• Economic evaluation of gas to liquids (GTL), crude oil commingled product transportation through the Trans Alaska Pipeline System (TAPS)

      Ibironke, Adejoke Motunrayo; Patil, Shirish L.; Chukwu, Godwin A.; Khataniar, Santanu A.; Reynolds, Douglas B.; Dandekar, Abhijit (2004-12)
      The Alaska North Slope is a potential candidate for the Gas to Liquid (GTL) technology. With over 38 TCF of natural gas reserves stranded on the Alaska North Slope, the GTL technology is considered as a possible method of harnessing the abundant resources. GTL fuels are environmentally friendly (sulfur free) with better ignition and burning properties than conventional petroleum products from crude oil. Economic evaluation using Rate of Return analysis and the Net Present Value (NPV) to identify the most favorable commingled mode for the transportation of the GTL products was performed. The Crystal Ball software was also used to run sensitivity analysis by using the probabilistic approach to give a clear view of the various scenarios on the project economics. Evaluating the options of transporting GTL products as a blend (Commingled) with the Alaska North Slope Crude Oil through the existing Trans-Alaska Pipeline System (TAPS) is the main focus of this study.
    • Economics of gas to liquids technology for monetization of Alaska North Slope Natural gas reserves

      Ogugbue, Chinenye C. E.; Chukwu, Godwin A.; Khataniar, Santanu; Patil, Shirish; Dandekar, Abhijit Y. (2006-08)
      The proven natural gas reserves of the Alaska North Slope (ANS) have enormous potential as clean-burning energy resources, if they can be effectively and efficiently utilized. These gas resources, exceeding 35 trillion cubic feet (TCF), currently represent a significant proportion of the energy equivalence of proven ANS oil reserves. With ANS located far from potential markets, there is need to evaluate the prospective economics of promising technologies for monetization of these stranded gas reserves. The economics of the chemical conversion of natural gas to synthetic liquid fuels favored by recent advances in FT synthesis techniques, liquid fuel transportation for the Trans Alaskan Pipeline System (TAPS) operations, and increased demand for clean burning diesel fuels, was the main focus of this study. Economic evaluation using Internal Rate of Return (IRR) analysis, Payout Time and the Net Present Value (NPV) to access and compare the economic viability of 3-train and 4-train GTL Projects is performed. Monte-Carlo simulation using the Crystal Ball software was utilized to run sensitivity analysis, incorporating the probabilistic approach, which generated insightful scenarios on the project economics.
    • The effect of capillary pressure on methane gas recovery from gas hydrates: a simulation study

      Stone, Christopher L. (2006-05)
      A simulation study on the effects of capillary pressure on methane gas recovery from methane hydrates was conducted using STOMP-HYD. Four stimulation recovery methods were examined in the study; thermal stimulation, depressurization above the Q-point, depressurization below the Q-point, and CO₂ micro-emulsion injection. Van Genuchten parameters pertaining to moisture retention characteristics for soil types ranging from coarse to fine grained were introduced into the simulations to quantify what role capillary force plays in methane gas recovery. It was observed that greater capillary forces resulted in gas production occurring sooner in all four stimulation cases. It was found that greater aqueous saturations resulted due to the higher capillary forces. The greater aqueous saturation allow for greater heat transfer through the porous media. As a result of greater heat transfer, CH₄ hydrates dissociate sooner in the cases where high capillary forces were observed, lending to faster production rates.
    • 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.
    • Equation of state model development and compositional simulation of enhanced oil recovery using gas injection for the West Sak heavy oil

      Morye, Ganesh G.; Patil, Shirish; Dandekar, Abhijit; Khataniar, Santanu (2007-12)
      West Sak oil field, with its very huge reserves of heavy oil, has the potential of supplementing the declining light oil production on the Alaska North Slope. Due to the heavy nature of oil, its phase behavior is very complex. A proper understanding of the phase behavioral changes of the West Sak oil is crucial to design any enhanced oil recovery scheme. Such Enhanced Oil Recovery (EOR) techniques are essential in the absence of natural drive mechanisms in these reservoirs. For the proper selection of any EOR technique, reservoir simulation studies should prove its viability. Accordingly, a complete phase behavior analysis of the West Sak crude oil was carried out. All the available experimental data was scrutinized and a model equation of state was developed that should describe the phase behavior of West Sak oil. After having done that, reservoir simulation was carried out to study the implications of employing gas injection as an EOR technique for the West Sak reservoir. It was found that a definite increase in heavy oil production can be obtained with proper selection of injectant gas and optimized reservoir operating parameters. A comparative analysis is provided which should help in making such a decision.
    • Evaluation of coalbed methane resource potential using limited data

