• Economic assessment of Alaska North Slope hydrate-bearing reservoir regional production development schemes

      Nollner, Stephanie P.; Dandekar, Abhijit; Patil, Shirish; Ning, Samson; Khataniar, Santanu (2015)
      The objective of this project was to evaluate the economic feasibility of producing the upper C sand of the Prudhoe Bay Unit L Pad gas-hydrate-bearing reservoir. The analysis is based on numerical modelling of production through depressurization completed in CM G STARS by a fellow UAF graduate student, Jennifer Blake, (2015). A staged field development plan was proposed, and the associated capital and operating costs were estimated using Siemens's Oil and Gas Manager planning software and costing database. An economic assessment was completed, incorporating the most common royalties, the current taxes laws applicable to conventional gas development, and most recent tariff estimates. The degree of vertical heterogeneity, initial average hydrate saturation, well spacing and well type had a significant impact on the regional gas production profiles in terms of cumulative volume produced, and more importantly, the expediency of gas production. The volume that is economically recoverable is highly dependent on how the field is developed. A field that has higher vertical heterogeneity and corresponding lower average initial hydrate saturation is most economically produced using horizontal wells at 160 acre spacing; the acceleration of gas production outweighs the increased drilling costs associated with the longer wells and tighter well spacing. The choice of development scenario does not impact the project economics significantly given a field that has lower vertical heterogeneity; however, development using horizontal wells at 320 acre spacing is marginally more economic than the alternatives. Assuming a Minimum Attractive Rate of Return of 20%, the minimum gas price that would allow economic production of ANS gas hydrates was found to be $29.83 per million British thermal units; this value is contingent on the reservoir having high average initial hydrate saturation and being developed with horizontal wells at 320 acre spacing. A slightly higher gas price of $36.18 per million British thermal units would allow economic production of a reservoir having low average initial hydrate saturation that is developed with horizontal wells at 160 acre spacing.
    • Modeling the injection of CO₂-N₂ in gas hydrates to recover methane using CMG STARS

      Oza, Shruti; Patil, Shirish; Dandekar, Abhijit; Khataniar, Santanu; Zhang, Yin (2015-08)
      The objective of this project was to develop a reservoir simulation model using CMG STARS for gas hydrates to simulate the Ignik Sikumi#1 field trial performed by ConocoPhillips at the North Slope, Alaska in 2013. The modeling efforts were focused exclusively on the injection of CO₂-N₂ in gas hydrate deposits to recover methane after an endothermic reaction. The model was history matched with the available production data from the field trial. Sensitivity analysis on hydrate saturation, intrinsic permeability, relative permeability curves, and hydrate zone size was done to determine the impact on the production. This was followed by checking the technical feasibility of the reservoir model for a long-term production of 360 days. This study describes the details of the reservoir simulation modeling concepts for gas hydrate reservoirs using CMG STARS, the impact on the long term production profile, and challenges and development schemes for future work. The results show that appropriate gas mixture can be successfully injected into hydrate bearing reservoir. The reservoir heat exchange was favorable, mitigating concerns for well bore freezing. It can be stated that CO₂-CH₄ exchange can be accomplished in hydrate reservoir although the extent is not yet known since the production declined for long term production period during forecasting study.
    • Molecular dynamics simulations to study the effect of fracturing on the efficiency of CH₄ - CO₂ replacement in hydrates

      Akheramka, Aditaya O.; Dandekar, Abhijit; Patil, Shirish; Ahmadi, Mohabbat; Ismail, Ahmed E. (2018-05)
      Feasible techniques for long-term methane production from naturally occurring gas hydrates are being explored in both marine and permafrost geological formations around the world. Most of the deposits are found in low-permeability reservoirs and the economic and efficient exploitation of these is an important issue. One of the techniques gaining momentum in recent years is the replacement of CH₄-hydrates with CO₂-hydrates. Studies have been performed, at both laboratory and field based experimental and simulation scale, to evaluate the feasibility of the in situ mass transfer by injecting CO₂ in gaseous, liquid, supercritical and emulsion form. Although thermodynamically feasible, these processes are limited by reaction kinetics and diffusive transport mechanisms. Increasing the permeability and the available surface area can lead to increased heat, mass and pressure transfer across the reservoir. Fracturing technology has been perfected over the years to provide a solution in such low-permeability reservoirs for surface-dependent processes. This work attempts to understand the effects of fracturing technology on the efficiency of this CH₄-CO₂ replacement process. Simulations are performed at the molecular scale to understand the effect of temperature, initial CO₂ concentration and initial surface area on the amount of CH₄ hydrates dissociated. A fully saturated methane hydrate lattice is subjected to a uniaxial tensile loading to validate the elastic mechanical properties and create a fracture opening for CO₂ injection. The Isothermal Young's modulus was found to be very close to literature values and equal to 8.25 GPa at 270 K. Liquid CO₂ molecules were then injected into an artificial fracture cavity, of known surface area, and the system was equilibrated to reach conditions suitable for CH₄ hydrate dissociation and CO₂ hydrate formation. The author finds that as the simulation progresses, CH₄ molecules are released into the cavity and the presence of CO₂ molecules aids in the rapid formation of CH₄ nanobubbles. These nanobubbles formed in the vicinity of the hydrate/liquid interface and not near the mouth of the cavity. The CO₂ molecules were observed to diffuse into the liquid region and were not a part of the nanobubble. Dissolved gas and water molecules are found to accumulate near the mouth of the cavity in all cases, potentially leading to secondary hydrate formation at longer time scales. Temperatures studied in this work did not have a significant effect on the replacement process. Simulations with varying initial CO₂ concentration, keeping the fracture surface area constant, show that the number of methane molecules released is directly proportional to the initial CO₂ concentration. It was also seen that the number of methane molecules released increases with the increase in the initial surface area available for mass transfer. On comparing the positive effect of the two parameters, the initial CO₂ concentration proved to have greater positive impact on the number of methane molecules released as compared to the surface area. These results provide some insight into the mechanism of combining the two recovery techniques. They lay the groundwork for further work exploring the use of fracturing as a primary kick-off technique prior to CO₂ injection for methane production from hydrates.
    • Project to demonstrate feasibility of gas production with sensitivities on production schemes on Sterling B4 sands formation

