Browsing by Subject "Petroleum engineering"
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Item Analysis of high pressure effects on wellbore integrity using the distinct element method(2012-05) Amamoo, Stacey J.; Ziaja, Malgorzata; Awal, Rafiqul M.; Siddiqui, ShameemIt is a proven fact that the analysis of the formation, casing and cement is of utmost importance in the maintenance of wellbore integrity. This has been done so far utilizing the continuity numerical methods such as finite element method together with experimental methods. In using finite element method to analyze wellbore integrity taking into consideration the formation, cement and casing, the discontinuity of their interaction is lost and as such fractures and other mechanisms such as debonding cannot be modeled. The main objective of this research is to utilize the distinct element method in analyzing wellbore instability so as to avoid or greatly minimize failure in wellbores. In this paper, the cement- formation bond and cement-casing bond is thoroughly discussed as well as their effect and contribution to well integrity. The ITASCA Particle flow code software is used. It is validated and then used to analyze a horizontal well using parameters from the Barnett Shale.Item Application of fracturing technology in improving volumetric sweep efficiency in enhanced oil recovery schemes(2012-05) Pirayesh, Elias; Soliman, Mohamed Y.; Menouar, Habib K.; Siddiqui, ShameemThe industry has developed methods to improve sweep efficiency during Enhanced Oil Recovery processes. These methods include the use of certain injection/production patterns, drilling horizontal and deviated wells, use of special chemicals as well as inflow control devices (ICDs). The purpose of the first two methods is to create an even movement of injection fluid across the reservoir. Special chemicals have been used to divert the injected fluid to eliminate channeling and to improve sweep efficiency. Inflow control devices have been used to delay water or gas breakthrough, making possible a more efficient drainage of the reservoir while maximizing production and recovery. The technique presented in this work creates a mechanical barrier to flow by introducing a fracture to the formation at a strategic location. This fracture is then filled with a conformance fluid which eventually becomes impermeable to fluid flow. The effects of various design parameters on the performance of barrier-fractures have been investigated and the results are presented. These design parameters include barrier-fracture length & location, number of barrier-fractures, and mobility ratio. It is illustrated that the breakthrough time and potential productivity of producing wells increase as a result of enhancing the volumetric sweep efficiency of hydrocarbons.Item Capillary pressure determination using the micropore membrane technique(2012-05) Williams, Akinlolu; Siddiqui, Shameem; Watson, Marshall C.; Menouar, Habib K.Generation of capillary pressure curves is essential to the evaluation of fluid flow phenomenon in the multi-phase region of a reservoir. It is used chiefly for the determination of oil and gas water contacts, the location of transition zones and modeling oil displacements through either water or gas flooding. Unfortunately its measurement is made unattractive by the time-consuming nature of its generation which could be up to six months in some cases. The micropore membrane technique of capillary pressure determination is a novel approach introduced by the Institut Français du Pétrole- IFP, which has the capacity to reduce the time required to generate a full suite of capillary pressure curves, namely – spontaneous imbibition, drainage and imbibition cycles to about a tenth of the time required for conventional methods such as the porous diaphragm restored state method. This research work was conducted to build a setup for capillary pressure measurement that replaces the conventional mercury injection and restored state techniques currently in use in the department’s core analysis laboratory. The setup was used to perform four distinct drainage runs on sandstones and dolomite with different petrophysical properties. Soltrol130-Brine pair was used for the fluid system while all the rock samples were characterized as water-wet. The drainage capillary pressure curves generated were analyzed on the basis of petrophysical analytical tools like pore entry pressure, irreducible water saturation and pore size distribution index. A homogeneity and heterogeneity correlation was established amongst the samples based on the shape of the drainage curves and the analytical tools and this trend was validated using CT scan images which were carried out on the dry core samples. Mercury injection capillary pressure (MICP) test was conducted on one of the samples and a very good match was obtained between the micropore membrane technique and MICP. Further validation of this method was carried out by conduction a