• Alkali-surfactant-polymer (ASP) flooding - potential and simulation for Alaskan North Slope reservoir

      Ghorpade, Tejas S. (2014-09)
      Enhanced oil recovery (EOR) is essential to recover bypassed oil and improve recovery factor. Alkaline-surfactant-polymer (ASP) flooding is a chemical EOR method that can be used to recover heavy oil containing organic acids from sandstone formations. It involves injection of alkali to generate in situ surfactants, improve sweep efficiency, and reduce interfacial tension (IFT) between displacing and displaced phase, and injection of a polymer to improve mobility ratio; typically, it is followed by extended waterflooding. The concentration of alkali, surfactant, and polymer used in the process depends on oil type, salinity of solution, pressure, temperature of the reservoir, and injection water quality. This project evaluates the effect of waterflooding on recovery, calculates the recovery factor for ASP flooding, and optimum concentration of alkali, surfactant, and polymer for an Alaskan reservoir. Also, the effects of waterflooding and improvement with ASP flooding are evaluated and compared. Studies of these effects on oil recovery were analyzed with a Computer Modeling Group (CMG)-generated model for the Alaskan North Slope (ANS) reservoir. Based on a literature review and screening criteria, the Western North Slope (WNS) 1 reservoir was selected for the ASP process. A CMG - WinProp simulator was used to create a fluid model and regression was carried out with the help of actual field data. The CMG - WinProp model was prepared with a 5 spot well injection pattern using the CMG STARS simulator. Simulation runs conducted for primary and waterflooding processes showed that the recovery factor increased from 3% due to primary recovery to 45% due to waterflooding at 500 psi drawdown for 60 years with a constant producing gas oil ratio (GOR). ASP flooding was conducted to increase recovery further, and optimum ASP parameters were calculated for maximum recovery. Also, effect of alkali, surfactant and polymer on recovery was observed and compared with ASP flood. If proved effective, the use of ASP chemicals for ANS reservoirs to increase the recovery factor could replace current miscible gas injection with chemical EOR. It will help to develop chemical flooding processes for heavier crude oil produced in harsh environments and create new horizons for chemical industries in Alaska.
    • Analysis of IPR curves in North Slope horizontal producers supported by waterflood and water alternating gas EOR processes

      Abel, Alan; Awoleke, Obadare; Zhang, Yin; Dandekar, Abhijit (2019-05)
      The shape and behavior of IPR curves in waterflooded reservoirs has not previously been defined despite their common use for optimization activities in such systems. This work begins to define the behavior of IPR curves in both water flood and water‐alternating‐gas EOR systems using a fine scale model of the Alpine A‐sand. The behavior of IPRs is extended to 3 additional reservoir systems with differing mobility ratios. Traditionally derived (Vogel, Fetkovich) IPR curves are found to be poor representations of well performance and are shown to lead to non‐optimal gas lift allocations in compression limited production networks. Additionally, the seemingly trivial solution to gas lift optimization in an unconstrained system is shown to be more complex than simply minimizing the bottom hole pressure of the producing well; maximized economic value is achieved at FBHPs greater than zero psi.
    • A comprehensive analysis of the oil fields of the North Slope of Alaska: their use as analogs, recent exploration, and forecasted royalty and production tax revenue

      Michie, Joshua J.; Patil, Shirish; Dandekar, Abhijit; Khataniar, Santanu; Sonwalker, Vikas (2018)
      Revenues from petroleum production supply most of the revenue for unrestricted general funds for the State of Alaska. As such, variations in the price of oil, decline from existing production and new developments greatly affect the money available for the state to spend on everything from roads to education. This study reviewed all producing oil fields on the North Slope, characterized their reservoir performance and forecasted future production. This was coupled with analysis of recent exploration discoveries and ongoing project developments to forecast future North Slope production and create potential royalty and production tax revenue forecasts. After 40 years of production, Prudhoe Bay remains the dominant field on the North Slope, accounting for 45% of current production. Relatively large changes in the non-anchor field pools are only able to change North Slope production by a couple of percent due to the nature of their size compared to Prudhoe Bay, Kuparuk and Alpine. New developments however, are able to materially contribute to changes in North Slope production if they are large enough. With continued activity in the many fields, creating an accurate forecast is challenging, however, without new developments, the Trans Alaska Pipeline will need to make changes to accommodate low flow rates. Currently identified new developments have the potential to extend current production rates 10-20 years. Some of these announced developments and discoveries have announced productivity rates that are not realistic compared to analog well performance, and will likely require many more wells to achieve the announced rates and volumes.
    • Computational fluid dynamics model of two-phase heavy oil and air flow in a horizontal pipe

