Recent Submissions

  • 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.
  • 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.
  • Experimental investigation of low salinity water flooding to improve viscous oil recovery from the Schrader Bluff Reservoir on Alaska North Slope

    Cheng, Yaoze; Zhang, Yin; Dandekar, Abhijit; Awoleke, Obadare; Chen, Gang (2018-05)
    Alaska's North Slope (ANS) contains vast resources of viscous oil that have not been developed efficiently using conventional water flooding. Although thermal methods are most commonly applied to recover viscous oil, they are impractical on ANS because of the concern of thawing the permafrost, which could cause disastrous environmental damage. Recently, low salinity water flooding (LSWF) has been considered to enhance oil recovery by reducing residual oil saturation in the Schrader Bluff viscous oil reservoir. In this study, lab experiments have been conducted to investigate the potential of LSWF to improve heavy oil recovery from the Schrader Bluff sand. Fresh-state core plugs cut from preserved core samples with original oil saturations have been flooded sequentially with high salinity water, low salinity water, and softened low salinity water. The cumulative oil production and pressure drops have been recorded, and the oil recovery factors and residual oil saturation after each flooding have been determined based on material balance. In addition, restored-state core plugs saturated with viscous oil have been employed to conduct unsteady-state displacement experiments to measure the oil-water relative permeabilities using high salinity water and low salinity water, respectively. The emulsification of provided viscous oil and low salinity water has also been investigated. Furthermore, the contact angles between the crude oil and reservoir rock have been measured. It has been found that the core plugs are very unconsolidated, with porosity and absolute permeability in the range of 33% to 36% and 155 mD to 330 mD, respectively. A produced crude oil sample having a viscosity of 63 cP at ambient conditions was used in the experiments. The total dissolved solids (TDS) of the high salinity water and the low salinity water are 28,000 mg/L and 2,940 mg/L, respectively. Softening had little effect on the TDS of the low salinity water, but the concentration of Ca²⁺ was reduced significantly. The residual oil saturations were reduced gradually by applying LSWF and softened LSWF successively after high salinity water flooding. On average, LSWF can improve viscous oil recovery by 6.3% OOIP over high salinity water flooding, while the softened LSWF further enhances the oil recovery by 1.3% OOIP. The pressure drops observed in the LSWF and softened LSWF demonstrate more fluctuation than that in the high salinity water flooding, which indicates potential clay migration in LSWF and softened LSWF. Furthermore, it was found that, regardless of the salinities, the calculated water relative permeabilities are much lower than the typical values in conventional systems, implying more complex reactions between the reservoir rock, viscous oil, and injected water. Mixing the provided viscous oil and low salinity water generates stable water-in-oil (W/O) emulsions. The viscosities of the W/O emulsions made from water-oil ratios of 20:80 and 50:50 are higher than that of the provided viscous oil. Moreover, the contact angle between the crude oil and reservoir rock in the presence of low salinity water is larger than that in the presence of high salinity water, which may result from the wettability change of the reservoir rock by contact with the low salinity water.
  • 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.
  • Dying intestate or with a will on toxic estate? an evaluation of petroleum fiscal systems and the economic and policy implications for decommissioning of onshore crude oil fields in Nigeria

