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
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
The purpose of this paper is to share findings that resulted from a study of pressures recorded from bundle carrier and wash pipe gauges run during frac-packing operations. The original premise was to correctly evaluate and identify fracture pressure responses associated with the "tip-screen-out" techniques used for frac-pack placement. The first attempts at frac pack pressure evaluation were done using data collected from bundle carriers in the workstring. Once washpipe data was obtained, it was noted that the bundle carrier data was distorted by phenomenon below the gauges in the well bore. The fluid friction generated through the crossover tool and friction associated with the slurry path around the screen proved to be a source of the observed distortion. Data collected from bottom hole pressure gauges attached to the wash pipe below the gravel pack running tool indicated that in several cases the observed pressure increase is associated with friction and not from the fracture inflation associated with "tip-screen-outs." It was noted that serious swabbing effects can accompany the movement of the service tool. This swabbing has in the past been considered negligible. The swab effect can potentially damage the completion beyond repair. This swab can pull formation material into the perforations tunnels and annulus, creating a severe pressure drop through that portion of the perforated interval. The implications can be detrimental to well performance. Early BHP data collection altered procedures for service tool movement and provided insight toward correcting friction pressure calculations.
This is a study of height growth in nine (9) wells encompassing thirteen (13) productive intervals that were completed as frac packs. The data used to evaluate these completions include bottom hole pressure recordings during treatment placement, multiple radioactive tracer logs, production spinner surveys, pulse neutron logs, and production history profiles. This study addresses concerns about fracture containment near water and barrier integrity. The study also involves limited aspects of fracture completions in laminated reservoirs. The completions studied include high pressured formations, depleted low pressured situations, as well as normal pressure zones. Introduction There are copious publications discussing the issue of height growth in conventional hard rock formations. This work was initiated due to the perceived lack of available published data regarding height growth of fractures in soft formations requiring sand control. This data is presented to provide supporting evidence for addressing the following concerns:What can constitute a barrier in soft formations?How close to water can you place a fracture?Will fractures in soft formations connect laminated pays sections? During the review process, pad volumes, pump rates, and formation log character were related to the bottom hole pressures encountered during the placement of the fractures. Summaries of some of the zone statistics (Table 1), treatment parameters (Table 2), and the treatment results (Table 3) are provided. Production histories were compared to the placement pressures and production logs (pulse neutron, spinner surveys, and tracer logs). The soft formations referenced in this study are characterized as unconsolidated to friable, moderate to high permeability, and require sand control. Also low Young's modulus and high Poissonws#x0027;s ratio are common characteristics of these soft sediments. Hard rock fracturing requires significant propagation pressures which in turn requires higher stress contrast between layers to confine the fracture. If a sufficient stress contrast is not present, then the layer thickness must be great enough to avoid communication with undesirable formations to be considered a barrier. Conversely, the relatively low propagation pressures of soft formations coupled with only a small contrast in formation stress can result in fracture height confinement. The short fracture half length, relative to the perforated height, usually generated with frac packs also limit the height growth. Therefore, variations in formation character as well as small shale streaks, may constitute a barrier. Fracturing near water in hard rock formations is normally considered hazardous. Because high net pressures are required to overcome the tensile strength of the rock to propagate the fracture. The stress contrast required for containment is often exceeded, especially at the end of the fracture treatment. On the other hand, in soft formations there is very little, if any tensile strength, and the net pressures required to propagate and contain the fracture are very low. When low pump rates are observed, in conjunction with thin fracturing fluids, obtaining a fracture and controlling height growth is possible. P. 403
Soft rock fracturing popularity has resulted in its wide spread use for stimulated completions in sand control environments. Varying degrees of completion efficiency and production improvements have been observed. More importantly these variances have been difficult to explain. This paper explores anomalies in pressure behavior observed during step rate, calibration testing, and fracturing treatments. This investigation will focus on why the predicted and actual production rates as a function of completion efficiency and skin do not always match. Scenarios will be proposed which can explain both the pressure anomalies and the production variances. The scenarios are constructed using bottom hole pressure data, pressure transient analysis, and production prediction using system analysis. Introduction Popularity of fracture stimulation combined with sand control as a completion technique has grown dramatically in the Gulf of Mexico since 1991. Due to the pronounced success of frac-packing, this technique has become the preferred completion method in sand control environments with several operating companies. Although the frac-packing technique results in more efficient completions (lower skins) as compared to gravel pack completions, occasionally one yields an abnormally high skin that requires further explanation. After a review of 72 frac-pack completions performed across the Gulf of Mexico, 5 example fracture treatments were selected for this study. This paper presents pressure anomalies seen in pre-treatment testing and treatment execution, relating these anomalies to post completion production and completion efficiency. Evaluation of bottom hole treating pressures during fracturing operations in sand control environments has not been a highly publicized topic, particularly the subtle, atypical examples that result in poor, less efficient completions. Pressures used in this study were measured from (1) surface, (2) directly above the service tool (crossover tool), and (3) the bottom of the wash pipe. The results of the pressure analyses are used to explain production variances from the expected results. System analysis combined with the use of bottom hole pressure transient tests is used to fully develop a total picture of the completion.
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