• 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.
    • Adaptation of engineering education in emerging technological revolution: a review

      Agbaraji, Casmir I. (2000-05)
      The future of engineering education has been a subject of concern in past years. There is no doubt that changes are needed to keep abreast with the new tools of technology and business, and to attract students. The planning of curricula should be governed by the definition of an engineer as the creator for public goods and by the demands of the industry. The tools that were available for engineering education in the past, those that are being presently used, and the techniques that dominate in the twenty-first century are analyzed. The problems associated with the new engineering education are discussed. The areas of engineering education that need improvement are highlighted. The current role of engineers in organization is analyzed. Engineering education will be challenged as never before, to shape the nature and quality of life in the twenty-first century. Engineering education will be at the forefront to meet these challenges.
    • Alkali-surfactant-polymer (ASP) flooding - potential and simulation for Alaskan North Slope reservoir

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

      Banerjee, Sudiptya; Patil, Shirish L.; Chukwu, Godwin A.; Khataniar, Santanu; Chen, Gang (2005-08)
      Traditional Portland cement has been used in the oilfield industry for over a hundred years in the United States. However, under the harsh cold of arctic conditions, cement has failed to provide the minimum standards of strength and safety required in the petroleum industry. Though there has been significant research to correct this shortcoming, no ideal solution has been found to improve the arctic performance of Portland cement. A chemically-bonded phosphate ceramic, known generically as Ceramicrete, has been developed which appears attractive as a cement replacement in arctic well construction. This material contains no Portland cement and does not have its limitations under cold conditions. It uses the same equipment in terms of storage and production as the Portland cement. In this research, Ceramicrete was vigorously tested according to industry-specifications in order to compare its material behavior against that of Portland cement as a viable alternative under arctic oilfield conditions.
    • Analysis of a chemically-bonded phosphate ceramic as an alternative oilfield cementing system for Arctic regions

      Limaye, Nilesh; Patil, Shirish L.; Chen, Gang; Khataniar, Santanu; Chukwu, Godwin A. (2007-12)
      Novel chemically bonded phosphate ceramic borehole sealant, i.e. Ceramicrete, has many advantages over conventionally used permafrost cement at Alaska North Slope (ANS). However, in normal field practices when Ceramicrete is mixed with water in blenders, it has a chance of being contaminated with leftover Portland cement. In order to identify the effect of Portland cement contamination, recent tests have been conducted at BJ services in Tomball, TX as well as at the University of Alaska Fairbanks with Ceramicrete formulations proposed by the Argonne National Laboratory. The tests conducted at BJ Services with proposed Ceramicrete formulations and Portland cement contamination have shown significant drawbacks which has caused these formulations to be rejected. However, the newly developed Ceramicrete formulation at the University of Alaska Fairbanks has shown positive results with Portland cement contamination as well as without Portland cement contamination for its effective use in oil well cementing operations at ANS.
    • 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.
    • 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.
    • Approximate bayesian computation for probabilistic decline curve analysis in unconventional reservoirs

      Paryani, Mohit; Ahmadi, Mohabbat; Hanks, Catherine; Awoleke, Obadare (2015-12)
      Predicting the production rate and ultimate production of shale resource plays is critical in order to determine if development is economical. In the absence of production from the Shublik Shale, Alaska, Arps' decline model and other newly proposed decline models were used to analyze production data from oil producing wells in the Eagle Ford Shale, Texas. It was found that shales violated assumptions used in Arps' model for conventional hydrocarbon accumulations. Newly proposed models fit the past production data to varying degrees, with the Logistic Growth Analysis (LGA) and Power Law Exponential (PLE) models making the most conservative predictions and those of Duong's model falling in between LGA and PLE. Using a regression coefficient cutoff of 95%, we see that the LGA model fits the production data (both rate and cumulative) from 81 of the 100 wells analyzed. Arps' hyperbolic and the LGA equation provided the most optimistic and pessimistic reserve estimates, respectively. The second part of this study investigates how the choice of residual function affects the estimation of model parameters and consequent remaining well life and reserves. Results suggest that using logarithmic rate residuals maximized the likelihood of Arps' equation having bounded estimates of reserves. We saw that approximately 75% of the well histories that were fitted using the logarithmic rate residual had hyperbolic b-values < 1, as opposed to 40% using the least squares error function--an 87.5% increase. This is because they allow the most recent production data to be weighted more heavily, thereby ensuring that the fitted parameters reflect the current flow regime in the drainage area of the wells. In the third part of this work, in order to quantify the uncertainty associated with Decline Curve Analysis (DCA) models, a methodology was developed that integrated DCA models with an approximate Bayesian probabilistic method based on rejection sampling. The proposed Bayesian model was tested by history matching the simulation results with the observed production data of 100 gas wells from the Barnett Shale and 21 oil wells from the Eagle Ford Shale. For example, in Karnes County, the ABC P90-P50-P10 average interval per well was 170-184-204 MSTB, while the true average cumulative production per well was 183 MSTB. The ABC methodology coupled with any deterministic DCA model will help in long-term planning of operations necessary for optimal/effective field development.
    • Assessment of formation damage from drilling fluids dynamic filtration in gas hydrate reservoirs of the North Slope of Alaska

