Evaluating the Performance of Hydraulically Fractured Horizontal Wells in the Bakken Shale Play

Abstract

In the last several years, interest in developing unconventional oil and gas reservoirs has grown tremendously. Most of these unconventional reservoirs have very low permeability which makes them unable to produce at economic flow rates without massive stimulation treatments or special recovery processes. Bakken Shale play is one of these reservoirs which horizontal wells with hydraulic fracture treatments have been proven to be an effective method for its development. In this study, to evaluate the performance of hydraulically fractured horizontal wells in the Bakken Shale play, a rigorous analytical model has been developed to predict the productivity of a tight multi-layered reservoir drained by a horizontal well with a longitudinal fracture. This model rigorously couples flow in the matrix to flow in the fracture, and then to flow in the wellbore to account for the fracture conductivity and wellbore hydraulics, respectively. History matching of production data for Bakken wells reveals that the developed model provides a reliable tool for predicting the productivity of this type of well-reservoir configuration. Moreover, using this model to study the key factors influencing the well performance indicates that length of fractured portion of the lateral is the primary factors affecting the well productivity, while conductivity of fracture has an insignificant effect on productivity, which means using better proppant or fluid has minimal effect on productivity. Introduction The Bakken formation of eastern Montana and western North Dakota has been experiencing significant development during the last several years due to its tremendous oil accumulation. This formation is comprised of three distinct members - lower and upper shale beds, and a lithologically variable middle member which is the main productive interval and the target of the current development. The upper and lower shale have almost the same characteristics. The upper shale is comprised of a black, organic-rich, pyritic shale with measured total organic content (TOC) up to 40%. It is the primary source of hydrocarbons for the Middle Bakken. The lower shale is comprised of a black to brownish-black, fissile, non-calcareous, organic mudstone or shale. It has TOC of up to 21% (Wiley et al. 2004). Both upper and lower shale have a low porosity with extremely low permeability which can act as a seal to the generated hydrocarbon. The Middle Bakken generally is a marine sandstone or siltstone with considerable percentages of carbonate grains and cements. The Elm Coulee field in the Richland County, Montana Bakken play, is developed in a very dolomitic facies where porosity and permeability are relatively high due to partial dissolution of interlocking replacive dolomite rhombs. The North Dakota productive Middle Bakken exhibits comparable depositional characteristics but has more of a clastic framework of quartz, feldspar, and reworked fossiliferous carbonate grains and smaller amounts of dolomite. Primary porosity with reduced amount of secondary porosity is the main driver in the reservoir system in North Dakota (Cox et al. 2008). Production from the Bakken has been reported as early as the 1950's. Since the discovery, the play has experienced three development periods (LeFever 2004):–Conventional vertical drilling (1953–1987),–Horizontal drilling in the upper Bakken Shale (1987–2000),–Horizontal drilling in the Middle Bakken (2000-present day).

Evaluation of Displacement Effects of Different Injection Media in Tight Oil Sandstone by Online Nuclear Magnetic Resonance

“…The source beds are closely related to the reservoirs, and there is no obvious boundary of the trap [9]. Development experience shows that the combination of long horizontal wells and multi-stage fracturing is an effective method for economic exploitation of tight oil reservoirs [10][11][12]. At present, China has carried out tight oil reservoirs development in Ordos, Songliao, Santanghu, and Junggar Basin [6].…”