Panel_14430
Panel_14430
1:15 PM
5:05 PM
2:00 p.m.
Evolution of Reservoir Characterization and Well Optimization in the Bakken/Three Forks Play
Four Seasons Ballroom 4
By M. Roth, M. Roth
Since the initial Bakken discovery well in 1957, over 8000 Bakken and 1600 Three Forks wells have been drilled across North Dakota, Montana and Saskatchewan. Over the past decade we have seen a rapid uptick in the geologic understanding of the Bakken and Three Forks, coupled with increasingly effective, and efficient, customization of drilling and completions. We illustrate how the emergence of geologic data coverage has driven industry understanding of play nuances. Regional structural, thickness and geochemistry maps highlight early play characterization and identification of the eastern "line of death" and unique characteristics of the Sanish and Parshall fields. Lithofacies classification of vertical well log suites illustrate the insights gained from delineation wells that framed interpretation of the complex play stratigraphy. More recently, sufficient well coverage has emerged to consistently map oil saturation/water cut across the basin; supported by more detailed depth and character mapping using the extensive gamma-ray coverage. Keeping pace with burgeoning geologic understanding, well completion techniques have been tested and tuned - from single to 40 and 50 stages - with sand volumes ranging well above 10 million pounds and accompanying fluids beyond 150,000 barrels. Currently, multi-lateral co-development of Bakken and two-to-four Three Forks formations are becoming standard operating procedure. "Frac hits" have emerged as the key development optimization focus as well spacings approach 500 feet in common formations and 250 feet in staggered multi-level patterns. While overlapping zones of stimulation can have beneficial effects, delayed infills are proving to be very problematic with unclear economic tradeoffs of increased, though contested well production, often offset with dramatic production decline in adjacent, active wells. Oilfield analytics provide a unique perspective of the ongoing efforts to "right size" drilling and completions engineering for rock and fluid characteristics in the Bakken and Three Forks reservoirs. Dynamic well spacing, vertical and lateral geometry, drilling and completions parameters and geologic character can all be quantified; providing a common basis for using analytic techniques to predict well performance. The results of these analyses are improved understanding of geologic prospectivity, independent of engineering, as well as indications of optimized engineering techniques for different geologic scenarios.
Since the initial Bakken discovery well in 1957, over 8000 Bakken and 1600 Three Forks wells have been drilled across North Dakota, Montana and Saskatchewan. Over the past decade we have seen a rapid uptick in the geologic understanding of the Bakken and Three Forks, coupled with increasingly effective, and efficient, customization of drilling and completions. We illustrate how the emergence of geologic data coverage has driven industry understanding of play nuances. Regional structural, thickness and geochemistry maps highlight early play characterization and identification of the eastern "line of death" and unique characteristics of the Sanish and Parshall fields. Lithofacies classification of vertical well log suites illustrate the insights gained from delineation wells that framed interpretation of the complex play stratigraphy. More recently, sufficient well coverage has emerged to consistently map oil saturation/water cut across the basin; supported by more detailed depth and character mapping using the extensive gamma-ray coverage. Keeping pace with burgeoning geologic understanding, well completion techniques have been tested and tuned - from single to 40 and 50 stages - with sand volumes ranging well above 10 million pounds and accompanying fluids beyond 150,000 barrels. Currently, multi-lateral co-development of Bakken and two-to-four Three Forks formations are becoming standard operating procedure. "Frac hits" have emerged as the key development optimization focus as well spacings approach 500 feet in common formations and 250 feet in staggered multi-level patterns. While overlapping zones of stimulation can have beneficial effects, delayed infills are proving to be very problematic with unclear economic tradeoffs of increased, though contested well production, often offset with dramatic production decline in adjacent, active wells. Oilfield analytics provide a unique perspective of the ongoing efforts to "right size" drilling and completions engineering for rock and fluid characteristics in the Bakken and Three Forks reservoirs. Dynamic well spacing, vertical and lateral geometry, drilling and completions parameters and geologic character can all be quantified; providing a common basis for using analytic techniques to predict well performance. The results of these analyses are improved understanding of geologic prospectivity, independent of engineering, as well as indications of optimized engineering techniques for different geologic scenarios.
Panel_14956
Panel_14956
2:00 PM
2:20 PM
4:05 p.m.