      Kerkar, Prasad B.; Patil, Shirish L.; Chukwu, Godwin A.; Dandekar, Abhijit Y.; Khataniar, Santanu (2005-08)
      Gas hydrates in the Alaska North Slope, with a potential of 590 TCF gas-in-place near existing infrastructures of Prudhoe Bay, Kuparuk River and Milne Point Units, have sparked interest among unconventional energy experts. Drilling through gas hydrates has always been critical as a source of heat into the formation, leading to dissociation of hydrates. Moreover, the recent drive toward open hole completions and highly deviated or horizontal wells have emphasized the need for evaluation of drilling or completion fluids suitability from a perspective of formation damage. A significant decrease in well productivity near the well-bore can occur due to the invasion of fine solids from drilling fluids, forming external and internal filter cake under dynamic conditions. An experimental setup for the evaluation of formation damage at in-situ conditions was designed. The dynamic filtration experiments were conducted with Berea sandstone cores. The absolute permeability was measured both before and after the drilling fluid circulation. The drilling fluid type, its flow rate, and shear rate, effective particle size, additive concentration, and amount of overbalance were found to influence drilling mud leak-off volume and the post mud circulation permeability.
    • Assessment of tight gas sands in Cook Inlet Basin

      Patel, Kanhaiyalal U.; Ogbe, David O.; Zhu, Tao; Patil, Shirish L. (2005-05)
      The Cook Inlet Basin is the source for all of the natural gas used in south-central Alaska. The estimated ultimate recovery from existing Cook Inlet gas fields is approximately 8.5 trillion cubic feet (tcf) and the proven reserves remaining on January 1, 2004 were 1.8 tcf. It will be difficult to meet the peak demand for gas in south-central Alaska after 2009. Cook Inlet Basin contains vast quantities of unconventional gas resources in tight sands. Resources-in-place and producible gas reserves from the tight sands are unknown. It is likely that these tight sands will be developed as additional gas reserves and will be produced along with the high permeability conventional gas reserves in order to meet both local and export demands. The objectives of this study are to quantify the distribution of tight gas sands; to estimate the resources in place and producible gas reserves in the Cook Inlet Basin; and to predict the post-stimulation gas production. Rate transient analysis, well log analysis and reservoir stimulation analysis were therefore conducted on selected key tight sand wells. Results indicate that the tight gas can play an important role in meeting south-central Alaska's gas demand beyond 2009.
    • Better understanding of production decline in shale gas wells

      Harongjit, Kananek; Ahmadi, Mohabbat; Patil, Shirish; Dandekar, Abhijit (2014-08)
      Production data from the Eagle Ford shale (an analog to the Alaska Shublik shale) was collected from two neighboring counties and analyzed to correlate well performance with completion parameters including length of horizontal wellbore and number of hydraulic fracturing stages. Thirty-eight dry gas wells with production history range of 18-43 months were analyzed using 6 different decline curve analysis (DCA) models including Arps' exponential, harmonic and hyperbolic, power law exponential (PLE), logistic growth analysis (LGA) and Duong's models. In the matching process, 2/3 of history was used to tune the DCA models and their forecasts were compared to the remaining 1/3 of real history. The matching results were analyzed based on production history length and flow regime to have better understanding of limitations and capabilities of each DCA model. Reservoir simulation models, constructed using range of realistic data and actual completion practices of 4 select wells, were employed to assess reasonable values of remaining reserve and remaining well life that were used as benchmarks for comparison with DCA results. The results showed that there was no strong correlation between well performance (average first year production rate) and the horizontal leg or the number of fracturing stages. This was an indication of extremely heterogeneous medium. In most cases, the accuracy of the DCA models increased when longer production history was used to tune the model parameters. LGA seems to be the most accurate DCA model since it gave the highest matching accuracy 71% of the total wells when using longest history length of 31 months. As the flow regime is concerned, LGA model also performed very well matched in 57% of the wells exhibiting only transient flow and 63% for the wells showing transient flow during early production time followed by boundary-dominated flow during late production. Moreover, the remaining reserve and well life of the select wells predicted by LGA fell into reasonably close range of the estimates from the reservoir simulations.
    • Characterization and fluid flow properties of frozen rock systems of Umiat Oil Field, Alaska

