Proper identification of damage mechanisms can improve stimulation techniques used in remediation of damaged gas-storage wells. Identifying damage mechanisms is only a beginning step in optimizing remediation. Determining the highest potential candidate wells and evaluating reservoir quality in the field can be just as crucial in optimizing a deliverability enhancement program. Historical data and reservoir/geological description analysis are required to properly rank candidates and design specific treatments to optimize deliverability potential. Once the diagnostic data and analysis are completed, an operator must begin the tedious process of applying the relevant data analysis to rank and validate the candidate wells' potential and select one or more tailored treatment designs. Adequate well ranking is critical to ensure that AFE dollars achieve maximum deliverability. This paper illustrates case studies using a "Solution Team" a multidisciplined team process, in which over 75 wells were diagnosed and treated successfully. Rigorous damage-identification techniques and reservoir quality diagnostics were used in the five gas-storage reservoirs. Each case study produced damage-specific stimulation treatments based on the operator's objectives to enhance existing deliverability. Follow-up evaluations were made at 1- and 2-year intervals to show how the team process that uses new, improved diagnostic practices can optimize deliverability. In this study, damage mechanisms were identified with improved methods described in a previous Gas Research Institute (GRI) project. Damage in each well was quantified using well-test analysis and historical injection/withdrawal cycle performance matching. Log analysis, petrophysical data, geological data, wellbore imaging, and workover historical data were also gathered as treatment-design criteria. The deliverability improvement was quantified for each well using post-treatment diagnostics. The post-treatment evaluations were updated with 1- and 2-year follow-up evaluations. Each study incorporates several unique treatment options addressing a variety of damage mechanisms. Treatments were selected to produce the highest deliverability enhancement and maximize the operator's return on investment. Case Study 1 incorporates high-pressure jetting, tailored acidizing, and hydraulic fracturing techniques used in a deep high-permeability pressure-drive carbonate reservoir. Case Study 2 includes high-pressure jetting and damage-specific fluid treatments in two shallow water-drive clastic reservoirs. Case Study 3 incorporates hydraulic fracturing and high-pressure jetting of a shallow high-permeability pressure-drive clastic reservoir. Case Study 4 incorporates high-pressure jetting with foamed chemical treatments in a converted oil-carbonate reservoir. Introduction This paper demonstrates how an effective diagnostic and ranking process can be used to tailor a well treatment that can optimize deliverability enhancement. In an alliance project with Natural Gas Pipeline (NGPL), now Kinder Morgan, Inc., the objective was to increase deliverability in each of the five existing storage fields described in the case studies.

This paper describes a new diagnostic process that can be applied to gas-storage wells. This technique consists of identifying damage mechanisms and designing individual treatments for each mechanism. The damage identification portion of the new process involves integrating (1) borehole imaging, (2) downhole sampling, (3) well testing, (4) laboratory analyses, (5) reservoir evaluation, and (6) reviews of well and field histories. This part of the process is partially based on results from a previous formation- damage identification study funded by the Gas Research Institute (GRI). Two case studies are provided. Based on overall economic results, field deliverability enhancement projects featuring the new diagnostic process have greater gas deliverability potential than conventionally treated wells. The two case studies presented were performed in porous-media gas-storage fields. Case Study 1 (Page 3) was performed on a pressure-drive carbonate reservoir. Case Study 2 (Page 4) was performed on a water-drive clastic reservoir. P. 43

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractGas-storage wells experience gas deliverability decline over the lifetime of the well for a variety of reasons, but most often decline is caused by near-wellbore skin damage. Recent developments in diagnostic techniques enable operators to identify near-wellbore damage and apply a tailored treatment to reverse the deliverability decline. In a Sayre, Oklahoma gas-storage field, gas deliverability was improved 32.5% in 14 wells, using pretreatment damage diagnostic analysis to remove near-wellbore damage with new coiled-tubingconveyed fluid-oscillation treatments.A fluid-oscillating tool (FOT) is key to the damageremoval technology. The FOT sends out alternating bursts of fluid to create pulsating pressure waves within the wellbore and formation fluids. These pressure waves help break up near-wellbore damage and restore effective permeability by carrying the fluid past the wellbore into the formation. These oscillating pressure waves are not affected by standoff, which is common with conventional jetting or velocity tools. Kinetic energy in the pressure pulse travels through the wellbore fluid with no appreciable energy loss. The pressure waves expand spherically, providing 360° coverage as the tool is moved through the interval. As damage is removed, the waves penetrate deeper into the formation. This paper presents a technical description of the processes incorporated to remediate damage in the Sayre field and the technology used in the oscillation treatments. A case study from West Virginia is also presented. Both cases illustrate pretreatment planning, job design, application procedures, and results.

Successful optimization of a gas storage field begins with proper reservoir description and evaluation of deliverability and storage capacity in the reservoir. Once true reservoir potential is determined, the effects of surface piping and surface-facility pressure constraints can be integrated to quantify a more accurate estimate of the actual deliverability, injectivity, and working gas capacity of the gas storage field. This paper discusses the integration of previously used deliverability enhancement methods with a new reservoir solution simulation package, fully coupled to include surface pipelines and field facilities. The process allows reservoir capacity, reservoir deliverability/injectivity potential, and the surface constraints imposed by pipeline interconnects and facilities to be modeled, allowing the storage operator to improve cycle performance of the entire storage asset. A gas-storage field in Pennsylvania with approximately 50 injection/withdraw wells completed in a pressure-drive sandstone reservoir was studied. The field was converted from a depleted gas producing field to storage in the 1940's. The operator wanted to evaluate the capability to improve deliverability and cycle performance of the field. To accomplish this, geologic modeling was integrated into a reservoir simulation package that incorporated modeling of the subsurface reservoir, the completion piping of the wells, and the complete surface gathering system to the mainline interconnect. Deliverability decline was evaluated using the deliverability indexing method and well test analysis. Skin damage determined from well testing was integrated into the reservoir simulation. After determining the reservoir uplift potential of the field from damage remediation, improvement opportunities were assessed, based on the results of a fully coupled simulation model of the reservoir, including pressure restrictions throughout the piping and facilities.

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.