This paper describes a one-step fracturing/gravel-pack (frac-andpack) completion procedure conducted on the BP Exploration Amberjack platform beginning in early 1992. This platform is 35 miles southwest of Venice. LA. The first four completions on this platform had an average positive skin values of 21. The goal of the frac-andpack procedure was to reduce these skins to nearly zero. In total, 24 frac-and-pack operations were performed. Details of the fracture design, pre fracture testing. fracture design and execution, and production response and a continuing optimization program are discussed. The fractures were performed with the screens in place with the gravel pack after the fracturing operation. The treatments were designed for the tip screenout technique 1 ,2 to create wide fractures and to provide proppant loadings exceeding 8 Ibmlft 2 .This paper presents the trend of the declining skin values. along with a discussion of time-dependent skins. The changes in fluids. breakers, and proppants are also presented. The average skin on 14 frac-and-pack completions was 5.3. The average skin on the final eight completions was 0.2. Design and ExecutionIntroduction. The BP Exploration Amberjack Project (Mississippi Canyon Block 109) is 35 miles southeast of Venice. LA. and 18 miles from the Mississippi River delta. The water depth ranges from 850 to 1,500 ftin the block. Acquired in 1983. the field is on the eastern side of the Plio-Pleistocene flexure trend of the Gulf of Mexico.A persistent problem with offshore gravel packs has been the presence of high positive skins measured on transient-pressure tests. Positive skins of 10 to 50 are routinely measured on all but very short intervals using state-of-the-art gravel-packing technology. Our early experience on the Amberjack platform showed a clear trend of higher-than-desired skins. On the first four wells. a viscous slurry prepack was pumped into the perforations. and after cleanout, the screens were run and a water pack was pumped. Studies have shown that using water as the carrier fluid provides a uniform, tight pack. Despite this, high positive skins were still measured.We think that a primary reason for the high skins may be that the prepack techniques currently used may not place sufficient sand in all perforations. A second and potentially more important reason is that the cleanout operation may destroy the hydraulic continuity between the perforations and the packed screens. Fracturing followed by gravel packing provides excellent vertical proppant distribution. This ensures that the connection among the formation, perforation, and packed screen is maintained if the operation is performed in one step. After a thorough review, a decision was reached to implement the frac-and-pack process with the screens in place.The fracturing treatments were performed with the screens in place, the crossover tool in the circulating position. and a closed choke on the annulus. The desired proppant volume is placed at fracture rates followed by an appropriate gravel-pack volu...

Since its introduction almost 50 years ago, hydraulic fracturing has been the prime engineering tool for improving well productivity either by bypassing near-wellbore damage or by actually stimulating performance. Historically (and in many instances erroneously), the emphasis for propped fracturing was on fracture length, culminating in massive treatments for tight-gas sands with several million pounds of proppant and design lengths in excess of 1,500 ft. More recently, the importance of fracture conductivity has become appreciated. This has led to exciting "new" applications of propped fractures in better-quality reservoira as illustrated by North Sea wells, stimulations in Prudhoe Bay, and "frac-pack" operations in the Gulf of Mexico and Indonesia, Wldle better understanding and new technologies are being used today, the actual application of fracturing to higher-permeability formations is not new. During early development of fracturing, nearly all applications were for moderateto high-permeability zones (becimse low-permeability rock was of little interest at oil prices of $3/bbl).While tremendously succeaatirl at increasing productivity index (PI), these early high-permeability treatments were doing little more than bypassing damage. More recent development of improved, artificial proppant, cleaner fluid systems, and new technologies have changed this, makhtg it possible to alter reservoir flow and stimulate production from moderate-to high-permeability reservoirs. The primary new tool in the engineer's arsenal is the development of tipscreenout (TSO) fracturing. WMle higher-permeability formations provide the new applications, the actual philosophy shift for fracturing occurred with the massive tight-gas stimulations. Traditionally applied to fracturing of poor quality reservoirs, these treatments represented the first engineering attempts to aher reservoir flow in the horizontal plane. The development of TSO fracturing to allow creation of extremely wide, highly conductive fractures has extended this ability to alter reservoir flow to better formations. However, creation of artificial, highly conductive flow paths in the earth also creates an ability to alter reservoir flow in the vertical plane, opening the way for propped fracturing to evolve from a stimulation technology to a total reservoir-management ted This paper uses field examples to trace the history, development, and application of TSO fracturing to high-permeability formations, including fracturing to increase P]. as well as appl icatiorrs aimed at improving completions in unconsolidated sands. Potential applications of fracturing to bypass the need for sand control are explored. Finally, the use of fracturing as a reservoir-management tool is examined through use of a propped fracture to alter the vertical flow profile of a well to maximize reserves. This particular use of fracturing leads to cases where careful design of both fracture length and conductivity is required: i.e., too much conductivity is as damaging to reservoir management as too...

