TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCoiled tubing (CT) is widely used in well intervention as a practical and cost-effective means of servicing wells. Over the years, the actual flow through CT has been a point of discussion and theory. Testing has been conducted to promote a better understanding of what happens inside the CT. In recent years, the use of computational fluid dynamics (CFD) software has provided greater insight into actual CT flow patterns, including fluid-flow velocity profiles and secondary flow regimes. These flow patterns can be studied in a straight pipe or curved (CT) condition with variable flow rates and variable fluids. CFD could help us understand the phenomenon of erosion, including particle path and migration through the tubing. It might also lead to a greater understanding and efficient design of friction pressure gradients. After CFD is proven and established, an alternative to full-scale testing or other predictive methods may be possible.This paper discusses the flow phenomenon of CT using CFD, particularly over the tubing guide. This is an area of concern because the tubing configuration changes from straight to bent to straight again. Details of fluid flow for both the straight and curved sections have been examined to evaluate flow-velocity profiles and flow patterns. Fluids investigated have included water, gel, and slurry.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCompared with conventional tubing fracturing, coiled tubing (CT) fracturing has several advantages. CT fracturing has become an effective stimulation technique for multi-zone oil and gas wells. CT fracturing is also attractive production enhancement method for multi-seam coalbed methane wells as well as wells with bypassed zones. The excessive frictional pressure loss through CT has been a concern for CT fracturing. CT strings have small diameter and this limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and hence results in extra flow resistance. This increased friction pressure results in high surface pumping pressure. The maximum possible pump rate and sand concentration, therefore, have to be reduced. To properly design a CT fracturing job, it is, therefore, essential to be able to predict the frictional pressure loss through CT accurately.This paper presents two correlations for the prediction of frictional pressure of fracturing slurries in coiled tubing. One is developed based on full-scale slurry flow tests with 1-1/2in. coiled tubing and slurries prepared with 35 lb/Mgal guar gel. The extensive experiments were conducted at the fullscale coiled tubing flow test facility. The other correlation is derived from the Srinivasan's friction factor correlation of Newtonian fluid in coiled pipes. The Srinivasan correlation is modified for the non-Newtonian fluids and it further requires an inclusion of the relative slurry viscosities which have been thoroughly evaluated in this study. The proposed correlations have been verified with the experimental data and actual field CT fracturing data. Case studies of wells recently fractured using CT are provided to demonstrate the application of the correlations. The correlations will be useful to the CT engineers in their hydraulics design calculations.

This case history paper presents fracture stimulation using coiled tubing (CT) hydrajetting, followed by (1) annular-path pumping of the fracturing treatment and (2) use of high-concentration proppant slugs to create proppant plugs for diversion. The process of hydrajet perforating and annular-path pumping (HPAP) has been used effectively for vertical well completions and is especially applicable for multi-interval completions. Further, use of this process for multi-interval fracturing of horizontal well completions has been performed successfully in several North America reservoirs, and in Texas at depths below 15,700 ft true vertical depth (TVD) and measured depths (MD) of more than 16,700 ft. Cased and cemented horizontal completions present several challenges for the HPAP method, including (1) unique CT calculations and operating procedures, and (2) proppant plug-setting procedures. This multi-stage completion process can also be applied in other methods of horizontal completions that incorporate a solid liner. Several case histories are examined to (1) highlight lessons learned in performance of this method on horizontal well completions, and (2) demonstrate efficiencies gained as compared to following conventional practices. Introduction Fracturing methods aimed at improving operational efficiency by reducing nonproductive time (NPT) have increased in importance as assets are being completed that involve multiple intervals, thick pay intervals, or horizontal wellbores (McDaniel 2005). Some of these methods, such as the use of high fracturing rates and limited-entry perforating, greatly reduce the overall completion time but have been shown to be less than adequate in stimulating all targeted intervals (Craig et al. 2005). Other fracturing methods that focus on treating intervals individually can result in many hours of NPT mainly as a result of discrete process steps that require trips in and out of the well between treatments while pumping equipment resources remain idle or are required to leave and return to the wellsite. These discrete steps include trips for (1) perforating, (2) setting or moving tools such as bridge plugs, and (3) wellbore cleanouts. In the late 1990s, a hydrajetting process (Surjaatmadja 1998) called hydrajet-assisted fracturing (HJAF), using dynamic diversion, was introduced to the industry as a means of treating horizontal wells, in particular openhole horizontal completions (Surjaatmadja et al. 1998; Love et al. 1998; McDaniel et al. 2002). The benefits of this process for reducing NPT were readily apparent and horizontal completions involving 20 separate fracture treatments in a single well have been performed in just 2 days of daylight operation (East et al. 2004). The process uses hydrajet perforating and HJAF, which eliminates a separate trip into and out of the wellbore (Fig. 1). The numerous advantages (and some limitations) of using hydrajetted perforations instead of explosive/shape charge perforating has been recently reviewed extensively in a recent paper (McDaniel et al. 2008). Because the HJAF process relies on dynamic diversion, no mechanical plugs are required to furnish diversion between intervals being treated. Therefore, there is no drilling of plugs or plug-retrieval operations after the treatments have been performed, further reducing NPT in the completion process. The HJAF method allows for recovery from premature screenouts because tubulars are in position for rapid cleanout of excess proppant at each stage of the fracturing and perforating process. This is particularly beneficial when aggressive proppant schedules are required, such as in the case of frac-pack or tip-screenout treatment designs.