      Olaniran, Oluwabiyi Michael; Ogbe, David O.; Zhu, Tao; Patil, Shirish L. (2005-05)
      This study presents the results of the evaluation of the Coalbed Methane (CBM) resource potential of the Cook Inlet Basin using a computer-aided well log analysis of the subsurface data. Coal seams were identified from the well logs. Formation and reservoir fluid properties including porosity, water saturation and net pay thickness of the coal seams were determined. The analysis revealed discontinuous coal seams interspaced largely by mudstone, silt, and sandstone formations within the depth of investigation. The CBM resource (Original Gas In Place) and recoverable reserves were estimated on per acre-foot basis. Monte Carlo simulation was run to refine the estimated CBM reserves and to allow for variations in the measured petrophysical input parameters used in the resource evaluation.
    • 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.
    • An evaluation of oilfield drilling fluid rheological properties at low shear rate ranges for hydraulic flow models

      Pan, Weizhong (2002-05)
      The hydraulic calculation requires the selection of a best fit model from some models used in petroleum industry. Especially, at low shear rate. This study is based on the data taken from ten wells to evaluate five models- Bingham plastic, Power Law, Casson, Herschel-Bulkley, and Robertson-Stiff for hydraulic optimization. In the course of optimizing, statistical method was used to evaluate all the data using linear regression and least square methods. Calculations were made to determine the rheological parameters, correlation coefficients and relative errors. Comparison was also made to the correlation coefficients and relative errors for selecting the best model for optimizing the hydraulics of specific drilling fluids. In order to verify the optimized results, the pressure losses both inside the drillpipe and the annulus and the Equivalent Circulating Density (ECD) were calculated by using these five models. Data obtained from Herschel-Bulkley model presented the most accurate results.
    • Evaluation of the modes of transporting GTL products through the Trans-Alaska Pipeline System (TAPS)

      Akwukwaegbu, Chinedu Franklyn (2001-05)
      Gas-to-liquids (GTL) conversion technology, where natural gas is chemically converted to transportable hydrocarbon liquid products, is an emerging technology that will undoubtedly reach commercialization within the next decade. Two GTL transportation modes, that could be used to exploit vast Alaska Natural Gas resources in the form of stable liquid through the Trans-Alaska Pipeline System (TAPS), are evaluated either as single slugs (batches) or commingled (mixed) with Crude Oil. In this study, thee pertinent energy equations are solved for both batch and commingled flow modes. The solutions of these equations are analytically presented for determining among other parameters, the pressure gradient and pertinent slug length required for batching. The application of the determined hydraulic parameters will aid in the analysis and economic evaluation of the GTL transportation modes through the Trans-Alaska Pipeline System (TAPS).
    • Experimental and economic evaluation of GTL fluid flow properties and effect on TAPS

      Ramakrishnan, Hariharan (2000-12)
      In this study, procedures are outlined to recondition and sample crude oil from high-pressure Welker cylinders. Standard laboratory procedures are developed to determine viscosity and density properties of crude oil, GTL and their mixtures. The steps needed to ensure Quality Assurance and Project Plan (QAPjp) is given in detail. A calibration macro is written to automate viscometer calibration calculations. A preliminary economic model is developed to evaluate GTL transportation options. Viscosity and density are measured for various samples at different temperatures. The reproducibility of the results is found to be within 5%. Batching is more preferable then blending for the parameter values considered in the economic model. In brief, GTL option appears to be a feasible way of utilizing Alaskan North Slope (ANS) gas resources and increasing the lifetime of TAPS, if suitable advancement in GTL conversion technology results in a substantial reduction in capital investment.
    • Experimental investigation of low salinity enhanced oil recovery potential and wettability characterization of Alaska North Slope cores

      Patil, Shivkumar B. (2007-12)
      Rock wettability and the chemical properties of the injection water influence fluid distribution and multiphase fluid flow behavior in petroleum reservoirs and hence it consequently affects the final residual oil saturation. Many researchers have proven that oil recovery is increased by decreasing the salinity of water used for waterflooding process. Three sets of experiments were conducted on representative Alaska North Slope (ANS) core samples to experimentally ascertain the influence of injected brine/fluid composition on wettability and hence on oil recovery in secondary oil recovery mode. All the sets of experiments examined the effect of brine salinity variation on wettability and residual oil saturation of representative core samples. The core samples used in the first and third set were new (clean) while in the second set core samples were oil aged. For first and second sets laboratory reconstituted 22,000 TDS, 11,000 TDS and 5,500 IDS (total dissolved solids) brines were used while for the third set ANS lake water was used. Oil aging of core decreased the water wetting state of cores slightly. This observation could be attributed to adsorption of polar compounds of crude oil. The general trend observed in all the coreflood experiment was reduction in Sor (up to 20%) and slight increase in the Amott-Harvey Wettability Index with decrease in salinity of the injected brine at reservoir temperature.
    • 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.
    • Experimental investigation on the transportation of commingled blends of gas-to-liquid (GTL) products and Alaskan heavy crude oil through the Trans-Alaska Pipeline System (TAPS)