    Afieroho, Erovie-Oghene Uyoyou-karo; Patil, Shirish L.; Dandekar, Abhijit; Reynolds, Douglas B.; Perkins, Robert (2018-05)
    Many giant fields in the world like the onshore fields in Nigeria which were initially discovered over half a century ago, have begun to see consistent decline in production and profit, and are gradually entering into the economic end of field life or decommissioning phase. Characteristically, in most regions with mature fields, the large multinational oil companies have begun to sell their oil fields to small indigenous companies who may not be financially robust enough to complete the decommissioning, when it occurs. Because of the pervasive societal impact of the oil industry, if an investor fails to properly decommissioning the infrastructure, a responsible government will have to pay for the proper decommissioning, else society will suffer the socioeconomic, political, health and environmental impact. Therefore, society needs to be effectively engaged in the development of a sustainable decommissioning policy framework, which is hindered if society is uninformed and lacks access to pertinent information. Currently, there is abysmal information in the public space on the cost of decommissioning liabilities of oil fields, especially in developing countries like Nigeria. The public also need simple interpretative ways to determine the vulnerability of a county or entity to decommissioning default risk and the imminence of a default risk. Furthermore, there is currently, no way to benchmark the level of maturity or level of preparedness for decommissioning phase such that countries and entities can identify their gaps to a sustainable decommissioning policy framework and define a roadmap to close the gaps. These are important challenges to vigorous public participation, which is an essential requirement for development and implementation of any sustainable public policy for a public issue like decommissioning of crude oil fields. This study adopted several research methods to develop and introduce a new cost estimating methodology that uses publicly declared cost of asset retirement obligations (ARO) to determine a plausible cost estimate range for decommissioning liabilities. It was demonstrated with Nigeria onshore crude oil fields, which it determined to have a rough order of magnitude cost estimate for decommissioning liabilities that could be as high as $3 billion. Secondly, it also introduced decommissioning coverage ratio (DCR) and decommissioning coverage ratio vector (DCRV) as new metrics to evaluate the vulnerability to and imminence of decommissioning default risk. In demonstrating these new metrics, this study determined that the imminence of and vulnerability to decommissioning default risk for the onshore crude oil fields in Nigeria, with respect to any of the available revenue streams, is high. Thirdly, it developed a graded scale maturity model for sustainable decommissioning of petroleum fields. The model described as Fairbanks maturity model for sustainable decommissioning in the petroleum industry, has five progressive levels of maturity. It leveraged the methodology used for similar maturity models developed in other industries and for business management, and a comparative analysis of level of progress in decommissioning frameworks between some countries with leading decommissioning experience in the petroleum industry, to develop the Fairbanks maturity model. Based on the Fairbanks maturity model, frameworks for sustainable decommissioning of Nigeria onshore crude oil fields were evaluated to be at Level 1, Ad hoc maturity level, which is the lowest maturity level. Recommendations to close the identified gaps were also were made. These methodologies can be applied to any petroleum producing region or entity in the world and are advancements to the frontier of knowledge in the management of decommissioning phase for petroleum fields in general and Nigeria onshore fields in particular.
  • Correcting Oil-Water Relative Permeability Data For Capillary End Effect In Displacement Experiments

    Qadeer, Suhail (1988)
    By neglecting the effect of capillary forces, the relative permeabilities calculated by the method of Johnson, Bossler, and Neumann or Jones and Roszelle from low rate displacement experiments are in error.<p> In this study, steady state and displacement experiments were carried out. A history matching package along with a fully implicit numerical simulator and a Welge type model were developed and the displacement data were analyzed by history matching to quantify these errors. A modified centrifuge drainage bucket was used to obtain drainage and imbibition capillary pressure data.<p> The results show that in the case of drainage the non-wetting phase end point relative permeabilities and saturation exponents increase with an increase in rate. However the saturation exponent for the wetting phase decreases with rate. The wetting phase end point relative permeability stayed more or less constant with rate. In the case of imbibition these parameters did not indicate any meaningful rate dependent trend. <p>
  • Electromagnetic heating of unconventional hydrocarbon resources on the Alaska North Slope