      Godabrelidze, Vasil (2010-12)
      The Umiat field, located in northwestern Alaska between the Brooks Range and the Arctic Ocean, potentially contains the largest accumulation of oil in Naval Petroleum Reserve No.4. Most of the oil is found within the permafrost zone. The main oil-producing zones in the Umiat field are marine sandstones in the Grandstand Formation of the Cretaceous Nanushuk group. Although the temperatures are close to freezing, the oil in the Umiat field remains unfrozen due to its very high API gravity. However, this results in a very unique pore space containing frozen water and oil, posing a particular challenge to characterization and measurement of fluid flow properties necessary for production. The unsteady-state gas-oil relative permeability measurement experiments were conducted in order to obtain critical information about the properties of two-phase fluid flow through the Umiat porous medium. Fluid flow experiments at 22°C and -10°C on representative core samples from the Umiat field showed 61% average decline in oil relative permeability as a result of freezing irreducible water. Capillary pressure measurement experiments were also carried out on selected core samples with an intention of characterizing their pore size distribution. Subsequently obtained data indicates fairly wide range of pore size for Umiat cores.
    • Characterization of Alaska North Slope oils for wax deposition

      Anyanwu, Okechukwu Ndubuisi; Zhu, Tao; Chukwu, Godwin A.; Dandekar, Abhijit; Zhou, Wendy (2007-08)
      Wax deposition during crude oil production is a major problem that has plagued the oil industry for decades especially in cold environments such as Alaska North Slope (ANS) fields, with adverse consequences in huge mitigation cost and lost production. It is therefore imperative to adequately and accurately identify the conditions for wax precipitation and deposition in order to optimize operation of the production systems of ANS. In order to assess ANS crude's potential for wax precipitation, Viscometry and Cross Polarization Microscopy (CPM) are used to determine the temperature at which paraffins begin to precipitate from ANS dead oils. Wax dissolution temperatures (WDT) are also determined by CPM. Results show that wax precipitation is possible at temperatures as high as 41°C (106°F) while it takes up to 50°C (122°F) to get all waxes back into solution. The CPM technique was more sensitive while Viscometry results did not provide a high level of certainty in some samples and therefore appear over-estimated relative to CPM results. Previous thermal history was observed to influence test results. Pour point, viscosity, density and specific gravity have also been measured. Pour point results indicate that oil could form gel in the temperature range 12°C (53.6°C) to less than -31°C ( -23.8°F).
    • Chemical and microbial characterization of North Slope viscous oils for MEOR application

      Ghotekar, Ashish L.; Patil, Shirish; Khataniar, Santanu; Dandekar, Abhijit (2007-12)
      Viscous oil reservoirs tend to be low-energy, low-gas/oil-ratio systems with high viscosities and are difficult to produce, transport and refine by conventional methods. Some of the commonly considered viscous oil recovery methods include processes such as steam flooding, in-situ combustion and miscible gas injection. The large viscous oil deposits in the ANS cannot be produced entirely by conventional methods like pressure displacement or waterflooding. Other methods such as miscible (gas injection and water alternating gas (WAG) also have limited success. Microbial enhanced oil recovery (MEOR) is one of the techniques for improving the oil recovery for viscous deposits. This method has not yet been applied to the ANS fields. This study includes experimental work to analyze the application of MEOR to the ANS oil fields. A microbial formulation was developed in order to simulate the MEOR. Coreflooding experiments were performed to simulate the improved recovery oil recovery and quantify the incremental oil recovery. Properties like viscosity, density and chemical composition of oil were monitored to propose a mechanism of oil recovery. Terminal restriction fragment length polymorphism (T-RFLP) was performed on the oil samples to qualitatively study the effect of the microbial formulation on a molecular scale.
    • Comparative economic evaluation of the options for transporting the Alaska North Slope stranded gas