Summary This paper describes the measurement of proppant terminal velocity in a simple non-Newtonian gel during shear. The shear was imposed between Lucite™cylinders with the outer cylinder rotating. During rotation, a proppant particle was introduced and the terminal velocity was measured. This measurement then was compared with Stokes law measurement then was compared with Stokes law using the fluid's apparent viscosity at the known shear rate for the Newtonian viscosity. This results in a good correlation between measured and theoretical data. Introduction Most of the early work done on sand settling used vertical fracturing models. Kern et al.1 and Babcock et al.2 reported on tests performed in such models which defined equilibrium bank height and equilibrium velocities. Novotny3also used a vertical model in his proppant transport study. Wahl4 studied the transport of proppants in a horizontal model. A knowledge of particle settling velocity is a necessary input in all design techniques that describe the final location of proppants in the fracture. For Newtonian fluids, the measurement of settling velocity is straightforward since their viscosity remains constant with variations in shear rate. For these fluids, particle settling velocity will follow Stokes law for particle Reynolds numbers less than two. For all but very thin fracturing fluids, particle Reynolds numbers will be in this range. Under these conditions, single particle settling velocity will follow Stokes law:Equation 1 This is the settling velocity for a single particle in an infinite media. Most fracturing gels, on the other hand, are non-Newtonian in character and are considered to follow the power law:Equation 2 Under these conditions, Stokes law becomesEquation 3 From this equation, settling velocity becomes a function of shear rate. As shown by Novotny,3 shear rate (?) consists of two components: a horizontal component imposed by fluid motion and a vertical component imposed by particle settling. The vertical shear rate can be expressed by V/d, and the combined shear rate becomesEquation 4 This shear rate expression leads to an altered form of Eq. 3. For the fluids used in these tests, the vertical shear rate V/d is very small and can be ignored without significant error. The experiments conducted were designed to see how closely dynamic particle fall velocity would follow Stokes law for the shear rate range imposed by the test device. If the measured values agreed with Stokes law, only a knowledge of shear rate would be required to predict settling velocity. Novotny3 found a good correlation working with a similar tester. The fluids used in our test were somewhat more viscous than shown by Novotny.3

Members SPE-AIME INTRODUCTION: Several papers written since 1978 have addressed the importance of an accurate knowledge of bottom hole fracturing pressure. Nolte and Smith in 1979 focused industry attention on the value of this information in predicting fracturing conditions. By the proper predicting fracturing conditions. By the proper interpretation of the slope of log net fracture pressure versus log time, they showed that normal extension with confined height, fracture height growth with extension, loss of fluid loss control due to hairline fracture openings, and runaway growth of fracture height could be interpreted for fractures conforming to the fracture geometry of Perkins and Kern and Nordgren. Nolte in another paper, demonstrated that post-fracturing pressure decline data could be used to predict certain pressure decline data could be used to predict certain other fracturing parameters such as fracture height, leak-off coefficient, length, width, and closure time. Papers dealing with this technique include those of Papers dealing with this technique include those of Veatch and Crowell, Schlottman, et al, Dobkins Smith and Smith. Nolte, in 1982, wrote an excellent paper summarizing these techniques in SPE paper 10911, paper summarizing these techniques in SPE paper 10911, "Fracture Design Considerations Based on Pressure Analysis." Novotny also proposed a fracture closure model based on fracture geometry and leak off. Erdle, et al, discussed the results of an experimental program conducted in Peru that addressed the same topics. program conducted in Peru that addressed the same topics. The authors here will not attempt to review or expand on the interpretive techniques given in the literature cited above. This approach has been generally accepted by the industry and dealt with in an excellent manner by the authors listed. In the cited literature a reference string, either the tubing or the tubing casing annulus, was available to act as a monitor for bottom hole pressure behavior, that is the sum of the indicated surface pressure plus the pressure exerted by the pressure plus the pressure exerted by the hydrostatic head in the reference string is an accurate reflection of the true bottom hole fracturing pressure. The reference string, while desirable in terms of pressure measurement, presents some problems from both an operational presents some problems from both an operational and economic standpoint. In many cases the strength of the tubular goods is insufficient to allow the well to be fractured at meaningful rates with a reference string in the well. For higher pressured wells, treatment down tubing without a pressured wells, treatment down tubing without a packer is many times impossible without casing packer is many times impossible without casing rupture. In addition, unless the well can be placed in its final production configuration, the placed in its final production configuration, the expanse of tubing trips must also be borne. Where annular treatments are performed there is concern that the presence of the tubing may contribute significantly to shear degradation of the crosslinked gels and that injection rates using this configuration may be limited. In theory, it has always been possible to predict bottom hole pressure from surface pressure predict bottom hole pressure from surface pressure measurements since: P = P + P - P .....................(1) P = P + P - P .....................(1) bh s HH f Where is the total pressure due to friction including that due to perforations. While this seems essentially a very simple operation, it implies an exact knowledge of injection rate, sand concentration, and base gel friction. During an actual treatment these variables change quite rapidly with time so that, except at selected points, no coherent picture of bottom hole points, no coherent picture of bottom hole pressure behavior is possible without some means pressure behavior is possible without some means of sensing and averaging this data quite rapidly.

This paper presents a method of scheduling proppants in perfect or near perfect transport fluids to meet predetermined proppant concentrations in the fracture. factors affecting reservoir improvement are considered by one computer program.