    Peraser, Vivek; Patil, Shirish L.; Khataniar, Santanu; Sonwalkar, Vikas S.; Dandekar, Abhijit Y. (2012-05)
    The heavy oil reserves on the Alaska North Slope (ANS) amount to approximately 24-33 billion barrels and approximately 85 trillion cubic feet of technically recoverable gas from gas hydrate deposits. Various mechanisms have been studied for production of these resources, the major one being the injection of heat into the reservoir in the form of steam or hot water. In the case of heavy oil reservoirs, heat reduces the viscosity of heavy oil and makes it flow more easily. Heating dissociates gas hydrates thereby releasing gas. But injecting steam or hot water as a mechanism of heating has its own limitations on the North Slope due to the presence of continuous permafrost and the footprint of facilities. The optimum way to inject heat would be to generate it in-situ. This work focuses on the use of electrical energy for heating and producing hydrocarbons from these reservoirs. Heating with electrical energy has two variants: high frequency electromagnetic (EM) heating and low frequency resistive heating. Using COMSOL ® multi-physics software and hypothetical reservoir, rock, and fluid properties an axisymmetric 2D model was built to study the effect of high frequency electromagnetic waves on the production of heavy oil. The results were encouraging and showed that with the use of EM heating, oil production rate increases by ~340% by the end of third year of heating for a reservoir initially at a temperature of 120°F. Applied Frequency and input power were important factors that affected EM heating. The optimum combination of power and frequency was found to be 70 KW and 915 MHz for a reservoir initially at a temperature of 120°F. Then using CMG-STARS ® software simulator, the use of low frequency resistive heating was implemented in the gas hydrate model in which gas production was modeled using the depressurization technique. The addition of electrical heating inhibited near-wellbore hydrate reformation preventing choking of the production well which improved gas production substantially.
  • Production optimization and forecasting of shale gas wells using simulation models and decline curve analysis

    Ikewun, Peter O.; Kamel, Ahmed; Hanks, Catherine; Ahmadi, Mohabbat (2012-08)
    Production data from the Eagle Ford shale (an analogue to the Shublik shale of Alaska) was compiled from three neighboring counties and analyzed using decline curve analysis (DCA) to correlate production performance with completion method (horizontal leg/stages of fracture) and length of horizontal leg. Generic simulation models were built and run using a realistic range of properties. Simulation results provided a better understanding of interplay between static properties and dynamic behavior. Results from the DCA of 24 producing wells with production histories of 9-57 months showed, for most cases, an increase in reserves with more fracture stages. However, the DCA generated different forecasts depending on which part of the data were used. This clearly indicated the need for running simulations. Simulation runs can generate more reliable production forecast of which the decline part can be used to evaluate the capability of DCA to reproduce the production profiles. A combination of simulation models and DCA was used to optimize production and forecasting. Simulation models were used to optimize production for a range of different reservoir and completion parameters. The ability for DCA to reproduce simulated results (built with similar data from the Eagle Ford) for wells with different production periods was also analyzed. This results in better and more reliable production forecasts for the Eagle Ford and other young producing shale reservoirs possessing short production history. Modeling of the complex reservoir geometry and fracture networks of these types of reservoirs would give an extensive understanding of the flow mechanics.
  • Evaluation of CO₂ sequestration through enhanced oil recovery in West Sak reservoir

    Nourpour Aghbash, Vahid (2013-05)
    CO₂ enhanced oil recovery (EOR) has been proposed as a method of sequestering CO₂. This study evaluates using CO₂ as an EOR agent in the West Sak reservoir. The injected CO₂ mixes with the oil and reduces the oil viscosity, enhancing its recovery. A considerable amount of CO₂ is left in the reservoir and 'sequestered'. Due to low reservoir temperature, this process can lead to formation of three hydrocarbon phases in the reservoir. An equation of state was tuned to simulate the West Sak oil and complex phase behavior of the CO₂-oil mixtures. A compositional simulator capable of handling three-phase flash calculation and four-phase flow was used to simulate CO₂ injection into a three-dimensional heterogeneous pattern model. The results showed that CO₂ EOR in the West Sak reservoir increases oil recovery by 4.5% of original oil in place and 48 million metric tons of CO₂ could be sequestered. Ignoring four-phase flow underestimated oil recovery and sequestered CO₂ volume. Enriching the CO₂ with natural gas liquid decreased sequestered CO₂ volume without a significant increase in oil recovery. Dissolution of CO₂ in the water phase and different water/CO₂ slug sizes and ratios did not change the sequestered CO₂ volume and oil recovery.
  • Meta-analysis of hydraulic fracture conductivity data

