Hydraulic fracture initiation dictates the communication path between the wellbore and fracture plane. Nonplanar fracture geometries such as multiple, T-Shaped, and reoriented fractures are not advantageous and they adversely affect the potential to achieve a desired stimulation treatment. Oriented perforation can be the solution to initiate a single wide fracture in vertical and deviated wells. Also oriented perforations may be used to create stable tunnels in poorly consolidated formations thus avoiding sand failure and consequently preventing sand production. This paper presents laboratory experimental results related to oriented perforations for hydraulic fracturing. It also discusses the use of oriented perforation for sand control. Experiments were designed to investigate the effect of perforation orientation in vertical and horizontal wells on hydraulic fracturing treatment. Introduction Oriented perforation has not been widely applied in the industry due to practical difficulties involved in this process. However, more applications are becoming candidates for oriented perforation, i.e., fracturing deviated and horizontal wells, controlling sand production, and solving wellbore instability problems. The first work on the effect of perforation on hydraulic fracturing was presented by Daneshy who showed that the direction of induced hydraulic fracture is not dictated by perforation orientation. He showed that in many cases, fluid traveled from the perforation through the area between the casing and formation to initiate a fracture in the direction of maximum horizontal stress. Several authors showed that the perforation orientation in horizontal wells should be in phase with the anticipated fracture direction. Field observations on the effect of oriented perforation were reported for vertical and deviated wells. Venditto, et al. reported a field observation on a vertical well. P. 411^
This paper presents a new zeta potential altering system that is based on an inner salt developed to enhance the water flowback recovery on borate and slick-water frac jobs. The system also aids in the control of fines. The mechanism of this system is to modify the zeta potential on particles such as frac sand from -50 mV, or coal from -28 mV, to more neutral values. This modification helps increase the potential for particle agglomeration and changes in the sand pack in the fracture to increase fluid recovery and production.Results from lab studies have shown that the flow rate ratio for a 2% KCl solution through sand packs (treated/not treated) increased up to 45% when treated with 6.0 gal of chemical per 1,000 lb of frac sand. Similar results were obtained on conductivity tests using ceramic proppant, improving conductivity from 7,150 mD-ft to 11,387 mD-ft at 2,000 psi closure stress.This new system does not interfere with fracturing fluid rheological profiles for borate systems and improves friction reducing characteristics in slick-water systems.The system was tested in the field on a slick-water job, where the additive was mixed in the blender tub.
This paper discusses particular aspects critical to designing a successful fracturing treatment for higher permeability reservoirs with the objectives of stimulation anellor sand control. The process entails creating a short and wide fracture and packing it with multiple layers of proppant, possibly incorporating a. resin-coateQ proppant.Use of a reservoir simulator to predict or history match a pressure drop profile throughout a given drainage area will be presented. A fracture length can be determined from the pressure drop profile so that a near wellbore damaged area is bypassed and formation failure conditions are not reached. Types of failure mechanisms responsible for solids production formation are discussed. Pressure analysis during fracture packing is presented.A new technique to orient the perforations relative to the in-situ stress field for optimum fracturing treatment and sand control is presented. A comprehensive treatment design and operational recommendations are given. This paper includes the use of a three-dimensional fracture design model, proppant choice and scheduling, of carrier fluid and additives.
There is a general uncertainty regarding the issues affecting shale stability in gas shale reservoirs. True swellable smectite is not present in most of the reservoirs currently being exploited. Illite and illite/smectite are the principal clay components, and they do have a distinct fixed water of hydration which is salinity and cation dependent. Historically, two factors had a major impact on the choices made for clay stability in clay rich reservoirs. Today, many hydraulic fracturing treatments are conducted with virtually fresh water, so this comprehensive study was undertaken to identify the role of salinity on the stability of various gas productive shales. Evaluated were various inorganic salts, temporary clay stabilizers and permanent clay/shale stabilizers, and the results of the comparisons will be presented.The petrophysical properties of the samples studied have been extensively characterized and the swelling and erosional characteristics have been examined with capillary suction time (CST), roller oven (RO) and unpropped fracture flow capacity tests. Some shale samples are inherently unstable, regardless of the fluid used in the measurement, while the majority responds positively to more compatible fluids. A few samples are extremely stable in all fluids. The native state of the clay in the shales has been characterized by a variety of tests, including specialized cation exchange and wettability studies, to help understand the fluid/rock interactions.The results of this study have identified the relationship between clay stabilizer type and concentration on the stability of the shale and the impact on flow capacity in the "stimulated reservoir volume". This is a compelling story of rock/fluid interaction studies on actual cores, fit for purpose product development, and supporting field production results.
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.
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