Tesis sobre el tema "Petroleum engineering"

In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale.

Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10 ^–1–10^–2 mD) and in the vertical direction (~10^–4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^–5 to 10 ^–8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation.

Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.

The objective of this study is threefold: 1) Build a dual-porosity, geological reservoir model of Niobrara formation in the Wishbone Section of the DJ Basin. 2) Use the geologic static model to construct a compositional model to assess performance of Well 1N in the Wishbone Section. 3) Compare the modeling results of this study with the result from an eleven-well modeling study (Ning, 2017) of the same formation which included the same well. The geologic model is based on discrete fracture network (DFN) model (Grechishnikova 2017) from an outcrop study of Niobrara formation.

This study is part of a broader program sponsored by Anadarko and conducted by the Reservoir Characterization Project (RCP) at Colorado School of Mines. The study area is the Wishbone Section (one square mile area), which has eleven horizontal producing wells with initial production dating back to September 2013. The project also includes a nine-component time-lapse seismic. The Wishbone section is a low-permeability faulted reservoir containing liquid-rich light hydrocarbons in the Niobrara chalk and Codell sandstone.

The geologic framework was built by Grechishnikova (2017) using seismic, microseismic, petrophysical suite, core and outcrop. I used Grechishnikova’s geologic framework and available petrophysical and core data to construct a 3D reservoir model. The 3D geologic model was used in the hydraulic fracture modeling software, GOHFER, to create a hydraulic fracture interpretation for the reservoir simulator and compared to the interpretation built by Alfataierge (2017). The reservoir numerical simulator incorporated PVT from a well within the section to create the compositional dual-porosity model in CMG with seven lumped components instead of the thirty-two individual components. History matching was completed for the numerical simulation, and rate transient analysis between field and actual production are compared; the results were similar. The history matching parameters are further compared to the input parameters, and Ning’s (2017) history matching parameters.

The study evaluated how fracture porosity and rock compaction impacts production. The fracture porosity is a major contributor to well production and the gas oil ratio. The fracture porosity is a major sink for gathering the matrix flow contribution. The compaction numerical simulations show oil production increases with compaction because of the increased compaction drive. As rock compaction increases, permeability and porosity decreases. How the numerical model software, CMG, builds the hydraulic fracture, artificially increases the original oil-in-place and decreases the recovery factor. Furthermore, grid structure impacts run-time and accuracy to the model. Finally, outcrop adds value to the subsurface model with careful qualitative sedimentology and structural extrapolations to the subsurface by providing understanding between the wellbore and seismic data scales.

This thesis describes the advantages of investigating gas shales reservoir description on a nanoscale by using petrographic analysis and core plug petrophysics to characterize the Barnett, Marcellus and Mancos shale plays. The results from this analysis now indicate their effects on the reservoir quality. Helium porosity measurements at confining pressure were carried out on core plugs from this shale plays. SEM (Scanning Electron Microscopy) imaging was done on freshly fractured gold-coated surfaces to indicate pore structure and grain sizes. Electron Dispersive X-ray Spectroscopy was done on freshly fractured carbon-coated surfaces to tell the mineralogy. Extra-thin sections were made to view pore spaces, natural fractures and grain distribution.

The results of this study show that confining pressure helium porosity values to be 9.6%, 5.3% and 1.7% in decreasing order for the samples from the Barnett, Mancos and Marcellus shale respectively. EDS X-ray spectroscopy indicates that the Barnett and Mancos have a high concentration of quartz (silica-content); while the Mancos and Marcellus contain calcite. Thin section analysis reveals obvious fractures in the Barnett, while Mancos and Marcellus have micro-fractures.

Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.