    Rahman, Mohammed Rashnur; Awoleke, Obadare O.; Goddard, Scott; Ahmadi, Mohabbat (2017-12)
    Previous empirical models of propped fracture conductivity are based either on data sourced from single investigations or on data not in the public domain. In this work, statistically rigorous models of propped fracture conductivity are developed using a database of fracture conductivity experiments reported in technical literature over the last 40 years. The database contains the results from about 2700 experimental runs. Propped fracture conductivity is the dependent variable and proppant types, mesh size, proppant concentration, formation hardness, closure stress, formation temperature, and polymer concentration are the independent variables. The mother database is partitioned into subsets; that is different databases with each daughter database having complete information in relation to the dependent and independent variables. As a result, the number of independent variables included in the daughter databases varied from three to six. Seventy percent of the data was used to develop the models while 30% of the data was used to validate them. First, fixed effect models were developed using regression analysis. Afterwards, three, four and five factor models were compared for two types of proppant: sand and ceramic proppant. The five factor model appeared to be the most prominent one. The analysis was further carried out using five factors of these two types of proppant. Mixed effect modeling was employed because of the disparate sources of the data and also the temporal diversity of the dataset. The mixed effect model appeared to be the better than the fixed effect model while compared the error terms. Also, because the mother database contained some missing values, two statistical imputation approaches were employed to predict the missing values which are categorical imputation and multiple imputation using chained equations. Imputations are employed because it is speculated that a model developed using a large number of data points should provide better predictions. Generally, the mean squared error (MSE) is less in the mixed effect model for sand and in the categorical imputation model for ceramic proppant. But, to be more precise on the performance of the models, model predictions were compared with an existing propped fracture conductivity model and different case histories published in literature. Subsequently, the models of this research can be arranged in order of predictive performance: multiple imputation model, mixed effect model, fixed effect/categorical imputation model. The results also indicate that mesh size, closure stress, formation hardness, and proppant concentration significantly affect fracture conductivity from a statistical point of view. Formation temperature and polymer concentration affect conductivity negatively but they were not statistically significant. Engineers will have access to a propped fracture conductivity database based on experiments reported over the past 40 years in technical literature. Engineers can use the models developed based on this database to generate statistical distributions of propped fracture conductivity for a variety of proppant characteristics and formation conditions. The models presented here are based on data from experimental investigations in different laboratories thereby reducing the bias that may be present in single laboratory investigations.
  • Implications of pore-scale distribution of frozen water for the production of hydrocarbon reservoirs located in permafrost

    Venepalli, Kiran Kumar (2011-08)
    Frozen reservoirs are unique with the extra element of ice residing in them along with the conventional components of a reservoir. The sub-zero temperatures of these reservoirs make them complicated to explore. This study investigates reduction in relative permeability to oil with decrease in temperature and proposes a best-production technique for reservoirs occurring in sub zero conditions. Core flood experiments were performed on two clean Berea sandstone cores under permafrost conditions to determine the sensitivity of the relative permeability to oil (kro) over a temperature range of 23°C to -10°C and for connate water salinities ranging from 0 to 6467 ppm. Both cores showed maximum reduction in relative permeability to oil when saturated with deionized water; they showed minimum reduction when saturated with 6467 ppm of saline water. Theoretically, the radius of ice formed in the center of the pore can be determined using the Kozeny-Carman Equation by assuming the pores and pore throats as a cube with 'N' identical parallel pipes embedded in it. With obtained values of kro as input to the Kozeny-Carman Equation at -10°C, the radius of ice dropped from 0.145 [upsilon]rn to 0.069 [upsilon]rn when flooding, water salinity is increased to 6467 ppm. This analysis quantifies the reductions in relative permeability solely due to different formation salinities. Other parameters like fluid saturations and pore structure effects also are discussed. Fluids like deionized water, saline water, and antifreeze (a mixture of 60% ethylene or propylene glycol with 40% water) were tested to find the best flooding agent for frozen reservoirs. At 0°C, 9% greater recovery was observed with antifreeze than with saline water. Antifreeze showed 48% recovery even at -10°C, at which temperature the rest of the fluids failed to increase production.
  • TEST College of Natural Sciences and Mathematics 9/25/17

