Impact of Fluid Heterogeneity on Tight Unconventional Well GOR Performance

Conference Paper

2020

This paper presents a comprehensive study of the influence of layer-wise fluid heterogeneity in the production performance of tight unconventional wells. Specifically, a reservoir simulation model is history-matched to actual production data from the field, using a black-oil reservoir simulator based on a planar-fracture symmetry element model. The history matched model is then used to illustrate the impact of multiple history-match “equivalents” that forecast GOR differently with uniform in-situ fluid assumption versus GOR variation in each parasequence (major geologic layer).

This is the last paper of a series of studies and previous presentations (by the same authors) that have studied the impact of petrophysical and fluid heterogeneities on well GOR performance. The first paper uses a broad range of geoscientific studies to assess the possibility, and support the most probable fluid heterogeneity scenario in a tight unconventional – i.e. each parasequence in a well may undergo different in-situ hydrocarbon generation that leads to different in-situ compositions and layer-wise solution GORs. This paper is a field application and extension of that earlier work, focused on the impact on GOR performance over time and uncertainty in ultimate recovery (EUR).

We use field daily-metered production data and a black-oil PVT formulation (based on a basin-wide EOS model) to history match a 3D finite difference horizontal well model with a planar fracture symmetry element model. The history-matched model is used to study the impact of fluid heterogeneity on history match quality and forecasted GOR performance. The fluid heterogeneity is treated as a two-layered system with very limited communication between the layers except through the wellbore/hydraulic-fracture. Each layer represents a parasequence containing a uniform composition (i.e. in-situ solution GOR is different for each layer). The cases studied cover both (a) equal petrophysical properties in each layer with different initial solution GOR, and (b) different petrophysical properties k and φ for each layer with different solution GOR.

The study shows that several non-unique fluid initializations (rock and fluid heterogeneities) can lead to a comparable history match of producing GORs, while the forecasted GOR performance may vary according to the assumptions made for initial fluid distribution. It is also shown that even with known rock heterogeneity (i.e. known petrophysical properties for each layer), there may still be multiple fluid initializations that yield similar early-time producing OGR behavior, and sometimes similar OGR behavior throughout the historical data available.

The fluid sample data that – if available – could be used to narrow the degree of fluid heterogeneity in a well is seldom (if ever) available. The main consequence is that a history match of well GOR performance should be made using a range of plausible GOR fluid initializations – from uniform to layer-wise solution GOR variation (constrained by early GOR performance). The different history-matched models can then be used to forecast oil and gas rates that quantitatively capture the uncertainty of in-situ fluid distribution.

Rate forecasting of both oil/condensate and gas has been a long-standing challenge in tight unconventional resource plays. This paper gives a pragmatic approach to capture the uncertainty in initial fluid heterogeneity, and how this uncertainty would yield a range of forecasted GORs and EURs.

• Publisher Name: Unconventional Resources Technology Conference (URTeC)