Date of Award

Spring 2017

Degree Type

Thesis

Degree Name

Master of Science (MS)

Committee Chair

Todd Hoffman

First Advisor

David Reichhardt

Second Advisor

Larry Smith

Abstract

The upstream (exploration and production) end of the petroleum industry has experienced tremendous success over the past fifteen years by employing innovative ways to drill and stimulate new wells thereby greatly increasing production. Based upon these successes, there has been a shift to unconventional wells, where the cost for drilling and completing wells can be much more expensive. Most unconventional wells target tight rock formations having low permeability and porosity. As a result, these reservoirs require enhanced stimulation to improve recovery operations to establish profitable oil or gas production. These wells are drilled horizontally to maximize contact area in the zone of interest and generally need to be hydraulically fractured to stimulate and enhance production.

Additional research is needed to better understand the nature of tight reservoirs such as the Bakken, and to provide for better reservoir modeling, simulation, and enhanced hydrocarbon recovery. Wells producing from unconventional reservoirs may not allow for traditional methods of reservoir evaluation due to their unique reservoir properties. Most of these hydrocarbon reservoirs are under sampled and poorly understood. There are comparatively few logs and cores available from unconventional wells. As a result, it is difficult to find relevant lab experiments or data including relative permeability measurements. It is also difficult to obtain representative fluid samples; thus, adding to the difficulty of properly modeling tight resource-play reservoirs. Finally, there are many people building models of unconventional reservoirs, but because of their lack of specific information, their data inputs are uncertain. Therefore, there is a need to investigate how these different parameters affect the results from the various models.

Using the Bakken as the formation of investigation, a square mile section is used to analyze the impact of each property. A black oil model and solvent model were built to represent primary recovery and gas injection. Porosity, permeability, relative permeabilities and capillary pressure were the main properties investigated.

A dual permeability model was compared to a single permeability model. An equation was found to relate the two models when the models had a well with no hydraulic fractures. Hydraulic fractures were then added to see if this equation could work but was unsuccessful.

Results found that, along with porosity and permeability, relative permeabilities can influence a reservoir greatly. The production totals as well as shape of the production curve are affected by relative permeability. This can be used to help improve modeling in unconventional reservoirs and narrow down values for relative permeability.

Comments

A thesis submitted in partial fulfillment of the requirements for the degree of Master of Science in Petroleum Engineering

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