    CHISUM (2017-09)
    TEST College of Natural Sciences and Mathematics 9/25/17
  • Low salinity water alternate gas injection process for Alaskan viscous oil EOR

    Saxena, Kushagra; Ahmadi, Mohabbat; Patil, Shirish; Dandekar, Abhijit; Brugman, Robert; Zhang, Yin (2017-05)
    Carbon dioxide has excellent oil swelling and viscosity reducing characteristics. CO₂ injection alternated with water has shown substantial incremental recovery over waterflood for the Alaska North Slope (ANS) viscous oil reservoirs. However, for any project, the ultimate CO₂ slug size is finite and once the apportioned solvent volume is used up, the reservoir oil rates gradually revert to the low waterflood rates during the later life of a field. Low salinity waterflooding (LSWF) has also shown some promise based on corefloods and single well tracer tests in North Slope light oil reservoirs. However, two challenges impede its implementation as a standalone enhanced oil recovery (EOR) option on the North Slope: 1) slow response; the delay prolonged with increasing oil viscosity and 2) large upfront investments for the processing and transport of source water. This study proposes a hybrid EOR scheme, the low salinity water alternate gas (LSWAG) process, for the viscous fields of the ANS. The process was modeled by coupling geochemical and ion exchange reactions to a CO₂-WAG type pattern model of the Schrader Bluff O sand. The Schrader Bluff reservoir has been classified suitable for low salinity EOR based on its permeability, temperature, clay content, and oil and formation water properties. Oil recovery through wettability alteration was modeled through ion exchange at the clay sites. Multiphase compositional flow simulation was run using numerical dispersion control. LSWAG forecast for 50 years following 36 years of high salinity waterflood recovered 15% OOIP more oil over high salinity waterflood and 4% incremental over high salinity WAG. This translates to an improvement of 58% and 11% over waterflood and conventional WAG respectively. Higher oil rates were observed during later life due to increased oil relative permeability caused by the low salinity mechanism. Furthermore, very low solvent utilization values were seen for LSWAG which can be tied to the higher ultimate oil recovery potential of using low salinity water over conventional waterflood. In summary, LSWAG outperformed LSWF and conventional WAG by synthesizing the oil swelling and viscosity reduction advantages of CO₂ with lower residual oil benefits of LSWF, while overcoming the challenges of the late response of LSWF and low waterflood oil rates during later life in a conventional WAG flood.
  • Life after CHOPS: the Alaskan heavy oil reservoir perspective

    Mathur, Bakul; Dandekar, Abhijit; Khataniar, Santanu; Patil, Shirish (2017-05)
    The heavy oil reservoirs in Alaska offer major production challenges, including proximity to the permafrost layer, very high viscosity oil and low mechanical strength pay zones. The Ugnu deposits of the Alaska North Slope (ANS) hold more than 6 billion barrels of oil. The dead oil viscosity at reservoir temperature ranges from 1,000 to 1,000,000 cp1. In an effort to sustain well life, this research focuses on the unique set of challenges occurring in the Ugnu reservoir and presents the best possible way to maximize production. The present research accentuates observations derived from the field data, which shows that deliberate sand production with the hydrocarbon stream while employing a Progressive Cavity Pump (PCP) as an artificial lift method has a favorable effect on primary oil recovery. The developments have led to the advent of a technique called Cold Heavy Oil Production with Sand (CHOPS) as an initial production method for shallow heavy oil reservoirs. Sand production leads to the formation of high porosity channels or wormholes that can range up to hundreds of meters. The co-mingling of heavy oil and sand develops foamy oil by creating a bubbly flow inside the reservoir. The combination of these wormholes with the foamy oil behavior are the primary factors that result in enhanced production during CHOPS. One of the major hindrances to its successful application is the selection of the post-CHOPS production method, which is addressed in this study with the help of modeling and simulation. Alternative recovery techniques following the primary cold production include water flooding, polymer injection, miscible gas injection and thermal recovery methods. Water flooding is unviable because of the mobility contrast between the highly viscous oil and water. The high permeability zones provide a bypass for water, consequently producing elevated water cuts. Another aspect unique to Alaskan heavy oil reservoirs is the proximity to the permafrost layer, with the hydrocarbon bearing zone making thermal recovery methods unappealing. Polymer injection and miscible gas injection become the favorable non-thermal secondary and tertiary recovery methods in this case. This study is based on modeling one of the wells drilled into the M80 sands of the Ugnu formation followed by the analysis of post-CHOPS recovery for the well. The CHOPS well modeling is done with the help of a wormhole fractal pattern and a foamy oil model. Simulation of the polymer injection is then employed from a nearby well. The results indicate almost 12% increment in recovery with polymer flooding as compared to the natural depletion. The recovery obtained from the simulations have been analyzed to provide a basis for designing the polymer injection job as an Enhanced Oil Recovery (EOR) method after CHOPS. With the promising results of this study, it can be determined that the Ugnu reservoir sands can be exploited for heavy oil with the help of polymer flooding. It can also be combined with miscible gas flooding or alkali-surfactant flooding to obtain even higher hydrocarbon recoveries.
  • Feasibility study of in-situ heat generation for oil reservoirs underlying the permafrost

