Variation of Skin Damage with Flow Rate Associated with Sand Flow or Stability in Unconsolidated-Sand Reservoirs

Abstract

Discussion of this paper is invited. Three copied of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A semi-cylindrical sand-pack model of a cased-and-perforated completion was loaded with an overburden pressure and fluid flowed through the pack to simulate production. Flow rate was gradually increased in each test. Sand arches formed to stabilize sand movement. As reported previously by the same authors, arch size was a function of flow rate. Skin effect caused by arch formation, destruction, and size variation is also a function of flow rate. Minimum skin effects were noted for a particular flow rate. Potentiometric flow particular flow rate. Potentiometric flow models were used to verify sand-pack results. Flow tests in a linear flow cell indicated a significant damage effect (permeability reduction) due to fines migration. The sand-pack completion model indicated that the fines migration and skin effect change are associated with sand instability. Introduction Sand production from oil and gas wells has become a major problem in many regions of the world. A high percentage of current exploration and develonment effort is being expended in these areas. Sand control with plastic injection and gravel packing is not only time-consuming and expensive, but also generally causes severe productivity restriction. The authors studied flow through a sand pack in the laboratory to understand the natural mechanism which prevents sand production from some wells completed in production from some wells completed in unconsolidated sands. That work was based on the arching studies of Hall and Harrisberger and Stein and Hilchie. Natural stabilization by arching of unconsolidated sand during production was confirmed with a sand pack model of a well completion. Fluid was flowed radially through a semi-cylindrical sand pack which was loaded vertically to 260 psig to simulate overburden pressure. (See Figure 1). Inlet fluid flow was distributed evenly over the outer surface. The inner cylindrical surface represented well casing. Sand used was 20–40 mesh Gopher State proppant sand. Sand arches formed around the fluid outlet ("perforation") to establish static equilibrium between the stressed sand pack and unstressed sand at the perforation. (See Figure 2). perforation. (See Figure 2). Flow rates were increased until sand flowed.