      Sanders, Nicholas E.; Ahmadi, Mohabbat; Awoleke, Obadara; Dandekar, Abhijit (2020-05)
      The production of heavy oil resources is becoming more prevalent as the conventional resources of the world continue to deplete. These heavy oil resources are being produced from horizontal wells and need to be transported in pipeline to processing facilities as a two-phase flow. Two-phase flow is important to the oil industry with the general focus being placed on light oil or water and gas flows. With little work having been done on two-phase heavy oil flow this study will examine these two-phase flows by recreating experimental data generated for heavy oil and air flow in a 1.5-inch diameter pipe and expand this data to include larger 2.875-inch and 3.5-inch pipes. A computational fluid dynamics model was generated to mimic the 1.5-inch diameter pipe used in the experiments. This model was validated for laminar and turbulent flow by using the same heavy oil properties from the original experiment and air respectively. The model was then run to simulate the given two-phase oil-air flows provided from the experimental data for the flow velocities that had pressure drop and liquid holdup data available. The two-phase results were compared to both the experimental data and the Beggs and Brill values for both pressure drop and liquid holdup. A 2.875-inch and 3.5-inch model were generated and the same process was followed for laminar and turbulent validation and then with a subset of four two-phase flow velocities. Without the availability of experimental data for the two larger size pipes the two-phase results were only compared to the Beggs and Brill values. Overall the results showed a good correlation to the laminar and turbulent flow in all three models with the turbulent flow showing the largest error for the pressure drop when the flow was in the laminar to turbulent transition zone for Reynolds numbers. The two-phase results showed to be in between the experimental and Beggs and Brill method values for the original 1.5-inch model and showed that as the gas flow velocity increased in the system the error grew for all three models. Given that the Beggs and Brill method values were generated based on experiments for water-air flow in a 1.0-inch pipe the values for the pressure drop in the 2.875-inch pipe and the 3.5-inch pipe were not unexpected and seemed to match well with an extrapolation of the experimental values. This study shows that a model can be generated to examine the two-phase flow behavior in horizontal sections of well and in pipelines on a computational basis. While these models are time consuming to generate and run with the increase in computing capacity available easily they can become more suitable than generating experimental setups for finding the same information. There will need to be more work done on heavy oil two-phase flow and additional experiments run for larger size pipes and two-phase flow to help tune these models but they do show promise for the future.
    • Development and economic appraisal of a lightweight zeolite cement blend for high temperature - high pressure oil and geothermal wells

      Misra, Jyotishka; Khataniar, Santanu; Patil, Shirish; Dandekar, Abhijit (2015-12)
      With ever-increasing global energy demand, it is of vital importance that technology consistently meets industry requirements. As high temperature-high pressure reservoirs become more and more profitable, the energy industry can be expected to exploit them. Hence, a versatile cement system that can be used in such reservoirs would need to be capable of ensuring well integrity under such conditions. However, in order to overcome most of these challenges, cement systems are often too dense to pump into a formation without damaging it. Therefore, a lightweight cement is needed. One promising means of delivering a lightweight cement that meets these rigorous demands is to replace a portion of the API cement with a natural pozzolan such as a zeolite. The zeolite cement blend developed in this project has a density of 13.5 ppg, far lower than the 17 to 18 ppg cements that would otherwise be used. Through a trial and error process of replacing portions of API class H or G cement with six different zeolites, an acceptable zeolite cement blend was found, along with the necessary system of additives to ensure that it performed within existing specifications for oil well cements. Each of the cement blends was subjected to high temperature-high pressure testing of consistency behavior, fluid loss, and compressive strength, along with studies of modification with carbonation. This study also endeavored to show that such a cement system was economically viable. This was done using a number of case studies including both oil and geothermal wells. The cement costs of the cement were found by studying each component. The associated costs associated with the cement were subjected to a Monte Carlo simulation to reflect better the variability expected in a well job. By adding the two, and comparing the cost with a similar job carried out with a standard class H cement, the economic viability of the cement was established. In addition, the cost per kilowatt-hour and projected revenues for the geothermal projects were calculated to show that it made financial sense to use the zeolite cement blend.
    • 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.
    • End-to-end well planning strategies for Alaska north slope directional wells