    Kargarpour, Mohammad Ali; Ahmadi, Mohabbat; Awoleke, Obadare; Hanks, Catherine (2017-05)
    Development of a heavy oil reservoir is a challenging issue in the oil industry. One of the major issues in heavy oil recovery is its high viscosity; so, using heating methods for producing oil have been developed and employed from the early 1950s. The existing relatively thick permafrost layer which overlays the heavy oil reservoirs of the North Slope of Alaska creates additional complexities for development of these heavy oil reservoirs. Applying any heating oil recovery process in regular way to these heavy oil Alaskan reservoirs would potentially jeopardize the permafrost layer. A down-hole heat generation system has been developed that uses a chemical and a special catalyst to generate heat. The effluent of this system would be steam and nitrogen. The system can be installed in a well string and at the bottom of the injector well. This thesis investigates the feasibility of employing this system for development of the heavy oil reservoirs that underlie the permafrost. The results of this study can be used for any steam injection process which uses any device for down-hole steam generation. The STARS module of the CMG reservoir simulation package is used for this study. In the model, live oil with a viscosity of about 30,000 cp is used. By examining several models with vertical and horizontal wells, a 3-D model with two horizontal injector and producer wells is ultimately constructed for final runs. Different sensitivities are run to find out the optimum operational parameters. Based on the results, a lateral well length of 800 ft in the middle of a reservoir with length of a 1250 ft is selected as a base case. Areal grid block size of 10 ft × 10 ft with the layer thickness of 10 ft in a reservoir with thickness of 50 ft is employed. To minimize the down-hole well bore temperature of the producer, just the last 50 ft (out of 800 ft of lateral length) at the toe of the well is opened to flow. Three different steam injection processes are examined: Steam Assisted Gravity Drainage (SAGD), Cyclic SAGD (CSAGD) and Cyclic Steam Stimulation (CSS). Simulation results reveal that the producer well bore temperature in optimum cases for SAGD, CSAGD and CSS is more than 140 ˚F, 110 ˚F and 100 ˚F, respectively. Also, the 10-year simulation period oil recoveries for optimum cases of SAGD, CSAGD and CSS are about 35%, 18% and 12%, respectively. On the other hand, results show applying any steam injection recovery method (SAGD, CSAGD or CSS) can only be recommended when the thickness of the overlying Sagavanirktok sand formation (which separates the permafrost from the heavy oil reservoir) is equal or more than 300 ft. The results also show that the addition of nitrogen has negative effect on the oil recovery. Based on the results, it is recommended to employ SAGD or CSAGD, but employ a system to cool the producer well-string to avoid melting the permafrost. A simple system of cooling the producer well-string is suggested.
  • Experimental study of multiphase flow of viscous oil, gas and sand in horizontal pipes

