This project is a research into the effect of gas condensate damage in hydraulically fractured wells. It is the result of a problem encountered in producing a low permeability formation from a well in South Texas owned by the El Paso Production Company. The well was producing a gas condensate reservoir and questions were raised about how much drop in flowing bottomhole pressure below dewpoint would be appropriate. Condensate damage in the hydraulic fracture was expected to be of significant effect. Previous attempts to answer these questions have been from the perspective of a radial model. Condensate builds up in the reservoir as the reservoir pressure drops below the dewpoint pressure. As a result, the gas moving to the wellbore becomes leaner. With respect to the study by El-Banbi and McCain, the gas production rate may stabilize, or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore. This current work has a totally different approach. The effects of reservoir depletion are minimized by introduction of an injector well with fluid composition the same as the original reservoir fluid. It also assumes an infinite conductivity hydraulic fracture and uses a linear model. During the research, gas condensate simulations were performed using a commercial simulator (CMG). The results of this research are a step forward in helping to improve the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. It also provides methodology for quantifying the condensate damage that impairs linear flow of gas into the hydraulic fracture.

Unconventional gas has become an important resource to help meet our future energy demands. Although plentiful, it is difficult to produce this resource, when locked in a massive sedimentary formation. Among all unconventional gas resources, tight gas sands represent a big fraction and are often characterized by very low porosity and permeability associated with their producing formations, resulting in extremely low production rate. The low flow properties and the recovery factors of these sands make necessary continuous efforts to reduce costs and improve efficiency in all aspects of drilling, completion and production techniques. Many of the recent improvements have been in well completions and hydraulic fracturing. Thus, the main goal of a hydraulic fracture is to create a long, highly conductive fracture to facilitate the gas flow from the reservoir to the wellbore to obtain commercial production rates. Fracture conductivity depends on several factors, such as like the damage created by the gel during the treatment and the gel clean-up after the treatment. This research is focused on predicting more accurately the fracture conductivity, the gel damage created in fractures, and the fracture cleanup after a hydraulic fracture treatment under certain pressure and temperature conditions. Parameters that alter fracture conductivity, such as polymer concentration, breaker concentration and gas flow rate, are also examined in this study. A series of experiments, using a procedure of “dynamical fracture conductivity test”, were carried out. This procedure simulates the proppant/frac fluid slurries flow into the fractures in a low-permeability rock, as it occurs in the field, using different combinations of polymer and breaker concentrations under reservoirs conditions. The result of this study provides the basis to optimize the fracturing fluids and the polymer loading at different reservoir conditions, which may result in a clean and conductive fracture. Success in improving this process will help to decrease capital expenditures and increase the production in unconventional tight gas reservoirs.

Tight gas reservoirs provide almost one quarter of the current U.S. domestic gas production, with significant projected increases in the next several decades in both the U.S. and abroad. These reservoirs constitute an important play type, with opportunities for improved reservoir simulation & management, such as simulation model design, well placement. Our work develops robust and efficient strategies for improved tight gas reservoir simulation and management. Reservoir simulation models are usually acquired by upscaling the detailed 3D geologic models. Earlier studies of flow simulation have developed layer-based coarse reservoir simulation models, from the more detailed 3D geologic models. However, the layer-based approach cannot capture the essential sand and flow. We introduce and utilize the diffusive time of flight to understand the pressure continuity within the fluvial sands, and develop novel adaptive reservoir simulation grids to preserve the continuity of the reservoir sands. Combined with the high resolution transmissibility based upscaling of flow properties, and well index based upscaling of the well connections, we can build accurate simulation models with at least one order magnitude simulation speed up, but the predicted recoveries are almost indistinguishable from those of the geologic models. General practice of well placement usually requires reservoir simulation to predict the dynamic reservoir response. Numerous well placement scenarios require many reservoir simulation runs, which may have significant CPU demands. We propose a novel simulation-free screening approach to generate a quality map, based on a combination of static and dynamic reservoir properties. The geologic uncertainty is taken into consideration through an uncertainty map form the spatial connectivity analysis and variograms. Combining the quality map and uncertainty map, good infill well locations and drilling sequence can be determined for improved reservoir management. We apply this workflow to design the infill well drilling sequence and explore the impact of subsurface also, for a large-scale tight gas reservoir. Also, we evaluated an improved pressure approximation method, through the comparison with the leading order high frequency term of the asymptotic solution. The proposed pressure solution can better predict the heterogeneous reservoir depletion behavior, thus provide good opportunities for tight gas reservoir management.

The supply and demand situation is crucial for the oil and gas industry during the first half of the 21st century. For the future, we will see two trends going in opposite directions: a decline in discoveries of conventional oil and gas reservoirs and an increase in world energy demand. Therefore, the need to develop and produce unconventional oil and gas resources, which encompass coal-bed methane, gas-shale, tight sands and heavy oil, will be of utmost importance in the coming decades. In the past, large-scale production from tight gas reservoirs occurred only in the U.S. and was boosted by both price incentives and well stimulation technology. A conservative study from Rogner (1997) has shown that tight gas sandstone reservoirs would represent at least over 7,000 trillion cubic feet (Tcf) of natural gas in place worldwide. However, most of the studies such as the ones by the U.S. Geological Survey (U.S.G.S.) and Kuuskraa have focused on assessing the technically recoverable gas resources in the U.S. with numbers ranging between 177 Tcf and 379 Tcf. During the past few decades, gas production from tight sands field developments have taken place all around the world from South America (Argentina), Australia, Asia (China, Indonesia), the Russian Federation, Northern Europe (Germany, Norway) and the Middle East (Oman). However, the U.S. remains the region where the most extensive exploration and production for unconventional gas resources occur. In fact, unconventional gas formations accounted for 43% of natural gas production and tight gas sandstones represented 66% of the total of unconventional resources produced in the U.S. in 2006. As compared to a conventional gas well, a tight gas well will have a very low productivity index and a small drainage area. Therefore, to extract the same amount of natural gas out of the reservoir, many more wells will have to be drilled and stimulated to efficiently develop and produce these reservoirs. Thus, the risk involved is much higher than the development of conventional gas resources and the economics of developing most tight gas reservoirs borders on the margin of profitability. To develop tight gas reservoirs, engineers face complex problems because there is no typical tight gas field. In reality, a wide range of geological and reservoir differences exist for these formations. For instance, a tight gas sandstone reservoir can be shallow or deep, low or high pressure, low or high temperature, bearing continuous (blanket) or lenticular shaped bodies, being naturally fractured, single or multi-layered, and holding contaminants such as CO2 and H2S which all combined increase considerably the complexity of how to drill a well. Since the first tight gas wells were drilled in the 1940's in the U.S., a considerable amount of information has been collected and documented within the industry literature. The main objective of this research project is to develop a computer program dedicated to applying the drilling technologies and methods selection for drilling tight gas sandstone formations that have been documented as best practices in the petroleum literature.