      Mahajan, Neeraj Hemant; Khataniar, Santanu; Patil, Shirish; Dandekar, Abhijit; Fatnani, Ashish (2018-05)
      Directional well planning has gained special attention in the Alaska North Slope (ANS) as operators are being compelled to drill increasing numbers of wells from already congested pads because of low oil prices, Capex restrictions, and environmental regulations. This research focuses on two major components of directional well planning: anti-collision and torque and drag analysis in Schrader Bluff, Milne Point. The drilling pattern at the ANS implies very high wellbore collision risk, especially at the shallower section, which affects the safety of drilling operations. However, satisfying anti-collision norms is not the solitary step towards successful well planning. Integration of anti-collision results with torque and drag analysis is essential in evaluating the safety and feasibility of drilling a particular well path and avoiding drill string failures. In the first part of the study, three well profiles (horizontal, slant, and s-shaped) were planned for each of the two new targets selected in the Schrader Bluff OA sand. Initially, this part of the research compared the performance of the newly developed Operator Wellbore Survey Group (OWSG) error model and the industry-standard Industry Steering Committee for Wellbore Surveying Accuracy (ISCWSA) error model. To provide effective guidelines, the results of error model comparison were used to carry out sensitivity analyses based on four parameters: surface location, well profiles, survey tools, and different target locations in the same sand. The results of this study aid in proposing an improved anti-collision risk management workflow for effective well planning in Arctic areas. The second part of the study investigates the drillability of the well paths planned using the improved anti-collision risk management workflow. Furthermore, this part of the research aims at defining the end point limits for critical well planning parameters, including inclination and dogleg, such that within these limits, the well path satisfies anticollision as well as torque and drag considerations. These limits were generated using a drill string optimized in terms of steerable tool, drill pipe size, mud rheology, trip speed, rotational speed, and weight on bit (WOB) during drilling and tripping out operations. The results of this study would help reduce the cumbersome iterative steps and narrow down the design domain for any well to be drilled on the North Slope of Alaska.
    • Experimental investigation of the influence of various nanoparticles on water-based mud

      Dhiman, Paritosh (2016-12)
      In the oil and gas industry, drilling fluids play an important role in the success of drilling operations. Hence, it is vital to predict accurately and maintain drilling fluid properties. Drilling fluids have multitude of functions, including but not limited to balancing the formation pressure, transporting cuttings, lubricating the bit, minimizing formation damage and maintaining well stability. Efficient completion of any drilling operation is governed by the selection of the proper drilling fluid. Growing hydrocarbon demand is driving the industry to explore unconventional resources such as shale formations and deep water and ultra-deep water areas where high temperature high pressure (HTHP) conditions persist. Generally, oil-based muds have been widely used in HTHP operations, as they can withstand high temperatures while offering high lubricity, but they are expensive and have an environmental impact. Water-based muds offer a cost-effective and environment-friendly option, but they have limited HTHP application, as they tend to break down, resulting in increased fluid loss and viscosity reduction. Also, upon exposure to high temperatures, they also face the issue of gelation and degradation of weighing materials and additives. Due to these issues with both oil-based muds and water-based muds, new drilling fluids are formulated regularly and the existing systems are tailored to curtail drilling operation costs. Most recently, nanoparticles have been recognized as an effective additive to improve the performance of drilling fluids, having the potential to overcome the limitations of current drilling fluid systems in challenging conditions. In this study, experiments have been conducted to investigate the impact of different nanoparticles on various drilling fluid properties, including rheology, filtration, and lubricity, considering a wide range of influence factors, such as nanoparticle concentration, particle size, nanoparticle type, temperature, and aging. The effect of nanoparticle concentrations (0.01 wt% ~ 1wt%) on drilling fluid properties has been first investigated using SiO₂ nanoparticles with and without coating. Then the effect of nanoparticle size (5 nm ~ 50 nm) on drilling fluid properties has been examined using TiO₂ nanoparticles. Subsequently, the impact of nanoparticle type, including four different nanoparticles, on drilling fluid properties has been tested. Moreover, the effects of temperature and aging on the nanoparticle-based drilling fluid properties have been investigated.
    • Improving ultimate recovery in the Granite Point field Tyonek C sands

