Summary This paper describes the results of six microfracturing experiments in a gas well in south Texas. The experiments were conducted in open hole and during the drilling operations. Microfracturing consisted of pumping very small volumes of drilling mud (tens of gallons) at very low rates (3 to 30 gal/min [189 to 1892 X 10(-6) m3/s]). Three of these microfractures extended below the bottom of the open hole and were cored out. Created fracture orientation was obtained from the fractures observed in the oriented core. Several instantaneous shut-in pressures recorded in each zone showed variations of about 200 to 300 psi [1.4 to 2.1 MPa]. This magnitude change is attributable to heterogeneity of the rock. Measured values of instantaneous shut-in pressure (ISIP) did not show any trend with lithology (shale or sand-stone), mechanical properties, or tensile strength. properties, or tensile strength. Introduction The experimental work described in this paper answers two questions.In a given field, what is the orientation of induced hydraulic fractures?In a given field, is there enough stress contrast between adjacent zones for fracture containment? The method used is quite simple. Create a hydraulic fracture in the open hole while the well is being drilled. There is a good chance that the fracture will extend below the bottom of the hole. Core the bottom of the hole. Obtain fracture orientation by observing its direction in the oriented core. The advantages of this method of operation are that all the data are obtained very early in the life of the reservoir. Openhole fracturing eliminates the effects of casing and perforations on fracture orientation and pressure. Coring the fracture provides a very positive visual determination of fracture orientation. The petroleum literature contains many fine articles on the relationship between in-situ stresses and fracture height, the need for determining fracture orientation, and how such data can be used for optimizing reservoir performance. For the sake of brevity, this paper will not performance. For the sake of brevity, this paper will not include a literature survey or a discussion of why the experiments were conducted. The major emphasis will be on a more complete description of each operation and results. Veatch provides background information on hydraulic fracturing. Experimental Procedure All the experiments were conducted in a gas-producing well in south Texas. The well has two producing zones separated by shales. The experimental work consisted of creating microfractures in each producing zone and in the shale zones above, between, and below the zones. Oriented cores were also obtained from every fractured zone. These cores were tested for physical and mechanical properties as well as for determination of actual fracture properties as well as for determination of actual fracture orientation. The sequence of events for each microfracture was as follows.With the drillpipe out of the hole, the openhole packer was assembled. This assembly contained two Bourdon tube (BT) gauges that would record the fluid pressure in the drillpipe (tubing). The packer was attached to an anchor pipe. By changing the length of the anchor pipe, one can regulate how high above the hole bottom the packer will seat, thus regulating the height of the openhole section to be fractured.The packer was lowered into the hole with the drillpipe. Once on bottom, it was seated by application of a vertical force to the drillpipe.The surface lines between pumps and wellhead were pressurized to detect and repair any leaks. Next, the pressurized to detect and repair any leaks. Next, the drillpipe was pressurized to ensure proper seating of the openhole packer. A small pressure was also applied to the annulus to detect and repair any leaks.Microfracturing was done by pumping of drilling mud as the fracturing fluid. Specific details of microfracturing will be discussed later.After microfracturing, the packer was released and brought to the surface. BT gauges were recovered for later determination of actual bottomhole pressures (BHP's).An oriented core was cut from the bottom of the hole for physical and mechanical rock-property measurements, as well as for detection of fracture orientation. The following sections provide more detailed descriptions of some key operations. Wellbore Preparation. The hole was drilled and cased to a depth of 7,750 ft [2362 m] according to standard oilfield operations. P. 891
Backproduction of proppant from hydraulic fractures (proppant flowback) is a continuing operational problem in the oil and gas industry. Up to 20% of the proppant can be flowed back after the treatment. Curable resin-coated proppants are used to control proppant production, but are known to chemically interact with fracturing fluids and may be prone to several failure mechanisms. Curable resin-coated proppants also require either well shut-in or the use of activators at low temperatures. A new method to control proppant flowback relies on fibers mixed with the proppant to stabilize the proppant pack. The main advantage of this patented3 technology is that it is physical rather than chemical. Therefore, proppant flowback is controlled without specific shut-in time, temperature, or pressure constraints. This paper presents flowback results from fractures of dry gas wells (<1 millidarcy permeability) where fiber/proppant mixtures were used to control proppant flowback (11 cases). Fluid flowback rate, gas rate and proppant production were monitored during the cleanup period. These wells are compared to wells where either curable resin-coated proppants or no flowback control were used (15 cases). The fiber/proppant mixtures controlled flowback of proppant for both