re-run on one sample to ensure repeatability of the procedure and accuracy of data collected. The results of the re-run showed an excellent match with the initial run to validate the procedure and accuracy of the data acquisition process of this technique. The success of the validation process and the functionality, flexibility and dynamism of the experimental setup and also the reliability of the procedure all borne out of the reliability of results obtained, with each experiment concluded in about 24hours using reservoir fluids confirms the micropore membrane technique to be a robust, simple, convenient and time efficient method for the generation of representative capillary pressure data for reservoir rock samples.Item Decline curve analysis in unconventional resource plays using logistic growth models(2011-08) Clark, Aaron James; Lake, Larry W.; Patzek, Tadeusz W.Current models used to forecast production in unconventional oil and gas formations are often not producing valid results. When traditional decline curve analysis models are used in shale formations, Arps b-values greater than 1 are commonly obtained, and these values yield infinite cumulative production, which is non-physical.. Additional methods have been developed to prevent the unrealistic values produced, like truncating hyperbolic declines with exponential declines when a minimum production rate is reached. Truncating a hyperbolic decline with an exponential decline solves some of the problems associated with decline curve analysis, but it is not an ideal solution. The exponential decline rate used is arbitrary, and the value picked greatly effects the results of the forecast. A new empirical model has been developed and used as an alternative to traditional decline curve analysis with the Arps equation. The new model is based on the concept of logistic growth models. Logistic growth models were originally developed in the 1830s by Belgian mathematician, Pierre Verhulst, to model population growth. The new logistic model for production forecasting in ultra-tight reservoirs uses the concept of a carrying capacity. The carrying capacity provides the maximum recoverable oil or gas from a single well, and it causes all forecasts produced with this model to be within a reasonable range of known volumetrically available oil. Additionally the carrying capacity causes the production rate forecast to eventually terminate as the cumulative production approaches the carrying capacity. The new model provides a more realistic method for forecasting reserves in unconventional formations than the traditional Arps model. The typical problems encountered when using conventional decline curve analysis are not present when using the logistic model. Predictions of the future are always difficult and often subject to factors such as operating conditions, which can never be predicted. The logistic growth model is well established, robust, and flexible. It provides a method to forecast reserves, which has been shown to accurately trend to existing production data and provide a realistic forecast based on known hydrocarbon volumes.Item An electric circuit network model for fluid flow in oil reservoir(2010-12) Munira, Sirajum; Flake, Robert H.; Bostick, Francis X.Interwell connectivity is a very important piece of the puzzle for petroleum engineers. To optimize the injection well flow for increasing the production rate, interwell connectivity is a very important parameter. To build a model that works with better precision and with less effort has always been desired by reservoir engineers. In this study we developed an electric circuit network model (referred as the admittance or ymodel) for calculating the admittance parameters to predict branch flow rates (injectorproducer well pair) of oil reservoirs with precision. The y-model is very simple and efficient model that can predict branch flow very efficiently. Injection and production flow rates are the key data used in this model, which also happens to be the most abundant data for oil reservoirs. Injector well bottom-hole pressure data can also be used in this model if available. The governing equation of the electric circuit analogy of well to well flow rates in the oil reservoir is based on Ohm’s law for admittance. A mathematical procedure is also being developed for this circuit network model which solves a series of equations and finds unique solutions for the admittances and branch flows. These results can further be used for predicting the production flow rate for individual producer well. The model shows very good agreement with the exploration data of real oil reservoir.Item Impact of fracture creation and growth on well injectivity and reservoir sweep during waterflooding and chemical EOR processes(2012-05) Lee, Kyung Haeng; Sharma, Mukul M.; Huh, Chun; Balhoff, Matthew T.; Pope, Gary A.; Bonnecaze, Roger