      Yeager, Ronald J.; Patil, Shirish; Ning, Samson; Khataniar, Santanu (2018-04)
      The Sterling B4 reservoir is a low-relief anticline structure underlain by a weak aquifer located on the Kenai Peninsula of Alaska. This dry gas-on-water reservoir, holding approximately 13.9 BCF, has experienced challenges since its first development in the 1960s. The gas-water contact is very mobile and easily influenced upward by gas production. All four wells, largely producing in succession of one another, have experienced excessive water production which killed gas production. Faulty drilling and completion work exacerbated the challenges associated with bringing the gas to market. This project covers an effort to develop the Sterling B4 and determine feasible alternatives for commercialization. Those alternatives include infill drilling, variable production, and co-production. Co-production is a method by which gas is produced from a single upper perforation and water is produced from a lower perforation; each of the streams are produced independently by mechanical means which utilize packers and tubing. The only feasible alternative found by this study is co-production. Of the two coproduction methods analyzed, the highest ultimate recovery includes the utilization of an existing vertical well perforating the upper portion of the reservoir for gas production and a new lower horizontal well perforating the water zone to control the gas-water contact. Modeled production schemes proved the gas-water contact was able to be controlled from upward mobility by maintaining a threshold pressure delta between the bottom-hole pressures of the two producing wells. Utilizing co-production in this manner yielded incremental benefit of over 2 BCF until shut-in limits were triggered. Economic analysis of the project has proved bringing the gas to sales presents a significant prize able to support production and able to support facility operational expense despite no other revenue streams. Should other nearby formations demonstrate sufficient targets the economic case would be enhanced and present an even greater prize.
    • Rate transient analysis and completion optimization study in Eagle Ford shale

      Borade, Chaitanya; Patil, Shirish; Inamdar, Abhijeet; Khataniar, Sanatanu (2015-08)
      Analysis of well performance data can deliver decision-making solutions regarding field development, production optimization, and reserves evaluation. Well performance analysis involves the study of the measured response of a system, the reservoir in our case, in the form of production rates and flowing pressures. The Eagle Ford shale in South Texas is one of the most prolific shale plays in the United States. However, the ultra-low permeability of the shale combined with its limited production history makes predicting ultimate recovery very difficult, especially in the early life of a well. Use of Rate Transient Analysis makes the analysis of early production data possible, which involves solving an inverse problem. Unlike the traditional decline analysis, Rate Transient Analysis requires measured production rates and flowing pressures, which were provided by an operator based in the Eagle Ford. This study is divided into two objectives. The first objective is to analyze well performance data from Eagle Ford shale gas wells provided by an operator. This analysis adopts the use of probabilistic rate transient analysis to help quantify uncertainty. With this approach, it is possible to systematically investigate the allowable parameter space based on acceptable ranges of inputs such as fracture length, matrix permeability, conductivity and well spacing. Since well spacing and reservoir boundaries were unknown, a base case with a reservoir width of 1500 feet was assumed. This analysis presents a workflow that integrates probabilistic and analytical modeling for shale gas wells in an unconventional reservoir. To validate the results between probabilistic and analytical modeling, a percent difference of less than 15% was assumed as an acceptable range for the ultimate recoverable forecasts. Understanding the effect of existing completion on the cumulative production is of great value to operators. This information helps them plan and optimize future completion designs while reducing operational costs. This study addresses the secondary objective by generating an Artificial Neural Network model. Using database from existing wells, a neural network model was successfully generated and completion effectiveness and optimization analysis was conducted. A good agreement between the predicted model output values and actual values (R² = 0.99) validated the applicability of this model. A completion optimization study showed that wells drilled in condensate-rich zones required higher proppant and liquid volumes, whereas wells in gas-rich zones required closer cluster spacing. Analysis results helped to identify wells which were either under-stimulated or over-stimulated and appropriate recommendations were made.