Recent Submissions

  • 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.
  • Ugnu pilot area - simulation model and sensitivity analysis

    Wooster, Arin J.; Dandekar, Abhijit; Ning, Samson; Zhang, Yin (2020-05)
    Collaborating with Hilcorp Alaska, LLC, the Ugnu pilot area is the subject of this project. Hilcorp Alaska is conducting field pilot test at Milne Point Field to prove commerciality with Ugnu heavy oil as well as an on-going Milne viscous oil polymer flood field pilot test in the Schrader Bluff sands. The Ugnu sand heavy oil represents much of the heavy oil on Alaska’s North Slope and has potential for future development. Typical heavy oil has a viscosity of 1,000 - 10,000 centipoise, approximately akin to viscosities of honey and molasses, respectively. North Slope heavy oil is located around 3,000-foot depths and typically overlays existing fields. The project involves a reservoir simulation model and sensitivity analysis to support developmental drilling plans from a Milne Point Unit pad. Necessary geologic and reservoir properties were provided for usage in this project by Hilcorp. Production data was provided for history matching. Field geologic background was also supplied to aid in the understanding of the reservoir. The reservoir simulation model was built using Computer Modelling Group software, namely Builder and IMEX. The first model iteration contained one producer in an 8,500-foot lateral pattern. Further iterations included additional producers and injectors for waterflood and polymer flood studies. Conclusions and recommendations were drawn upon analyzing the reservoir simulation results centering around favorable production strategies, polymer flood performance, comparison to the on-going Milne viscous oil polymer flood pilot, and future polymer flood studies. Completed objectives of this project included: 1. Developing a numerical reservoir simulation model for the Ugnu MB sand in the pilot area; 2. Evaluating the productivity of horizontal wells in the Ugnu MB sand; 3. Predicting ultimate oil recovery with waterflood and polymer flood; 4. Predicting polymer utilization, polymer injected per incremental oil barrels over waterflood.
  • 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.
  • Application of design of experiments for well pattern optimization in Umiat oil field: a natural petroleum reserve of Alaska case study

    Gurav, Yojana Shivaji; Dandekar, Abhijit; Patil, Shirish; Khataniar, Santanu; Clough, James; Patwardhan, Samarth (2020-05)
    Umiat field, located in Alaska North Slope poses unique development challenges because of its remote location and permafrost within the reservoir. This hinders the field development, and further leads to a potential low expected oil recovery despite latest estimates of oil in-place volume of 1550 million barrels. The objective of this work is to assess various possible well patterns of the Umiat field development and perform a detailed parametric study to maximize oil recovery and minimize well costs using statistical methods. Design of Experiments (DoE) is implemented to design simulation runs for characterizing system behavior using the effect of certain critical parameters, such as well type, horizontal well length, well pattern geometry, and injection/production constraints on oil recovery. After carrying out simulation runs using a commercially available simulation software, well cost is estimated for each simulation case. Response Surface methodology (RSM) is used for optimization of well pattern parameters. The parameters, their interactions and response are modeled into a mathematical equation to maximize oil recovery and minimize well cost. Economics plays a key role in deciding the best well pattern for any field during the field development phase. Hence, while solving the optimization problem, well costs have been incorporated in the analysis. Thus, based on the results of the study performed on selected parameters, using interdependence of the above mentioned methodologies, optimum combinations of variables for maximizing oil recovery and minimizing well cost will be obtained. Additionally, reservoir level optimization assists in providing a much needed platform for solving the integrated production optimization problem involving parameters relevant at different levels, such as reservoir, wells and field. As a result, this optimum well pattern methodology will help ensure optimum oil recovery in the otherwise economically unattractive field and can provide significant insights into developing the field more efficiently. Computational algorithms are gaining popularity for solving optimization problems, as opposed to manual simulations. DoE is effective, simple to use and saves computational time, when compared to algorithms. Although, DoE has been used widely in the oil industry, its application in domains like well pattern optimization is novel. This research presents a case study for the application of DoE and RSM to well optimization in a real existing field, considering all possible scenarios and variables. As a result, increase in estimated oil recovery is achieved within economical constraints through well pattern optimization.
  • 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.
  • 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.
  • 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.
  • 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.
  • Using rate transient analysis and bayesian algorithms for reservoir characterization in hydraulically fractured horizontal gas wells during linear flow

