Bilinear Flow in Horizontal Wells in a Homogeneous Reservoir

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174325, “Bilinear Flow in Horizontal Wells in a Homogeneous Reservoir: Huntington Case Study,” by Wei Cher Feng, E.ON E&P; Peyman Nurafza, BG Group; Basil Al-Shamma, E.ON E&P; and Alain Gringarten, Imperial College London, prepared for EUROPEC 2015, Madrid, Spain, 1–4 June. The paper has not been peer reviewed. In the Huntington field in the North Sea, bilinear flow with a clear one-quarter slope in the pressure derivative has been observed during intermediate times in horizontal-well tests, instead of the usual linear flow with a one-half slope expected in a homogeneous reservoir. This paper offers insight into an integrated effort at combining analytical information, numerical well-test models, and geological evidence to explain the reservoir behavior observed in the Huntington field. Reservoir Description The Huntington field is a sandstone reservoir with a maximum oil-column thickness of 120 ft, located within a sand-rich turbidite system in the central North Sea. Vertical appraisal wells show a largely homogeneous reservoir with average porosities of 20%, net/gross ratio of 80–90%, and average permeabilities of 30–60 md. Core samples do not indicate any inherent natural fractures. The reservoir contains undersaturated light oil with gravity of 43 °API, viscosity of 0.3 cp, and bubblepoint pressure of 2,200 psig at reservoir pressure of 4,000 psig and temperature of 250°F. Well tests of two vertical wells match a homogeneous-reservoir model, but four horizontal producers drilled in this reservoir exhibited a one-quarter-slope straight line in the pressure derivative, stretching up to two log cycles during intermediate time. Reservoir Connectivity and Areal Anisotropy. Reservoir-connectivity investigations indicate no obvious barriers between the wells and good reservoir connectivity between all the wells. However, the modified pulse tests indicate possible reservoir heterogeneity between the wells. The minimum-permeability direction was determined from data sets of three well tests, two horizontal and one vertical. It was found that areal permeability anisotropy could exist within the reservoir, with the minimum- permeability direction in the northeast/southwest direction of the Huntington field. Rate History and Production-Time Effects on Well Data An incomplete rate history can mask pressure-derivative response because of the use of superposition time in pressure-buildup analysis. Production-time effects can also affect the shape of the pressure derivative of a pressure-buildup well test. During a buildup, as the pressure stabilizes when reservoir pressure approaches equilibrium, pressure variations become smaller and signal/noise ratio decreases. The transition effect of characteristic flow regimes is discussed in detail in the complete paper. Ultimately, a one-quarter- slope straight line in the pressure derivative is not unique to bilinear flow but could be caused by a combination of transition effects of the characteristic flow regimes in a horizontal well.