The modules can be rigged up on offshore locations in series without the need for any external lifting mechanism on site.

Brunei Shell Petroleum offshore well A was offline and shut in due to the 3 1/8" 5K lower master valve on the monoblock tree, being seized in the closed position, due to scale production. The subsequent loss of production was 200 m3 (1260 BOPD), with a monetary value of US$1.5 million per month at $40 per barrel. Two options were considered for recovering the well using well intervention techniques rather than a complete workover and well killing operation.Mobilize a "Gate Valve Milling Machine" the nearest being available was in Europe.Mill the Gate Valve with a coiled tubing unit, which was already on the platform, performing a stimulation programme on adjoining wells. Option one was expensive due to high mobilization costs, some HSE issues, well control but this was a tried and test method of remedying the problem. Option two was a somewhat untried operation, which had only been performed as far as BSP and the contractors involved knew, once before in the North Sea. Given the coiled tubing unit was already on the platform, and the specialist low speed high torque motors with an anti stall device and specialist mills were availed in the time frame required. The decision process based on HSE, engineering review (SWOP), and cost considerations, chose the coiled tubing option. The paper will examine the problem with the wellhead master valve, the HSE, engineering and cost decision process leading up to the decision to go with the coiled tubing option. The milling operation from programme inception to successful execution of the milling operation, and placing the well back on line, will review in detail. Other operators will be able to benefit from this safe, low cost and time saving method of recovering production from wells with similar problems, which are many around the world. SUMMARY In Brunei Shell Petroleum Offshore during routine wellhead maintenance the LMGV on Well-A was found to be seized. Given the well was online and producing then it was assumed that the valve had seized in the fully open position though no immediate means to confirm same were available. A number of attempts were made to free the seized valve by moving / turning the wheel handle but without success. Calcium carbonate scaling tendencies were identified as a likely cause of both the valve seizure and the progressive production decline observed since completion. As a result an HCL acid (15% pre-mix) soak treatment was performed pumping a total of 20–25 bbls acid to the wellbore. This wasn't successful in regaining movement of the valve and returning it to fully operable service. An HCL acid (15% pre-mix) soak treatment was repeated. Given the closed nature of the LMGV then the treatment consisted on this occasion of a series of smaller volume 1–1.5 bbls acid soak pills, which were pumped and left to soak on the top of the closed valve. Each spent pill was displaced after several hours via the flow wing outlet. The treatment was not successful in regaining movement of the valve.