Proposal Numerous oil-producing wells in Southern Oman are completed with wire wrap screens (WWS), internal gravel packs (IGPs), and predrilled liners. These wells produce from mature clastic formations where fines migration and subsequent blockage of screens can result in impaired oil production. In the past, conventional treatment using coiled tubing and a jetting tool has been chosen to remove this damage. The gains resulting from these intervention activities were more often than not short-lived. This lack of longevity required frequent well intervention and oil deferment, often resulting in a loss of revenue. Recently, a systematic approach was undertaken to evaluate the wellbore cleaning and stimulation tools that are currently available in the industry. This approach was implemented as a trial of three cleanout tools in oil-producing wells. This paper describes the results of using these tools for cleanout and stimulation of sand screens. Excellent success was achieved with a pulse-jetting tool operating on the Principles of Coanda effect. This tool is further described in the following sections, and results of its use in a number of oil-producing wells are presented. The effect of the cleanout procedure is presented in terms of initial production and sustainment of production level. This paper also outlines the importance of using proper cleaning and/or stimulation fluid. To help avoid clay-swelling problems, special emphasis is placed on the brine fluid salt concentration. Based on the success it has achieved, the pulse-jetting tool is now a standard tool used in well interventions geared for wellbore cleanout and/or stimulation. The versatility of the tool enables it to be deployed for use with coiled tubing or regular workover strings. Many fluids, including nitrogen, can be pumped through the tool. This versatility is important because most of the wells are sub-hydrostatic and require the use of nitrified fluid to maintain circulation in case cleanout and well-lifting operations occur immediately after sandstone acid stimulation. Introduction Screens are installed in wells to prevent formation sand from being produced along with the oil. These screens, however, are prone to plugging, which in turn leads to reduced production. This problem is currently solved by bullheading brine into the annulus, which flushes the sand off the screen face when coiled tubing units are not available. Although this treatment is cheap in restoring some of the productivity, it is ineffective with short-lived gains, very localized, and needs to be repeated every three months. Frequent application of bullhead treatments can increase the risk of formation impairment and associated reduction in production. To help avoid these problems, three cleaning tools from different service companies were used and evaluated: a rotational-cavitation jetting tool from Service Company A, a piezo-electric sonic tool (PST) from Service Company B, and a pulse-jetting tool from Service Company C. Results of the Trials Rotational-Cavitation Tool Trial runs of the tool were completed in 2001. Nine jobs were performed. In general, the initial cleanup of WWS generated oil gain and raised the fluid level for the wells. The increased production level was not sustained for more than one month in some cases, and after three months, all the wells had dropped in gross production. Piezo-Electric Sonic Tool Trial runs of the PST acoustic tool were completed in October 2002. Five jobs were performed. In general, the initial cleanups of gravel pack (GP) WWS generated oil gain and raised the fluid level for the wells (gross increased). The increased production level in three of the wells was not sustained for more than one month, and in the other two cases, no improvement in production was observed.

Compared with conventional-tubing fracturing, coiled-tubing (CT) fracturing has several advantages. CT fracturing has become an effective stimulation technique for multizone oil and gas wells. It is also an attractive production-enhancement method for multiseam coalbed-methane wells, and wells with bypassed zones. The excessive frictional pressure loss through CT has been a concern in fracturing. The small diameter of the string limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and results in extra flow resistance. This increased frictional pressure loss results in high surface pumping pressure. The maximum possible pump rate and sand concentration, therefore, have to be reduced. To design a CT fracturing job properly, it is essential to predict the frictional pressure loss through the tubing accurately.This paper presents correlations for the prediction of frictional pressure loss of fracturing slurries in straight tubing and CT. They are developed on the basis of full-scale slurry-flow tests with 1½-in. CT and slurries prepared with 35 lbm/1,000 gal of guar gel. The extensive experiments were conducted at the full-scale CT-flow test facility. The proposed correlations have been verified with the experimental data and actual field CT-fracturing data. Case studies of wells recently fractured are provided to demonstrate the application of the correlations. The correlations will be useful to the CT engineers in their hydraulics design calculations.