The paper presents the findings of 20 completions in both oil and gas wells. These completions were performed from the period of 1973 through 1994. The early completions employed sand control technology of the 1970's and 1980's with most requiring acid stimulation immediately after sand placement to assure the removal of completion damage. The 1994 completions Involved fracturing combined with sand control (frac-packing) in the same reservoirs which had been gravel packed in the '70's and '80's.The unique aspect of this review is that these fracturing treatments were carried out using a solidsfree viscoelastic surfactant fluid. The fluid system is discussed along with the reasons why this particular fluid was selected. The implications that this fluid has on the fracture placement as well as productivity are discussed.Laboratory testing indicates that the solids based polymer fluids actually exhibit "deep bed" filtration and plug the formation pore throats, the fracture packs, and perforations. This damage can require acid stimulation for optimized production.The completion results are compared by use of a productivity index (J), normalized Jl\ and bottom hole pressure build-up analysis. 5%VESS

This paper discusses case histories of more than seventy completions requiring sand control. Approximately half of these wells were gravel packed (both slurry and water packs) between 1990 and 1995 while the remaining completions were fracture stimulated (frac-packs) from 1992 through 1995. The case histories include: geopressured oil reservoirs of moderate permeability, normal pressured high perm oil and gas formations, partially depleted high perm gas sands, and shallow dry gas formations. Results of bottom hole pressure transient analyses are included that compare skin values and completion efficiencies of both gravel packed and frac-packed completions. Production plots and decline curves are presented depicting accelerated as well as improved reserve recovery with the frac-packed completions. The associated costs of frac-packing is discussed along with a net present value analysis justifying these costs. Introduction The popularity of fracture stimulation combined with sand control as a completion technique has intensified in recent years. Due to the pronounced success of frac packing, this technique has become the preferred completion method in sand control environments with several operating companies. However, there has been some debate within the industry concerning the feasibility of this technique in moderate to high permeability formations. This paper reviews the results of one operator's experiences in a variety of applications, including both oil and gas reservoirs with permeability ranges of 3 to 4000 md and bottom hole pressure gradients of 0.17 to 0.84 psi/ft. The skin values of 35 frac-pack completions are compared to those observed in 29 gravel packs employing similar completion techniques with the exception of the sand control method. The relationship of skin damage to flow efficiency is also discussed. Several case histories confirm the theoretical calculations, comparing original gravel pack completions that sanded up to their subsequent frac-pack workovers in the same perforated interval. The rate acceleration and improved recovery of these direct comparisons is presented as well as the rig time and costs of the two different techniques. A comparison of productivity index (PI) and the improvement of PI observed over time in frac-packs is summarized. Finally, the economic impact of these improvements is evaluated relative to the increased cost of the frac-pack technique. Skin Damage The most obvious economic justification for frac-pack completions is improved completion efficiency (lower skin) and the resultant higher flow rates. P. 201

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSince its introduction, over 700 alternate path sand control completions have been implemented around the world ranging from single zone cased hole gravel-packs to multi-zone fracpacks and fibre optic (DTS) enabled open hole horizontal completions. Over the last six years, the alternate path system has been field proven to provide high reliability in achieving complete packs as well as additional features allowing simultaneous cake cleanup, shale bypass and other contingencies that enable "doing it right the first time" in deep-water/subsea completions where interventions tend to be economically and logistically prohibitive.This paper provides a critical review of those completions, capturing both successes and failures, along with the lessons learned in their design, execution and evaluation in relation to completion efficiency in sanding reservoirs. Furthermore, it details future development work and enablers that will allow the use of alternate path technology as the mainstay of intelligent well solutions, geometrical design improvements to provide optimal aspect ratios in the wellbore and its applicability in conjunction with water packing.

Fracpacks have become the completion of choice for deepwater wells due to concerns over loss of productivity associated with fines and sand production, limited rig availability and high intervention / sidetracking costs. Many deepwater reservoirs also require seawater injection in order to maintain reservoir pressure and increase the ultimate recovery of hydrocarbon reserves. This practice can significantly increase the potential for scaling, particularly the deposition of barium sulphate (BaSO 4 ) scale in reservoirs with high barium concentrations. Mechanical removal of sulphate scale at the reservoir level and / or from a damaged fracpack is not feasible. Chemical dissolution is not always practical, particularly in cases of high scale buildup. In these circumstances, little can be done to restore loss production except for pulling the completion or sidetracking the well. In either case, the consequences of sulphate scale build-up can be detrimental to the economics of the project, especially for high rate producer wells. For these reasons, preemptive scale management, most often in the form of scale squeezes, is a standard operating practice in high value wells susceptible to scaling. Deployment of a scale inhibitor concurrently with well completion operations is very attractive in that it delays the onset of scaling while providing a means for scale inhibition monitoring from the start of production. This not only provides adequate protection in case of early water breakthrough, but it also provides warning to plan and schedule routine well interventions, efficient utilization of resources (rig availability, workover crews, etc.), and better reservoir management. The addition of a phosphonate scale inhibitor into the pre-frac acid and overflush brine stages preceeding the frac operation was previously discussed in SPE 127768. As an extension of the previous work, a liquid pentaphosphonate scale inhibitor has been successfully incorporated into a seawater-based, borate-crosslinked frac fluid for fracpack operations in deepwater environments. Many challenges, including complex shear and temperature profiles, as well as potential incompatibilities arising from the interaction between the SI, crosslining agent / buffer package, and seawater were overcome by adjustments made to the crosslinking package, polymer loading, and fluid pH. The rigorous laboratory testing that led to the development of optimized fluid formulations, the assessment of scale inhibitor efficacy and formation damage potential is described herein.

This paper discusses hydraulic fracturing treatments for unconsolidated sand reservoirs. The procedures needed for selecting the appropriate candidate wells, designing successful treatments, executing them and evaluating the results, are presented in a format directly usable by the practicing engineer. Field examples illustrate some of the key techniques.