This paper describes a Friction Measuring Tool (FMT) and how it is used to estimate pressure loss from friction in the wellbore while a foam fracture treatment is being pumped. Combined with standard surface equipment, such as densitometers, flowmeters, and pressure transducers, this tool (located on the surface) offers real-time estimates of bottomhole treating pressures during the fracture treatment. Field examples are presented comparing calculated bottomhole treating pressures, based on the FMT, to actual pressures measured with downhole electronic pressure gauges (installed in the casing just below the treated zone) during stimulation treatments. In addition to the provided field examples which verify application of the FMT, the theory and mathematical background underlying the use of the FMT are described. Construction of the tool, actual use in the field, and trouble-shooting are also presented. This tool is also applicable to foam for coiled tubing operations or stable foam drilling. Development of the FMT is one product of a cooperative research program sponsored by the Gas Research Institute (GRI) where one of the broad research objectives is improved stimulation techniques.

Sand flowback can be a big problem in high rate gas wells. Sand can quickly erode chokes, valves and other surface equipment creating potentially dangerous situations for the gas well operating and pipeline companies. In 1998 and 1999 several different sand flowback or backflow control methods have been applied in Columbia Gas Transmission Company's Rockport Storage Field. Deformable particles are the latest innovation for controlling sand flowback. Unlike curable resin coated sands and tacky surface-modification agents, deformable particles differ in that they do not "glue" the sand pack in place, but rather mechanically hold it together by dimpling under stress and physically holding adjacent grains of sand firmly in place. A modest weight percentage of deformable particles can easily lock the sand pack in place, resisting the forces brought to bear by gas and fluid flow within the fracture. The Oriskany Sandstone in the Rockport Storage Field can be classified as a highly permeable formation capable of a withdrawal rate greater than 40 MMSCFD. Stimulation treatments are routinely pumped to improve the Oriskany's deliverability back to original levels following workover operations. Prior to running deformable particles for sand flowback control, tacky resin-like chemicals and curable resin coated sand were pumped to alleviate the problem. Introduction Sand or proppant flowback can result in higher operating costs due to erosion of tubulars, surface chokes, lines and valves, workovers to repair or replace downhole pumps, sand fill cleanout and production facility damage. A loss of near wellbore fracture conductivity is also a definite possibility. All of these in turn can lead to reduced production and heightened safety concerns.1,2 Sand control techniques are not normally needed on wells fractured in the Northeast United States. Indeed, the sand or fines that flow back after hydraulic fracturing operations most often is crushed fracturing sand.3 There are exceptions like Michigan's Antrim Shale where operators have struggled for more than a decade with fracturing sand flowing back during the dewatering process necessary before gas production begins. Tailing-in with 12/20 sand has historically been the first action taken in Appalachian Basin oil & gas fields where sand flowback became an issue. The logic was that the larger and heavier 12/20 sand grains would be more difficult to flow out of the well than the smaller, lighter 20/40 sand. While that is true, there are other processes at work here that can lead to failure of 12/20 sand to prevent 20/40 sand from flowing back after a treatment. In a laboratory API conductivity cell one can easily demonstrate that a sand pack of 12/20 sand resists movement better than 20/40 sand. But consider a well with a large perforated interval where some of the perforations have prematurely screened out using the smaller sand prior to the addition of the larger sand at the blender. These packed-off perforations are more apt to freely give back sand during the post-frac clean up and the producing life of the well. In the case of dynamic sand settling or banking during the fracture treatment, the larger sand may be deposited on top of the bed of smaller mesh sand. Perforations below the larger/smaller sand contact boundary within the perforated interval may give up sand when the fluid and gas velocity through this portion of the sand bed reaches some critical point.

This paper presents the equipment requirements and field procedures needed for safely and efficiently conducting in-situ formation stress tests (stress tests). It is set apart from other papers which primarily present data and describe analysis procedures. This work briefly discusses when stress tests are practical and what can be learned. The majority of the work describes detailed equipment requirements and field procedures for openhole and cased-hole tests. Different considerations are also mentioned when working with nitrogen and water. Encountered and potential problems are discussed alerting the operator to equipment and events requiring careful attention. An example is provided outlining actual testing time and related costs along with the information obtained.

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fax 01-972-952-9435.References at the end of the paper. AbstractWastes are generated during all oilfield and gas-field operations. Produced fluids make up the largest volume of generated waste, and any material used for drilling, treating, or reworking oil and gas wells can become part of the waste stream. In some cases, the cost of proper waste disposal can be significant. However, the cost of fines, cleanup, litigation, and a tarnished corporate image associated with improper waste disposal is far greater.To remain competitive and profitable, companies must control their costs. Workover and fracturing fluids can be reused, or they can be disposed of on-site for minimal cost. However, these fluids must sometimes be shipped to off-site treatment facilities at great expense to the gas-production or storage company. This paper discusses ways of reducing the volume of produced fluids and used fracturing fluids that must be disposed of. We present a case history on (1) reusing fracturing flowback fluids and produced fluids and (2) redesigning fracturing treatments so that they use less fluid to provide the same results. IntroductionHydraulic fracturing treatments are performed to increase hydrocarbon production rates. The fracturing fluids that are flowed back from the well to the surface become wastes that must be disposed of. These fracturing fluids can be water-, oil-, acid-, foam-, or alcohol-based and can contain thickening additives, frictionreducing additives, and additives that allow the fluid to carry more sand and make the fluid compatible with the formation.Gas-storage companies have been reusing workover fluids and drilling fluids for some time. Even when drilling fluids must be disposed of, they can sometimes be land-applied on-site at