    Yuhun, Pirayu; Awoleke, Obadare; Ahmadi, Mohabbat; Hanks, Catherine (2019-05)
    Multi-stage hydraulically fractured horizontal wells (MFHWs) are currently a popular method of developing shale gas and oil reservoirs. The performance of MFHWs can be analyzed by an approach called Rate transient analysis (RTA). However, the predicted outcomes are often inaccurate and provide non-unique results. Therefore, the main objective of this thesis is to couple Bayesian Algorithms with a current production analysis method, that is, rate transient analysis, to generate probabilistic credible interval ranges for key reservoir and completion variables. To show the legitimacy of the RTA-Bayesian method, synthetic production data from a multistage hydraulically fractured horizontal completion in a reservoir modeled after Marcellus shale reservoir was generated using a reservoir (CMG) model. The synthetic production data was analyzed using a combination of rate transient analysis with Bayesian techniques. Firstly, the traditional log-log plot was produced to identify the linear flow production regime, which is usually the dominant regime in shale reservoirs. Using the linear flow production data and traditional rate transient analysis equations, Bayesian inversion was carried out using likelihood-based and likelihood-free Bayesian methods. The rjags and EasyABC packages in statistical software R were used for the likelihood-based and likelihood-free inversion respectively. Model priors were based (1) on information available about the Marcellus shale from technical literature and (2) hydraulic fracture design parameters. Posterior distributions and prediction intervals were developed for the fracture length, matrix permeability, and skin factor. These predicted credible intervals were then compared with actual synthetic reservoir and hydraulic fracture data. The methodology was also repeated for an actual case in the Barnett shale for a validation. The most substantial finding was that for all the investigated cases, including complicated scenarios (such as finite fracture conductivity, fracturing fluid flowback, heterogeneity of fracture length, and pressure-dependent reservoir), the combined RTA-Bayesian model provided a reasonable prediction interval that encompassed the actual/observed values of the reservoir/hydraulic fracture variables. The R-squared value of predicted values over true values was more than 0.5 in all cases. For the base case in this study, the choice of the prior distribution did not affect the posterior distribution/prediction interval in a significant manner in as much as the prior distribution was partially informative. However, the use of noninformative priors resulted in a loss of precision. Also, a comparison of the Approximate Bayesian Computation (ABC) and the traditional Bayesian algorithms showed that the ABC algorithm reduced computational time with minimal loss of accuracy by at least an order of magnitude by bypassing the complicated step of having to compute the likelihood function. In addition, the production time, number of iterations and tolerance of fitting had a minimal impact on the posterior distribution after an optimum point--which was at least one-year production, 10,000 iterations and 0.001 respectively. In summary, the RTA-Bayesian production analysis method implemented in relatively easy computational platforms, like R and Excel, provided good characterization of all key variables such as matrix permeability, fracture length and skin when compared to results obtained from analytical methods. This probabilistic characterization has the potential to enable better understanding of well performance, improved identification of optimization opportunities and ultimately improved ultimate recovery from shale gas resources.
  • 3-D modeling of interaction between a hydraulic fracture and multiple natural fractures using finite element analysis

    Talukder, Debashish; Awoleke, Obadare; Ahmadi, Mohabbat; Hanks, Catherine (2019-05)
    A three-layered, 3-D geo-mechanical model was developed using Finite Element Analysis (FEA) software (ABAQUS) to simulate single stage hydraulic fracturing treatment in a synthetic fractured model based on available shale information from literature. The main objectives of this study were- (i) to investigate the interaction between a hydraulic fracture (HF) orthogonally intersecting two parallel natural fractures (NF) and (ii) to identify significant parameters and their 2-factor interactions that affect HF propagation in the presence of multiple NFs. Based on literature review, an initial set of 20 parameters (a combination of geologic and drilling parameters) was selected. Those parameters were believed to affect the hydraulic fracture propagation in a naturally fractured model. Experiments were conducted in two stages. First-order order numerical experiments were conducted under the Plackett-Burman experimental design. Central Composite Design (CCD) was used to check curvature and to take care of non-linearity existing in the dataset. A stepwise sensitivity analysis and parametric study were conducted to identify significant parameters and their interactions. When the HF interacted with NFs, there were three possible outcomes- the HF either got arrested, dilated or crossed the NF. The overall hydraulic fracture geometry depended on the type of interaction behavior occurring at the intersection. The NF leakoff coefficient was the most significant factor in the 1st order experiments that affected the HF propagation in the presence of multiple NFs. CCD results suggested that NF strength at the bottom shale layer and injection fluid viscosity significantly influenced the HF opening in the presence of the natural fractures. The most significant two-factor interaction was the interaction between stress contrast and Young's modulus of the overburden shale (Ytop). This study will help understand the interaction behavior between a HF and two pre-existing NFs. The parametric study will provide a valuable insight for hydraulic fracturing treatment in a naturally fractured formation.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • Scaling laws in cold heavy oil production with sand reservoirs

    Robertson, Keith W. III; Awoleke, Obadare; Peterson, Rorik; Ahmadi, Mohabbat; Liu, Jenny (2018-08)
    This thesis presents a rigorous step by step procedure for deriving the minimum set of scaling laws for Cold Heavy Oil Production with Sand (CHOPS) reservoirs based on a given set of physical equations using inspectional analysis. The resulting dimensionless equations are then simulated in COMSOL Mutiphysics to validate the dimensionless groups and determine which groups are more significant by performing a sensitivity analysis using a factorial design. The work starts simple by demonstrating how the above process is done for 1D single-phase flow and then slowly ramps up the complexity to account for foamy oil and then finally for wormholes by using a sand failure criterion. The end result is three dimensionless partial differential equations to be solved simultaneously using a finite element simulator. The significance of these groups is that they can be used to extrapolate between a small scale model and a large scale prototype.
  • 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.
  • 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.
  • 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.
  • 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.

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