      Nenahlo, Thomas L.; Dandekar, Abhijit; Patil, Shirish; Ning, Samson (2018-12)
      The objective of this research is to determine how the ultimate recovery of the Granite Point field can be improved. An understanding of the depositional setting, structure, stratigraphy, reservoir rock properties, reservoir fluids, aquifer, and development history of the Granite Point field was compiled. This was then leveraged to provide recommendations on how the ultimate recovery can be improved. The Granite Point field Tyonek C sands are located on an anticline structure at 8,000' to 11,000' SSTVD within the offshore Cook Inlet basin. These sands were deposited in a fluvial environment with the source material provided by the Alaska Range to the northwest. Due to uplifting, the Tyonek C sands are of relatively low porosity for their depth. The sands thin, become more numerous, and are of generally lower porosity from southwest to northeast. Oil quality is excellent and displacement efficiency of the reservoir rock with water flood exceeds 50% at breakthrough. Although displacement efficiency is high, the relative permeability to water is extremely low. The fracture gradient of the reservoir rock is on the order of magnitude of 1.0 psi/ft. Many initiatives were undertaken throughout the history of the Granite Point field to improve the rate and resource recovery, all of which were met with negligible success with the exception being the introduction of horizontal wells that were first drilled in the early 1990's. The underlying reason for the lack of success of these other initiatives is the low effective permeability to oil and the extremely low effective permeability to water. Secondary recovery with water injection was successful in the early stage of development, and can be in the future, but only when applied between wells that are connected by a sand of acceptable porosity. The results of this research indicate that to improve the ultimate recovery of the Granite Point field a thorough quantification of aquifer and injection water movement must first be understood, then horizontal wells can be placed in appropriate locations to improve the offtake and leverage the weak aquifer drive to provide pressure support.
    • 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.
    • The practical application of a hydraulic power recovery turbine at the Valdez Marine Terminal

      Bruns, Brendon; Dandekar, Abhijit; Heimke, David; Wies, Richard (2019-05)
      A hydraulic power recovery turbine (HPRT) is a machine designed to capture energy from the pressure differential of a fluid. The HPRT recovers energy that would otherwise be lost to entropy in flowing fluid processes. When the shaft of the HPRT is coupled to an electric generator, the electricity produced can be employed for practical purposes. At the terminus of the Trans-Alaska Pipeline System (TAPS) in Valdez, favorable hydraulic conditions and electrical infrastructure exists for the application of an HPRT to generate significant power. This project will study the practical application of an HPRT as a source of clean, reliable electricity to the VMT. Installation of an HPRT has the potential to reduce diesel consumption and emissions of air pollutants at the VMT.
    • 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.
    • Prudhoe Bay West End gas lift supply optimization

      Chou, Irwin; Dandekar, Abhijit; Ning, Samson; Zhang, Yin (2019-12)
      The western extension of Alaska's Prudhoe Bay, known collectively as Eileen West End (EWE), operates under a gas lift pressure supply constraint. This constraint is largely contributed by two factors: the extensively long gas lift supply line that stretches across the western field and the large number of production wells offtaking gas lift to stay online or enhance production. The gas lift supply line is approximately 18.5 miles long and provides gas lift to 200+ production wells. This results in a pressure drop severe enough to start hindering production on the western most side of the field as low gas lift supply pressure can cause unstable production, reduced production rate, or stop production altogether. Theory suggests that boosting the system's gas lift supply pressure will improve production from the field. In order to quantify the benefit of boosting the gas lift supply pressure and determine the most optimal way to do so, an industry proven physics based multiphase flow simulator was used to construct two models, a production system and a gas lift system. This dual integrated model approach enabled the ability to capture and predict production effects caused by changes in gas lift supply pressure and determine if boosting the pressure will be beneficial from an operator standpoint. The objective of this project is to describe how building an integrated production model can capture and quantify changes in production for a very large and complex interconnected system. Applying these types of models can help steer important operational and economic decisions to minimize risk and expense as an operator. Using the models, several scenarios were evaluated to determine and quantify the most optimal approach to address the low gas lift supply in EWE. It was determined that shutting in the least competitive wells to boost the gas lift supply pressure was the best scenario to implement for several reasons: the scenario still yielded a high production benefit, it did not have any investment requirement, and the actions could be reversed if a negative impact was realized.
    • 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.
    • Reservoir simulations integrated with geomechanics for West Sak Reservoir