    Hulsurkar, Panav; Awoleke, Obadare; Ahmadi, Mohabbat; Patil, Shirish (2017-05)
    The oil and gas industry relies on multiphase flow models and correlations to predict the behavior of fluids through wells and pipelines. Significant amount of research has been performed on the multiphase flow of different types of liquids with gases to extend the applicability of existing models to field-specific fluid conditions. Heavy oil and gas flow research commenced in the past decade and new correlations have been developed that define their flow behavior/regimes. This study aims to plant a foot in the quite deficient area of multiphase flow research that focuses on a sufficiently common situation faced by many heavy oil producing fields: the presence of sand in wells and pipelines. This study will be the first recorded attempt to understand the multiphase flow of heavy oil, gas, and sand. A 1.5" diameter multiphase flow loop facility capable of handling solids was designed and constructed for the study. Data logging instruments were calibrated and installed to be able to withstand the erosive effects of sand. The flow loop was leak and pressure tested with water and air. Three oils of 150, 196 and 218 cP viscosities were utilized to gather 49 single phase liquid, 227 two-phase liquid- air and 87 three-phase liquid, air and solid multiphase flow data points which included differential and absolute pressures, fluid flow rates, temperatures, liquid and composite liquid- solid hold- up data and photo and videotaping of the observed flow regimes. Validation of the setup was performed using single phase flow of oil and two-phase flow of oil and air. Sand was added in three different concentrations to the 218 cP oil and three-phase oil, gas and sand multiphase flow tests were performed. Flow patterns were identified and flow pattern maps were created using acquired data. No change was observed on flow pattern transitions by changing oil viscosities. Liquid hold- up and differential pressures were compared to observe the effect of changing oil viscosity and the presence of sand in varying concentrations on the two-phase flow of oil and gas and the three-phase flow of oil, gas and sand respectively. An increase in differential pressures was observed with increasing viscosities and the addition of sand. No changes in hold-up were seen with changing oil viscosities rather flow patterns impacted liquid hold-up significantly. The slug flow pattern was analyzed. Composite liquid-solid hold-up in slug flow were physically measured and predicted. Liquid slug lengths were predicted and compared with observed lengths using photo and videography techniques. Differential pressures and liquid hold-up were compared with existing multiphase flow models in the PIPESIM multiphase flow simulator to test model predictions against observed flow data. The dependence of differential pressure gradients and liquid hold-up on dimensionless variables was realized by performing normalized linear regressions to identify the most significant dimensionless groups and the results were given a mathematical form by proposing correlations for differential pressure and hold-up predictions. To the best of our knowledge, this study is the first attempt at systematically measuring pressure drop and liquid hold up during the three-phase flow of oil, gas and sand.
  • Petrophysical property modeling of Umiat Field, a frozen oil reservoir

    Levi-Johnson, Obioma I.; Hanks, C. L.; Mongrain, J.; McCarthy, P. J.; Dandekar, A. (2010-08)
    Umiat field, a frozen oil reservoir, is situated in the folded and thrust-faulted Cretaceous sedimentary rocks at the leading edge of the Brooks Range foothills of northern Alaska. The main oil reservoirs are between 500-1400 feet deep and in permafrost. The main oil-producing zones in the Umiat field are the Grandstand shoreface sandstones. Statistical analyses of the porosity and permeability of the Upper and Lower sands indicate that the sands have distinct petrophysical characteristics. A plot of cumulative flow capacity versus cumulative storage capacity (i.e. Modified Lorenz Plot) defined the flow structures of the Upper and Lower sands in Umiat well # 9. The observed heterogeneities can be correlated with very fine-grained sediments observed in the conventional core of the interval. A petrophysical property model of Umiat field was built consistent with the existing data and geologic knowledge about the reservoir. This model will be used in the future to test various production strategies for Umiat field. Based on this model, the estimated oil in place is 1.2 billion stock tank barrels and the associated gas is 84 billion standard cubic feet.

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