Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146239, ’Flow-Assurance Challenges in Gas-Storage Schemes in Depleted Reservoirs,’ by Alireza Kazemi, SPE, and Bahman Tohidi, SPE, Hydrafact Ltd., and Emile Bakala Nyounary, Heriot-Watt University, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.
Injection or production of dry gas into or from a depleted gas reservoir could result in serious flow-assurance challenges. Parameters involved in water evaporation/production and in salt precipitation for a gas-production/-injection well are described quantitatively. The terms of formation damage (skin) were evaluated, and some recommendations for prediction and mitigation are proposed. Water in the produced gas is a major flow-assurance threat because of the possibility of gas-hydrate formation in the production system. Mitigation methods are presented.
Introduction
Gas injected into the depleted reservoir normally is a processed/dried gas. However, after injection, the gas is in contact with hydrocarbon and aqueous phases in the reservoir. Therefore, the composition of the produced gas may differ from that of the injected gas. More importantly, the produced gas will have some water (mainly in the form of vapor at reservoir conditions) because of the contact with water in the formation. During production, the water is produced with the gas. The net result is evaporation of water from formation brines, resulting in an increased formation-water salt concentration in the reservoir and salt formation/deposition. Also, the produced water may condense in the wellbore and/or surface facilities, resulting in corrosion, hydrate, and/or ice formation.
Background
The study model was a 3D, Cartesian-grid-type block containing one well. The model was intended to represent a portion of a gas field (i.e., drainage area) with its corresponding producer/injector. A seasonal natural-gas storage/production scheme was modeled. First, production from the reservoir lasted 30 months with a maximum daily gas-production rate of 45×106 m3/d. Then, injection was modeled for 3 months at 10×106 m3/d, followed by 4 months of soaking (i.e., shut-in). Then, for 5 years the following injection/production cycle was used: 2 months of production, 3 months of soaking, 3 months of injection, 4 months of soaking, and 2 months of production, for each calendar year.
The following properties were assumed: Reservoir temperature=104°C, initial reservoir pressure=250 bar, average porosity=10%, horizontal permeability in x- and y-direction=100 md, vertical permeability=10 md, reservoir thickness=110 m, and reservoir dimensions of 900×900 m.
Connate-water saturation was assumed to be 10%, with a gas/water contact at 1005-m depth. The reservoir gas was assumed to comprise four main components: methane (highest concentration), ethane, carbon dioxide, and water. The injected dry gas was assumed to have no water (i.e., 0% humidity). A modified Peng-Robinson equation of state was used in the simulation calculations.