This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200807, “Closing the Loop on a History Match for a Permian EOR Field With Relative Permeability Data Uncertainty,” by Usman Aslam, Emerson, and Jorge Burgos, SPE, and Craig Williams, Occidental Petroleum, et al. The paper has not been peer reviewed.


Reservoir production forecasts are inherently uncertain because of the lack of quality data available to build predictive reservoir models. Traditionally, a best estimate for relative permeability data is assumed during the history-matching process despite significant uncertainty. Performing sensitivities around the best-estimate relative permeability case will cover only part of the uncertainty space. In the complete paper, the authors present an application of a Bayesian framework for uncertainty assessment and efficient history matching of a Permian carbon-dioxide (CO2) enhanced oil recovery field for reliable production forecasting.

Field Details

Regional and Structural Geology. The Central Basin Platform (CBP) is a positive tectonic feature that separates the Delaware and Midland sub-basins of the Permian. The study field is located on the northeastern end of the CBP, with the Permian (Guadalupian) -aged reservoir composed of San Andres Formation dolostone. The total thickness of the unit is approximately 1,500 ft, with the main reservoir within the middle 600 ft.

Structural Framework. The area of interest features 270 wells that have a total depth in the San Andres formation or deeper. Of these, 234 have digital open- or cased-hole logs that were used to correlate formation tops. After reviewing all well logs, it became clear that, historically, the zones were primarily identifiable from porosity picks, which are more subjective than markers identified with gamma ray methods. A new sequence stratigraphic framework was developed based on core descriptions and outcrop analogs. This correlation framework was then extrapolated to well logs. After a grid of north/south and west/east cross sections was correlated across the field and a series of loop ties was made for quality-control purposes, structure and isopach maps were created for each zone.

Reservoir Description. At the time of discovery, natural gas was trapped at the structural high point of the study field. Above the gas/oil interface is the gas cap. Below the gas was an oil accumulation, which extended to the producing oil/water contact (POWC). The POWC was defined by early drilling as the maximum depth where water-free oil was produced. The base of the transition zone is the top of the residual oil zone (ROZ); this reservoir interval extends to the free-water level and is an interval believed to have been waterflooded naturally. The ROZ is the target for CO2 injection.

Grid Construction and Property Modeling. A full-field detailed 3D reservoir characterization was modeled at 50-ft × 50-ft grid increments and an approximate 2-ft average layer thickness. The reservoir model consists of 114,222,528 cells. A total of 235 wells in the unit area was correlated and used to constrain the structural framework of the model. Quantitative porosity log suites were available in 233 of the wells in the model area, which were used to create the full-field porosity property in the 3D model. The logs were normalized to the core data and upscaled.

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