      Chauhan, Nitesh; Khataniar, Santanu; Dandekar, Abhijit; Patil, Shirish (2014-07)
      Geomechanics is the study of the mechanical behavior of geologic formations. Geomechanics plays an important role in the life of a well. Without a proper understanding of the geomechanics of a reservoir, the projects associated with it may run into problems related to drilling, completion, and production. Geomechanics is important for issues such as wellbore integrity, sand production, and recovery in heavy oil reservoirs. While studying geomechanics, proper weight is given to mechanical properties such as effective mean stress, volumetric strain, etc., and the changes that these properties cause in other properties such as porosity, permeability, and yield state. The importance of analyzing geomechanics increases for complex reservoirs or reservoirs with heavy oil. This project is a case study of the West Sak reservoir in the North Slope of Alaska. Waterflooding has been implemented as enhanced oil recovery method in the reservoir. In this study, a reservoir model is built to understand the behavior and importance of geomechanics for the reservoir. First, a fluid model is built. After that, reservoir simulation is carried out by building two cases: one coupled with geomechanics and one without geomechanics. Coupling geomechanics to simulations led to the consideration of many important mechanical properties such as stress, strain, subsidence etc. Once the importance of considering geomechanical properties is established, different injection and production pressure ranges are used to understand how pressure ranges affect the geomechanical properties. The sensitivity analysis defines safer pressure ranges contingent on whether the formation is yielding or not. The yielding criterion is based on Mohr's Coulomb failure criteria. In the case of waterflooding, injection pressure should be maintained at 3800 psi or lower and production at 1600 psi or higher. And if injection rates are used as the operating parameter, it should be maintained below 1000 bbls/day. It is also observed that injection pressure dominates the geomechanics of the reservoir.
    • Review and case study of electric submersible pump performance with dispersions

      Ellexson, Dexter Bryant; Awoleke, Obadare; Ning, Samson; Dandekar, Abhijit (2020-12)
      Centrifugal pump performance is very sensitive to fluid viscosity, gas fraction, and flow pattern in impeller channels. Viscous oil reduces the head and rate capacity of the pump. High gas fraction reduces the head capacity of the pump at high rates and leads to unstable surging at low rates. If the flow pattern in the impeller transitions to an elongated bubble the pump can gas-lock causing loss of production and excessive heat buildup. The complex geometry and 3-dimensional flow in a pump stage make the analysis of flow in a pump difficult without simplifying assumptions. Empirical and mechanistic models have been developed for correcting pump performance for viscosity, gas fraction, and predicting flow pattern within the impeller with reasonable accuracy. Difficulties arise when produced fluids form stable dispersions. Foams, emulsions, and solid suspensions make the determination of viscosity, gas separation efficiency, and flow pattern more difficult. Interfacial properties between phases become important in determining the bulk fluid properties, and the presence of surfactants exacerbates the interfacial effects. The objective of this project is to describe the fundamentals of electrical submersible centrifugal pumps, ESPs, and the effects that produced fluids have on their performance. These findings are then used to evaluate a case study of an ESP installed in a well with foamy and viscous crude. The ESP exhibits reduced head and rate compared to predicted viscous and gas corrections. Including interfacial effects on the fluid viscosity allow a satisfactory performance match of pump performance to be achieved. The effect of foam on pump performance can be attributed to the increased viscosity exhibited when gas behaves as a dispersed phase in a continuous oil phase rather than a separate phase in a mixture.
    • Simulation and analysis of wellbore stability in permafrost formation with FLAC

      Wang, Kai; Patil, Shirish; Chen, Gang (2015-07)
      Permafrost underlies approximately 80% of Alaska. Permafrost's high sensitivity to temperature variations plays a significant role in the stability of wellbores drilled through permafrost formations. Wellbore instability may cause stuck pipes, lost circulation, and/or collapse of the wellbore, resulting in extra cost and time loss. In order to minimize the influence of the heat produced during drilling, a vertical well is the only choice to penetrate permafrost formation. Fast Lagrangian Analysis of Continua (FLAC) was used in this simulation to test the minimum wellbore pressure to maintain stability in a permafrost formation. Three layers were set in the simulation model: clay, silt, and sand. With the drilling fluid temperature set at 343K and a 267K initial formation temperature, four different thermal times, i.e. 1 week, 1 month, 1 year, and 5 years, were tested to determine the minimum stable pressure. Pore pressure of the formation has the strongest effect on this pressure. And in a short operation period, drilling fluid temperature will not influence the minimum mud pressure value significantly. A regression analysis was conducted on the simulation results, and the minimum wellbore stable pressure was found to be a function of pore pressure, cohesion, frictional angle, temperature difference, conductivity difference, thermal time, and wellbore radius. With the help of this function, engineers could calculate stable pressure for wells in arctic area before drilling based on drilling fluid temperature.
    • A Study of overpressure in the Navarin Basin, Alaska

