Application and Performance of Single-Trip, Multi-zone, High-Rate Water Packs in a Mature Low-Pressure, Low-Temperature Gas Field

Application and Performance of Single-Trip, Multi-zone, High-Rate Water Packs in a Mature Low-Pressure, Low-Temperature Gas Field Lewis B. Ledlow; Lewis B. Ledlow ConocoPhillips Search for other works by this author on: This Site Google Scholar Brian T. Seitz Brian T. Seitz ConocoPhillips Search for other works by this author on: This Site Google Scholar Paper presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 2004. Paper Number: SPE-86512-MS https://doi.org/10.2118/86512-MS Published: February 18 2004 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Ledlow, Lewis B., and Brian T. Seitz. "Application and Performance of Single-Trip, Multi-zone, High-Rate Water Packs in a Mature Low-Pressure, Low-Temperature Gas Field." Paper presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 2004. doi: https://doi.org/10.2118/86512-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE International Conference and Exhibition on Formation Damage Control Search Advanced Search AbstractA total of six high rate water packs were installed in two wells utilizing a single trip, multi-zone gravel pack technique. The multi-zone gravel pack tool system allowed the installation of multiple gravel packs with a single run into the wellbore.1,2,3 This gravel pack system was chosen to reduce rig time and to minimize fluid loss into the low pressure, high permeability gas sands. In this high permeability reservoir, frac packing did not appear necessary for stimulation. The multi-layered reservoir and low strength rock made it highly unlikely that single, planar fractures could be created that would grow and connect up all the individual sands. Emphasis was placed on completion efficiency to minimize the effects of non-Darcy flow that severely limit the productivity of conventionally completed wells.This paper describes the nodal analysis and well test evaluation techniques used to assess the rate limiting effects and completion inefficiencies of existing completions in this field. Also presented are single-trip, multi-zone gravel pack completion design and installation techniques that provided two to five times the productivity over conventional completions in a mature, low pressure, low temperature gas field. Sustained deliverability from the two completed wells has deferred both rig and non-rig wellwork for several years.IntroductionThe Beluga River gas field is an onshore development located 32 miles west of Anchorage, Alaska, along the northwest shoreline of Cook Inlet (Figure 1). Access to the Beluga River Field is by air or water. There are no roads connecting the field to the highway road system. The shallow gas accumulation was discovered in 1962 while exploring for a deeper oil objective. The field was first put on production in 1968 and is a significant supplier of gas used for power generation and space heating around the major population centers of south-central Alaska. With a customer base primarily consisting of the utility market in a seasonal cold weather environment, the field has historically been a provider of high swing gas, with monthly average winter rates exceeding the summer demand by a factor of more than two (Figure 2). Daily fluctuations in demand are even greater. With no gas storage available, swings in gas supply throughout the region are provided via the wellbore.The Beluga River Unit produces from the Sterling and Beluga formations over a gross interval of 3000'.4 Encased in relatively impermeable siltstones and mudstones, individual sands range from 5' to 50' thick (Figure 3). The interbedded coals sourced the large volumes of biogenic gas trapped within the field and the reservoir gas consists of 99.5% methane. No hydrocarbon liquids are produced. Original reservoir pressure in the Sterling formation was 1635 psia with a temperature of 94°F at 3300' TVDSS. By the time this work was performed in 1998, the reservoir pressure had declined to 1163 psia. Permabilities measured from core can vary up to two orders of magnitude but on average exceed 100 md.This paper focuses on the Pliocene age Sterling formation that ranges in depth from 3,000' to 4000' TVDSS. These high permeability, gas-charged sandstones are friable, matrix clay rich, with minimal cementation. Rate restrictions are imposed on conventionally completed wells to minimize sand production. When water breakthrough occurs, sand production is uncontrollable regardless of rate. Non-Darcy flow effects associated with gas production from this low pressure reservoir cause significant near wellbore drawdown. These non-Darcy flow effects and the resultant pressure drop near the wellbore limit the rate at which conventionally completed wells can be produced sand free. Keywords: volumetric measurement, flow rate, perforation, reservoir pressure, mscfd, low pressure, high rate water pack, psia, gas field, low temperature gas field Subjects: Formation Evaluation & Management, Perforating, Completion Installation and Operations, Completion Operations This content is only available via PDF. 2004. 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