T.During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance. In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery. In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated. The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery.Item Implementation of full permeability tensor representation in a dual porosity reservoir simulator(2001-08) Li, Bowei; Miller, Mark A.; Sepehrnoori, Kamy, 1951-Item Mathematical model of the central battery for a major oil producing field(Texas Tech University, 1976-05) Skinner, David RandellNot available.Item The History of Secondary Recovery of Oil in the United States(Texas Tech University, 1953-05) Carmack, Roy P.Not Available.Item The history of secondary recovery of oil in the United States(Texas Tech University, 1953-05) Carmack, Roy P.Not availableItem Two-dimensional ASP flood for a viscous oil(2014-12) Aitkulov, Almas; Mohanty, Kishore KumarThere is a vast deposit of viscous and heavy oil, especially in Canada and Venezuela. Typically thermal methods are used to recover heavy oil. However, thermal methods are inefficient when the depth of the reservoir is high and pay thickness is low. Non-thermal methods need to be developed for viscous and heavy oils. Alkaline-surfactant-polymer (ASP) floods can be used for improving the displacement efficiency, but its effect on sweep efficiency in viscous oil recovery has not been studied. The objective of this research was to investigate 2D ASP floods in a quarter five-spot pattern. Through careful phase behavior screening, the surfactant formulation was developed that produced ultra-low interfacial tension with reservoir viscous oil (100 cp). After verifying that the design of surfactant formulation was robust and can recover more than 90% of oil in a 1D ASP sandpack flood, it was tested in a 2D geometry. Both stable and unstable tertiary ASP floods were performed in a 2D quarter five-spot sandpack using the surfactant formulation developed in 1D ASP sandpack flood. In a stable ASP quarter five-spot sandpack flood, the oil recovery was excellent (~97% of ROIP). Oil recovery in the stable 2D ASP flood behaved similar to oil recovery in the 1D stable ASP flood. However, pressure drop obtained was high which would be unsustainable in field applications. Interestingly, unstable 2D flood performed well even with an adverse mobility ratio between oil/water bank and ASP slug with a recovery of 80% ROIP. Decreasing the viscosity of ASP slug 6 times decreased the maximum pressure drop 5 times; thus, the maximum pressure drop was almost proportional to the ASP slug viscosity in a 2D pattern. This research showed that unstable ASP flood in a 2D geometry can recover significant amount of oil with a practical pressure gradient.Item Using 3D printing for the instruction of petrophysical properties(2014-08) Dees, Elizabeth Ann; Prodanović, Maša; Allen, David T.With the recent increase in natural gas production, the demand for college educated petroleum engineers has increased. A greater number of high school graduates are now applying to petroleum engineering degree programs, however, the admission requirements to petroleum engineering schools are becoming increasingly stricter. Secondary educators have a greater challenge to better prepare students to compete for these positions and there is a need to introduce petrophysical concepts to students in the most effective manner. One petrophysical concept is porosity of rock. In this report, background information on rock formation and porosity of rocks is provided along with a brief summary on how 3D printers operate. But primarily, a lesson plan is presented to teach rock porosity in a novel way using 3D printed enlargements of porous rock from x-ray microtomography images of packed sand. The hypothesis was that students will gain greater understanding of petrophysical properties when using 3D prints of rocks. The porosity lesson with a lab using the 3D printed rocks was taught to a treatment group of 20 upcoming 6th graders. A porosity lesson without the use of 3D printed rocks was didactically taught to a control group of 14 additional 6th graders. Because of time limitations, not all of the students from the treatment group were able to experience all elements of the lab. However, every student in the control group received instruction and practice on how to calculate porosity of rock. The treatment group showed greater gain in learning the abstract concept about porosity that rocks of similar structure will have equivalent porosity regardless of grain size. However, the control group indicated greater gain learning the fundamental concepts of the definition of porosity, how to calculate porosity, and at being able to transfer their knowledge of percent porosity to a general problem about percentages. Despite the limited sample size and other sources of error, using 3D printed enlargements of rock was found to enhance students’ abilities to visualize abstract petrophysical properties. However, benefits from didactic instruction of fundamental concepts of petrophysical properties were found as well.