      Igbokwe, Chidiebere G. C.; Dandekar, Abhijit Y.; Chukwu, Godwin A.; Patil, Shirish L.; Khataniar, Santanu (2006-08)
      Heavy oil deposits in the West Sak and Ugnu formations are currently considered as potential resources to address the issue of declining oil production on Alaska's North Slope (ANS). Similarly, an estimated proven and recoverable ANS gas reserve of 38 trillion cubic feet (TCF) can be converted to high premium Gas-to-Liquid products which may be commingled with Alaskan heavy oil products. These commingled blends of GTL and Alaska heavy oil can be transported through the Trans Alaska Pipeline System (TAPS). The primary operational issues that could affect the transportation of these fluids through TAPS are: pump ability of the heavy oil, cold restart following a prolonged shut down, and solid deposition in the pipeline. Since TAPS was originally designed to carry light to medium, low viscosity crude oil, transporting heavy or viscous oil may cause problems with the overall hydraulics. In this study, ANS crude oil was distilled and the heavy fraction cuts (~18° API gravity) were commingled with ANS crude oil and GTL samples for evaluation. Density and viscosity results showed that addition of GTL significantly reduced heavy oil viscosity to present TAPS conditions. However, solid deposition was observed to be a potential problem.
    • 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.
    • Experimental study of solid deposition and vapor pressure in gas-to-liquid and crude oil mixtures for trasportation through the Trans Alaska Pipeline System

      Amadi, Samuel Uche (2003-08)
      Chemical conversion of Alaska North Slope (ANS) gas to liquid and subsequently transporting it through the Trans Alaska Pipeline System (TAPS) is a means of bringing the ANS gas to the market. However, transporting the gas-to-liquid (GTL) product with ANS crude oil through the Trans Alaska Pipeline System (TAPS) may pose some operational challenges. The major issue of concern relates to the asphaltene and wax deposition problems in the pipeline, as well as the vapor pressure of GTL and GTL/crude oil blends. In this study, experiments were carried out to determine the degree to which GTL is a flocculant of asphaltene. The stability/instability of the ANS crude to asphaltene deposition, as well as the wax appearance temperature of various cuts of GTL and GTL/crude oil blends were also determined. The results show that GTL is a possible flocculant of asphaltene, however, ANS is stable to asphaltene deposition. The results also show that GTL has a high wax appearance temperature, which raises a concern under arctic conditions. The Reid vapor pressure test results from this study show no consistent trend. This is because the GTL samples used have been flashed already as a result of sample withdrawal from the container by previous researchers. Thus the sample did not meet both the ASTM and IP requirements for Reid vapor test.
    • 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.
    • Geologic description and reservoir modeling of a Jurassic aged, low permeability, light oil reservoir, northern coastal plain, Alaska

      Newell, Jack Robert (2001-05)
      The objectives of the study include the analysis of the geologic description and reservoir modeling of a Jurassic aged, low permeability, light oil reservoir on the northern coastal plain of Alaska. The methodology of the study was to use a reservoir simulation model to evaluate the performance and cumulative recovery of the reservoir under primary depletion and a water injection process. Results of the simulation showed a primary recovery of 15.9 %OOIP of oil by solution gas drive. The results of thee simulation by a water displacement process showed that 41.9 %OOIP oil could be recovered with a production of 38.5 %HCPV of the injected water. This study has an application in determining estimates of the design paramaters for surface facilities required for the development of the field.
    • Geological modeling and reservoir simulation of Umiat: a large shallow oil accumulation

      Oraki Kohshour, Iman; Dandekar, Abhijit; Hanks, Catherine; Ahmadi, Mohabbat; Dandekar, Abhijit (2013-05)
      Current high oil price and availability of new technologies allow re-evaluation of oil resources previously considered uneconomic. Umiat oil field is one such resource: a unique, shallow (275-1055 feet), low-pressure (200-400 psi) reservoir within the permafrost zone located north of the Arctic Circle, 80 miles west of Trans Alaska Pipeline System (TAPS) with an estimated 1.5 billion barrel of oil-in-place. This thesis presents a reservoir model that incorporates recently identified permeability anisotropy patterns within the Cretaceous Nanushuk sandstone reservoir to evaluate various potential mechanisms such as horizontal wells and immiscible gas injections. The simulation model focuses on the Lower Grandstand which is identified as a better reservoir rock. The reservoir temperature is assumed at 26 OF and gas is injected at the same temperature to maintain equilibrium with the permafrost and prevent any well integrity problems. An optimum horizontal well length of 1500 ft was found and applied for all simulation cases. The simulation results show that with 50 years of lean gas injection, recovery factors for the base case and case of 600 psi injection pressures are 12% and 15%, respectively, keeping all other parameters constant.
    • 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.