A New Rock-Eval Methodology for Tight Oils
Four Seasons Ballroom 4
By B. Garcia, J. Daniel*
The Rock-Eval is a versatile, high-tech instrument for geochemical assessment of fossil organic matter. It imposed itself as a standard technic which has evolved over the last decades in terms of hardware, software and interpretation capabilities. Primarily, in a conventional petroleum system perspective, it has been designed as a screening tool assessing basic organic attributes of source rocks, such as occurrence of organic matter, TOC, petroleum potential and thermal maturity (Espitalié and Bordenave 1993). Further improvements were developed in order to determine kinetics parameters (e.g. Ungerer 1986, 1987) and more recently carbonate content and type (Pillot et al 2013). Moreover, several of these attributes are instrumental inputs for any numerical basin modeling. Due to operational constraints, sampling is often poor and relies mainly on cuttings which are mixing lithologies and are often stored in non-adequate conditions, implying an uncertain assessment of free hydrocarbons content (S1). The Rock-Eval program developed was then not specifically directed to measure this parameter with accuracy. For instance, the initial heating temperature of the standard Rock-Eval program (set à 300°C) leads to a loss of the lighter end of free hydrocarbons. Consequently with this standard methodology the S1 parameter is generally not seriously considered. With the rise of shale plays interest, a specific focus is needed in order to quantify the occurring free hydrocarbons and assess their nature and properties. In this respect, a new Rock-Eval method is proposed to provide this kind of information. This method, presented using examples, implies a low initial thermovaporization temperature which allows to minimize the loss of the lightest hydrocarbons. Consequently, it provides a more realistic value for the free hydrocarbons occurring in shale play samples. This method is also designed to generate a double peak for the free hydrocarbons, with the aim to tentatively provide an insight in the quality of the hydrocarbon fluids. This double peak is artificially induced by introducing a selected temperature plateau during the step of hydrocarbons thermovaporization. Information on the nature of hydrocarbon fluids and operational proxies, i.e. API of the fluid in the rock, are derived from a processing of the relative importance of these two peaks. In addition, this new methodology intents to prevent the potential interference of heavy hydrocarbons with the peak resulting from the pyrolysis of the kerogen (S2). This interference is more likely to occur in oil-rich shale plays and are likely to bias parameters such as residual HI and Tmax.
The Rock-Eval is a versatile, high-tech instrument for geochemical assessment of fossil organic matter. It imposed itself as a standard technic which has evolved over the last decades in terms of hardware, software and interpretation capabilities. Primarily, in a conventional petroleum system perspective, it has been designed as a screening tool assessing basic organic attributes of source rocks, such as occurrence of organic matter, TOC, petroleum potential and thermal maturity (Espitalié and Bordenave 1993). Further improvements were developed in order to determine kinetics parameters (e.g. Ungerer 1986, 1987) and more recently carbonate content and type (Pillot et al 2013). Moreover, several of these attributes are instrumental inputs for any numerical basin modeling. Due to operational constraints, sampling is often poor and relies mainly on cuttings which are mixing lithologies and are often stored in non-adequate conditions, implying an uncertain assessment of free hydrocarbons content (S1). The Rock-Eval program developed was then not specifically directed to measure this parameter with accuracy. For instance, the initial heating temperature of the standard Rock-Eval program (set à 300°C) leads to a loss of the lighter end of free hydrocarbons. Consequently with this standard methodology the S1 parameter is generally not seriously considered. With the rise of shale plays interest, a specific focus is needed in order to quantify the occurring free hydrocarbons and assess their nature and properties. In this respect, a new Rock-Eval method is proposed to provide this kind of information. This method, presented using examples, implies a low initial thermovaporization temperature which allows to minimize the loss of the lightest hydrocarbons. Consequently, it provides a more realistic value for the free hydrocarbons occurring in shale play samples. This method is also designed to generate a double peak for the free hydrocarbons, with the aim to tentatively provide an insight in the quality of the hydrocarbon fluids. This double peak is artificially induced by introducing a selected temperature plateau during the step of hydrocarbons thermovaporization. Information on the nature of hydrocarbon fluids and operational proxies, i.e. API of the fluid in the rock, are derived from a processing of the relative importance of these two peaks. In addition, this new methodology intents to prevent the potential interference of heavy hydrocarbons with the peak resulting from the pyrolysis of the kerogen (S2). This interference is more likely to occur in oil-rich shale plays and are likely to bias parameters such as residual HI and Tmax.
Panel_14955
Panel_14955
4:05 PM
4:25 PM