      Robison, Matthew; Atashbari, Vahid; Ahmadi, Mohabbat; Awoleke, Obadare (2019-12)
      The Navarin basin is a region to the west of Alaska between the Aleutian Islands and Russia. It has been identified as a potential Petroleum prospect, and exploration wells have been drilled under the ocean up to depths of 17,000 feet. The exploration of the basin was started by Russia and the United States with several exploratory wells drilled in the 1980’s. The geology of the region consists of tertiary sedimentary rock deposited during the Eocene age with mudstone and siltstone from Paleogenic deposition. When dealing with such depths, it is expected that the pressure will increase beyond the hydrostatic gradient. Overpressure, when unexpected, can cause blowouts or oil spills as well as danger to the oil production workforce. Herein, the origin of overpressure in this basin is examined using the well log and geological information, and potential mechanisms responsible for generating abnormal pressure are further discussed. In this study, extensive existing well log data are thoroughly examined and organized to facilitate the characterization of overpressure zones in the basin. As a preliminary step, well logs from eight exploratory wells in the Navarin Basin were digitized and organized as the basis of the analysis. Next, overburden pressure is determined for each applicable well in the target area by examining well log and other geological information. Then, a shale discrimination scheme is applied on the log data to differentiate clay-rich formations (that undergo mechanical compaction) from other rock types. Overpressure horizons are identified and examined through velocity, resistivity and other well logging measurements of clay-rich deposits. As such, sonic velocity vs. density and resistivity vs. density cross plots are constructed to identify signatures of different mechanisms of overpressure. Further characterization of the origin of overpressure involves examination of the tectonics, stratigraphy and source rock in order to characterize the pore pressure regime. Finally, pore pressure is calculated using Eaton (1974) and Bowers (1995) method are utilized to calculate pore pressure within the studied wells and degree of confidence in such calculations are examined.
    • A study of waterflood sweep efficiency in a complex viscous oil reservoir

      Jensen, Marc Daniel; Khataniar, Santanu; Dandekar, Abhijit; Patil, Shirish (2014-12)
      West Sak is a multi-billion barrel viscous oil accumulation on the North Slope of Alaska. The unique geologic complexities and fluid properties of the West Sak reservoir make understanding ultimate sweep efficiency under waterflood a challenge. This project uses uncertainty modeling to evaluate the ultimate sweep efficiency in the West Sak reservoir and honors a rich dataset gathered from 30 years of development history. A sector model encompassing the area of the West Sak commercial pilot was developed and a sensitivity analysis conducted to determine the most important parameters affecting sweep efficiency. As part of this process unique constraints were incorporated into the model including measured saturations at the end of history, and observed completion performance. The workflow for this project was documented and can be adapted for use in larger scale models. The workflow includes the development of static cell properties which accurately represent field behavior, a preliminary history match using conventional methods and a sensitivity analysis employing a multi-run visualization tool to effectively navigate and process large amounts of data. The main contributions of this work include the identification of key parameters affecting sweep efficiency in the West Sak oil field, a documented workflow, and increased insight into observed production behavior.
    • Thermal analysis on permafrost subsidence on the North Slope of Alaska

      Agrawal, Neha Dinesh; Patil, Shirish; Chen, Gang; Dandekar, Abhijit; Bray, Matthew (2015-11)
      One of the major problems associated with the oil fields on the North Slope of Alaska is thawing permafrost around producing oil wells. In these wells, the heat from the producing well fluid gradually thaws the permafrost. This thawing in turn destroys the bond between the permafrost and the casing and causes instability that results in permafrost subsidence which further causes subsidence of the soil surrounding the wellbore and, subjects the casing to high mechanical stresses. The above problem has been addressed by several engineers, and several preventive measures, such as controlling the subsidence by refrigeration or by insulation of the wellbore, have been analyzed. Understanding the thermal behavior of the permafrost is imperative to analyzing permafrost subsidence and providing preventative measures. The current project focuses on building a scaled-down axi-symmetric model in FLAC 7.0 that will help us understand the thermal behavior (i.e., the heat input to the permafrost interval due to hydrocarbon production) and temperature distributions that result in permafrost subsidence. The numerical analysis estimated the thaw influence of steam injection used for heavy oil recovery and its effect on the area around the wellbore for 10 years. The developed model was compared with Smith and Clegg (1971) axi-symmetric model and COMSOL model and correlations of thaw radius and wellbore temperatures were obtained for different types of soils. Heat transfer mitigation techniques were also attempted which are discussed in the report further.