sand and ceramic proppants when used with all the proppant or in only the last part of proppant (tail-in). Flowback could begin right after the fracturing equipment was rigged down (15 to 30 minutes). Cleanup fluid flow rates were up to ten times higher than previously obtainable with curable resin-coated proppants and less proppant was flowed back. Faster flowback rates also resulted in earlier onset of gas production and reduced flowback time. Fibers allow greater latitude in flowback rate than curable resin- coated proppants without the need for shut-in time. Introduction Propped hydraulic fracturing is successfully used in many formations to enhance production. One associated problem is the backproduction of proppant during cleanup and throughout the life of the well (proppant flowback). Up to 20% of the proppant placed in the fracture can return during the cleanup period. The proppant that flows back has a detrimental wear effect on the production equipment. and requires the use of separators in the production line. Concern about proppant flowback can limit the flow rates during cleanup and production. Curable resin-coated proppants (RCP) are the predominant technology to control proppant flowback. They are used as all or the last part (tail-in) of the proppant in the fracture. The resin coating cures to form a strong proppant pack under conditions of sufficient closure stress, shut-in time, and temperature. Curable RCPs control proppant flowback in many cases but can have several disadvantages. They are known to interact with the fluid chemistry (pH, crosslinkers, breakers, etc.), can reduce fracture conductivity, and may be prone to failure under cyclic loading conditions. Further, RCPs need specific temperature, shut-in time and stress conditions to form a strong bond. Shut-in time can be as long as overnight, and at low temperatures (<150 F) additional chemical activators must be added to promote cure. P. 453
Members SPE-AIME Abstract This paper consists of three parts. The first part presents new type curves for a well part presents new type curves for a well intercepting a vertical fracture with finite conductivity. The type curves are for a well located in a limited reservoir and producing under constant flowing pressure. The second part describes how the type pressure. The second part describes how the type curves can be used in predicting and matching reservoir performance. Description of automated history match is also included. The match procedure considers the effect of turbulent flow inside the fracture as well as the change in fracture conductivity due to change in flowing pressure (crushing of sand). The third part of the paper presents application of the first two parts to actual field cases. The discussed procedure is applied to two gas wells in South Texas. The paper presents the following for each well:A prefracturing build-up test analysis.Fracturing treatment design.History match of production data calculating the fracture length and conductivity. Introduction Evaluation and design of hydraulic fractures located in a tight gas reservoir is one of the important aspects that concerns both service companies and producing oil companies. The conventional method of evaluating such a design is to run a drawdown or a build-up test after fracturing. Semi-log and type curve matching methods are then used to calculate a fracture length and conductivity. Because of the limited duration of these tests, the calculated parameters might not always be reliable. A different method is to use long-time production data. This technique is referred to as history matching. History match has a distinct advantage over the conventional methods for having much longer duration. On the other hand, it is much more difficult to perform. The topic of history match has been generally discussed in the literature. The use of type curves for predicting reservoir performance has been also recognized. performance has been also recognized. This paper presents new type curves for a fractured well, and discusses their applications in design and history matching. The paper basically consists of three parts. The first part of the paper relates to type curves for a part of the paper relates to type curves for a well intercepting a vertical fracture with finite conductivity. The well is producing at a constant flowing pressure and is located in a limited reservoir. Constant flowing pressure at the wellbore makes these type curves most suitable for tight gas reservoirs. In the second part, application of the type curve for designing a fracturing treatment is discussed. An example using type curves in designing fracture conductivity is reviewed. In the last part of the paper, the type curves are used in evaluating actual field cases. Evaluation is done by using the history match technique and is achieved using a non-linear optimization technique. A published method utilizing a non-linear regression technique is used to achieve a solution with least error. it is briefly discussed in the history match portion of the paper. Mathematical Model Describing the Type Curves Statement of the Problem The well is assumed to be vertically fractured in the center of a square reservoir and producing at a constant bottom hole pressure under unsteady state conditions. The formation has a constant height. The outer boundaries of the reservoir are no-flow boundaries. The fracture extends an equal distance on each side of the wellbore. The fracture is propped and has a finite capacity (W f K f). It propped and has a finite capacity (W f K f). It completely penetrates the formation in height. Other assumptions are used in developing the model. P. 189
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