      Eke, Chineme R.; Chukwu, Godwin A.; Patil, Shirish L.; Reynolds, Douglas; Dandekar, Abhijit Y.; Khataniar, Santanu (2006-08)
      The most effective economic parameter often considered in feasibility analysis is the Return On Investment (ROI). Any Alaskan gas pipeline project is expected to have a high return on investment to be considered economic. A Comparative Economic (CE) model was used in this study to analyze the gas pipeline project options. These options are: The Alaskan Canadian (AlCan) Highway stand alone gas pipeline project, the AlCan Highway gas pipeline with an instate spurline to southern Alaska, the All-Alaskan Liquefied Natural Gas (LNG) Project, the All- Alaskan LNG project with a spur line to southern Alaska, and the Gas-To-Liquid (GTL) project. The CE model makes use of the Crystal Ball and some input parameters like cost, taxes, tariffs and price to determine the economic feasibility of each option based on the ROI, payout period and total revenue accrued from each project. It was shown from the analysis that the AlCan Highway stand-alone pipeline project had the highest return on investment of 33%. This was followed by the AlCan Highway gas pipeline with an instate spurline to southern Alaska with return on investment of 32.6%. The all-Alaskan LNG projects proved feasible but with less return on investment compared to other options.
    • A comprehensive analysis of the oil fields of the North Slope of Alaska: their use as analogs, recent exploration, and forecasted royalty and production tax revenue

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

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

      Delaihdem, Dieudonne K.; Dandekar, Abhijit; Ahmadi, Mohabbat; Hanks, Catherine (2013-12)
      Transient and fracture dominated flow regimes in tight permeability shale reservoirs with hydraulically fractured horizontal wells impose many unconventional challenges. These include execution of appropriate shale decline curve analysis and the optimization of hydrocarbons recovery. Additionally, short production profiles available are inadequate for accurate production decline analysis. This research assessed the effectiveness of Arps' decline curve analysis and recently established methods--power law exponential analysis, logistic growth analysis, Duong's method and the author's approach--to predict future production of horizontal wells in the Eagle Ford Shale. Simulation models investigated history matching, enhanced shale oil recovery, and drainage area beyond stimulated reservoir volume. Traditional Arps' hyperbolic method sufficiently analyzed past production rates, but inaccurately forecasted cumulative productions. The recent decline models show slight variations in their past performance evaluations and forecasting future production trends. The technique proposed and used in this work enhanced the successful application of Arps' hyperbolic decline from 32.5% to 80%. Simulation results indicate 4.0% primary oil recovery factor and 5.8% enhanced shale oil recovery factor using CO��� miscible injection. Based on pressure observed outside of the stimulated reservoir volume, limited to the range of data used in this study, drainage area outside stimulated reservoir volume is not significant.
    • Determination of methane hydrate stability zones in the Prudhoe Bay, Kuparuk River, and Milne Point units on the North Slope of Alaska

      Westervelt, Jason V. (2004-05)
      Estimates range from approximately 37 to 44 trillion cubic feet of in-place gas in methane hydrate from within the Eileen Trend of the Prudhoe Bay (PBU), Kuparuk River (KRU), and Milne Point (MPU) Units on the North Slope of Alaska (Collett, 1993). This study was based on measuring pressure and temperature conditions for hydrate dissociation. The results showed that the depth of the hydrate stability zone (HSZ) ranges from 585 to 780 meters. The results from this study also show that the HSZ in the Alaska North Slope (ANS) is thinning westward. This study also showed that the effect of formation brines typically found on the North Slope only affects the depth of the hydrate stability zone by 30 to 45 meters when a porous media is not present. Experiments carried out on a porous media sample provided by the Anadarko Corporation showed that the formation brines only affect the depth of the hydrate stability zone by 10 to 15 meters. Geothermal gradients, gas composition, and the type of porous media play the biggest role in the thickness of the HSZ. These variables are also the most important when determining the depth to the HSZ.