TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents long-term follow-up results from postfracture and post-refracture deliverability testing for 56 gas storage wells. The wells studied include 32 injection/withdraw (IW) wells hydraulically fractured with surface modification agent (SMA) applied to the proppant and 24 IW wells hydraulically fractured without SMA applied to the proppant for sand flowback control.Deliverability sustainability results previously presented 1 will be updated for these treatments from a 6-to a 9-year period. The results will include analysis from deliverability data for SMA-treated and non-SMA-treated wells over six to nine IW cycles. Three wells of the original group of 24 wells previously fractured without SMA were refractured using SMA.In the original study, a number of wells were fractured without using SMA proppant. These earlier stimulation treatment wells suffered some operational problems and the need for proppant flowback control became apparent. The addition of SMA to fracture treatments reduced operational problems related to produced sand and fracture treatments improved deliverability. The wells that included a SMA now have been through six to seven complete pressure cycles and the long-term effects of sand flowback and well performance can be compared.The results of this updated study show that SMA injected with the proppant helps reduce operational problems in gas storage fields by reducing proppant flowback. In addition, analysis of SMA fractruring treatments in gas storage wells typically show no detriment to long-term performance. In addition, SMA can improve results from refracturing.

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 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.

This paper presents a study of a shallow, low-productivity Devonian shale gas field consisting of 48 wells in Mason County , WV. Gas production from wells in the field was found to be associated with zones of substantial free-gas porosity in the presence of high kerogen (organic) content. Most wells are poor producers; the best wells are located in the northwest portion of the field, which corresponds to an area of natural fracturing identified by remote sensing imagery. We identified and mapped quality reservoir areas and predicted performance for all wells in the field. The stimulation treatments conducted on all wells in the field successfully initiated gas production from the shales, but these treatments generally failed to achieve the degree of stimulation expected from such jobs. IntroductionBackground. All 48 wells in this study are operated by Union Drilling Inc. of Buckhannon, WV. The field, called the Mason County field, is located in westeriI West Virginia on the Ohio border and occupies an 8x4-mile [12.9x6.4-krn] area. Fig. 1 shows the location of the field.This field was developed to supply natural gas to a local industrial facility. A guaranteed market exists for the gas; thus, the wells are continually on line. This guaranteed market was important to the development of the field because the majority of the wells in the field are poor producers. The average well produced 7 to 8 MMscf [198 x 10 3 to 227 X 10 3 std m 3 ] during the first year of production, or about 20 Mscf/D [566 std m 3 /d]. The best well in the field produced only 27.7 MMscf [784 x 10 3 std m 3 ] during its first year of production, or about 75 Mscf/D [2124 std m 3 /d]. More than half of the wells in the field are now producing less than 10 MscflD [283 std m 3 /d].

Objectives/Scope This paper describes a pilot installation of a digital intelligent artificial lift (DIAL) gas lift production optimization system. The work was inspired by PETRONAS' upstream digitalization strategy with five single and dual-string gas lift completions planned from 2018 to 2020, offshore Malaysia. The authors evaluate the impact of the DIAL system in terms of increasing production, optimizing lift-gas injection, reducing well intervention frequency, as well as OPEX and risk reduction. Methods, Procedure, Process DIAL is a unique technology that enhances the efficiency of gas lift production. Downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention. The paper focuses on a well installed in June 2020, the first in a five well campaign. The authors will provide details of the technology, and pilot program phases: system design; pre-job preparations; run in hole and surface hook-up; commissioning and unloading; and subsequent production operations. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits. Results, Observations, Conclusions DIAL introduces a paradigm shift in the design, installation, and operation of gas lifted wells. This paper will compare the differences between this digital technology and conventional gas lift techniques. It will consider the value added from the design stage through installation operations to production optimization. The DIAL system's ability to operate at greater than 80-degree deviation enabled deeper injection while avoiding tractor interventions for GLV maintenance in the highly deviated section of the well. Built-in downhole sensors provided real-time pressure monitoring that enabled a better understanding of reservoir behaviour and triggered data-driven reservoir stimulation decisions. The technology also proved very beneficial for production optimization, with the intervention-less adjustment of gas injection rate and depth downhole, based on the observed reservoir response in real time. The variable port sizes can be manipulated by means of surface switch/control. Overcoming the completion challenges due to COVID-19 restrictions, the well was unloaded and brought online with the assistance of personnel located in Houston and Dubai using Silverwell's visualization software. The well continues to be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS' upstream digitization strategic vision. Novel/Additive Information First deployment worldwide of new and unique gas lift production optimization technology in offshore highly deviated well. The technology deployment was the result of collaborative work between a multi-discipline engineering team in PETRONAS, Silverwell, and Neural Oilfield Service.