Mitigating production decline is a challenging task that every oil company will be faced with at some point over the life of an oil reservoir. However, depending on the existing reservoir fluid and rock characteristics, saturation distribution, and the level of heterogeneity of the reservoir rock, Enhanced Oil Recovery (EOR) programs can be implemented to alleviate the decline in oil rate and improve overall recovery. This paper presents an example of a how a mature waterflooded field in southwestern Saskatchewan, Canada could be revitalized using Alkaline-Surfactant-Polymer (ASP) flooding. In this study, laboratory tests were undertaken to select effective chemicals and optimize concentrations that would yield the highest potential oil recovery. Subsequent radial coreflood experiments demonstrated a wide range of potential recovery that depended on slug size and chemical concentration. A detailed numerical simulation of the optimum core displacement was performed in order to calibrate the interaction of the EOR agent with the reservoir rock and fluids, and ultimately upscaled to the full field numerical model Reservoir simulation sensitivity runs were conducted in order to identify an optimum field development strategy using the selected ASP fluid. The results from this optimized development strategy were compared to the waterflood base case to demonstrate the potential upside of the chemical flood. This paper also presents a holistic roadmap for developing EOR projects from initial concept to field implementation and beyond.
Hydraulic fracturing in multi stage horizontal unconventional wells is perhaps one of the most important if not the most important in the drilling and completion cycle of these wells. It's also the most applied technique repeatedly in multiple formations throughout the world and yet the question that looms large over us, do we understand the fracture geometry in these unconventional environments.Year on year most unconventional formations seem to fall in line with the industry trend of increasing lateral lengths and pumping more stages to improve production and recovery. Again, we need to ask ourselves if this is sustainable. Introspection of data available from public data seems to indicate that a significant chunk of these wells buck the trend of increased lateral lengths and stages and we still continue to apply these techniques especially in a price sensitive oil market. What if we could challenge this paradigm through a systematic engineering process that could relate the impact of fracture geometry and well spacing? We selected one of the up and coming plays in Canada that is on the road to development called the Duvernay.The Duvernay Formation is a unit of the Woodbend Group and is considered as the source rock for prolific reservoirs such as the Leduc reefs. Duvernay formation holds an estimated 443 trillion cubic feet of gas and 61.7 billion barrels of oil.This paper is an attempt to model and understand complex hydraulic fractures in a multi well pad environment coupled with production modelling to understand drainage patterns. Public data from the IHS database was used to construct and build a geocellular model and wells that had petrophysical and geomechanical data were used to build a representative well pad model. Using the model built complex fractures using the unconventional fracture models were simulated in a multi well pad environment. Impact on reservoir drainage has been assessed with various simulations by changing different parameters with respect to hydraulic fracturing. The results of these various simulations are presented in the paper and these simulations act as a tool to understand when possible interference may occur in these pads. Spacing of wells and frac sizes can be adjusted to minimize competitive drainage between wells.
Stimulating Shale Gas Wells has become a mundane activity with very little or no engineering. The industry has focused heavily on reducing costs and increasing efficiencies of operations that there is seldom any time for engineering. The lack of any horizontal logging information, assumptions that rock quality does not change have led to excel driven spreadsheets doing glorified mass balances which are considered as the fracture designs of today. In addition to this the same fracture treatment is pumped stage after stage well after well. Needless to say the industry's lack of ability to model these complex fractures has also contributed to the exercise of moving away from fundamental fracture design. This trend has resulted in productivities of wells being all over the place that mostly are unexplained. The industry is beginning to realize that a significant % of the wells drilled in unconventionals are not profitable.Refracturing is also gaining prominence because of a single important factor that primary initial completions are ineffective. Shale 2.0 is all about integrating seismic to stimulation information to provide better answers and ultimately better productivity via simple measurements in the lateral. These measurements are ultimately used to engineer the completion, design and understand the science behind fracturing than just merely pumping the job. This paper details the planning, design and evaluation processes in the application of a new workflow called the Unconventional Reservoir Optimized Completion workflow. This revolutionary Seismic to Stimulation workflow demonstrates with examples how we have migrated, a dominant well centric process to a reservoir centric process. A significant step change in fracture modelling has been applied using unconventional fracture models which have the ability to model complex fractures using discrete fracture networks. These models can be validated using microseismic and when calibrated with production can become a powerful prediction tool. Experiences and lessons learned in the Canadian Montney will be presented.
A major numerical modelling project was performed with the objectives of develop a more robust model for development planning studies. The second was to gain a better understanding of "reservoir dynamics", in particular aquifer influx, the lateral pressure distribution and gross fluid movement within the major reservoirs of the Wara–Burgan sequence and the flow between them. The challenges and implemented solutions of history matching a reservoir model of a huge, complex field with multiple production zones, many wells and large volumes of production and surveillance data are described in the context of a recently completed study of Wara–Burgan reservoir in the giant Greater Burgan field. Additional challenges due to possible mechanical problems in wells and uncertainties in production and injection data, as usually experienced in mature fields, are also discussed. The work started with reviews of basic engineering data, previous simulation studies and the regional geology. It was the first project for this field in which modern assisted history matching (AHM) techniques were applied. The main enablers for this were increased computational resources and the availability of new generation high-performance reservoir simulators. AHM techniques were used to help better define "high level" features of aquifer properties, pressure communication and gross fluid movement within and between the main reservoir units. A large emphasis was given to matching the pressure data from RFTs and cased-hole saturation estimates. A combination of AHM and more traditional calibration methods have enabled improved models of the Wara-Burgan reservoir to be developed. These models account for the gross aspects of pressure and fluid movements in and between major reservoir units and provide a reasonable match of the performance at field, reservoir unit and gathering center (GC) levels. The use of AHM techniques and special plots to assess the quality of the pressure match have enabled better characterization on permeability levels and allowed lateral pressure gradients to be better represented. As the match was refined, issues with well histories become more apparent and the approach to dealing with these problems is discussed. Matching the apparent remaining oil distribution was facilitated by extensive tools that allowed easy comparison of simulation with both saturation estimates at wells from cased-hole logs and to interpreted saturation maps. The available workflows, simulation tools and computing environment also allowed models with different levels of refinement (4 to 28 million cells) to be used to address concerns about numerical resolution and upscaling. Base "Do-Nothing" prediction cases were also performed. These gave some insight into how sensitive prediction results would be to model calibration assumptions. Development of the current representative numerical model for the main (Wara – Burgan) reservoir of the giant Greater Burgan field has allowed the major features of pressure communication, fluid movement and current pressure and fluid distributions all to be captured in a geologically plausible setting. The approach to using very large volumes of data, including log data, in the AHM work and the novel tools used to assist visualization of match quality will be discussed.
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