The Pine Prairie Field is situated on a salt dome in northern Evangeline Parish, located in south-central Louisiana. Pine Prairie contains the only known Cook Mountain Formation hydrocarbon reservoir in Louisiana. Operators have targeted and produced hydrocarbons from the Cook Mountain reservoir in eight wells at the Pine Prairie Field. The source and origin of the Cook Mountain’s reservoir properties are unknown. The objective of this study is to determine the origin of the Cook Mountain Formation’s reservoir properties by identifying the processes associated with the formation of a Cook Mountain Reservoir. There are two carbonate outcrops at the surface expression of the Pine Prairie Dome. Samples were taken and thin sections made to determine the relationship, if any, to the Cook Mountain Formation. Thin section analysis of the carbonate outcrop was used to gain a better understanding of the depositional setting present at Pine Prairie Field. Well log, seismic, and production data were integrated to determine that, in all instances, commercial Cook Mountain production is associated with fault zones. The passage of acidic, diagenetic fluids through Cook Mountain fault zones generated areas of vuggy porosity proximal to Cook Mountain faulting. Further, fluctuations in short-term pressure gradients associated with salt diapirism resulted in the vertical migration of hydrocarbons via fault zones. In the Pine Prairie Field, fault seal breakdown occurs in Sparta and Wilcox Reservoirs, subsequently charging the Cook Mountain fault zone. Early hydrocarbon charge from the underlying Wilcox and Sparta Reservoirs prevented additional diagenesis, preserving secondary porosity in areas of Cook Mountain faulting.

The Spraberry Formation is a Leonardian age submarine fan deposit restricted to the Midland Basin. The formation consists of very fine-grained sandstone, medium to coarse grain size siltstones, organic shales and carbonate mudstones. These rocks show variability in sedimentary structures and bedding types varied from thinly laminated to convolute laminations. Bioturbations were present in some samples and soft sediment deformation, such as water escape features, sediment loading and flame structures.

The Spraberry Formation is a naturally fractured reservoir with low porosity and low matrix permeability. Porosity measured varied from 2% in rocks with poor reservoir quality such as the argillaceous siltstone and mudstone while good reservoir rocks had an average porosity of 9%. Seven lithofacies were identified based on sedimentary structures, grain size and rock fabrics. Petrographic analysis showed four porosity types: (1) intragraular porosity; (2) dissolution porosity; (3) fracture porosity and (4) intergranular porosity. Fractured porosity was only observed in the argillaceous siltstone lithofacies.

The prominent diagenetic influences on the Spraberry Formation are: quartz cementation, quartz overgrowth, illtization of smectite, feldspar dissolution, clay precipitation, carbonate cementation, formation of framboidal pyrite and fracture formation. These diagenetic features were observed using scanning electron microscope (SEM) and in thin sections. Generally, petrophysical properties, such as porosity and permeability, vary gradually from reservoir rocks to non-reservoir rock. Observed trends where: 1) increasing organic and argillaceous content with decreasing porosity and 2) increasing carbonate sediments and calcite cements with decreasing porosity. Mineralogical analysis from FTIR showed an abundance of quartz and calcite, while illite is the prominent clay mineral observed in all samples.

CO₂ flooding has proven to be an effective technique for enhanced oil recovery. However, the application of CO₂ flooding in the recovery process of asphaltenic crude systems is often avoided, as high asphaltene precipitation rates may occur. While the effects of asphaltene concetration and CO₂ injection pressure on asphaltene precipitation rate have been the focus of many studies, asphaltene precipitation rate is not a reliable factor to predict the magnitude of asphaltene-induced formation damage. Wettability alteration is only caused by the immobile asphaltene deposits on the rock surface. The enternmaint of flocs may occur at high fluid velocity. Morover, the effective permeability reduction is only caused by the flocs, which have become large enough to block the pore throats. The dissociation of the flocs may occur under certain flow conditions. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection practice, which avoids asphaltene-induced formation damage during both immiscible and miscible CO₂ flooding in asphaltenic crude system. Without injection, at pressure above bubble point, slight precipitation occurred in the zone of the lowest pressure near the producing well. As pressure approached the bubble point, precipitation increased due to the change in the hydrocarbon composition, which suggested that the potential of asphaltene-induced formation damage is determined by the overall fluid composition. At very low pressure, precipitation decreased due to the increase in the density.

As CO₂ was injected below the minimum miscibility pressure, a slight precipitation occurred in the transition zone at the gas-oil interface due to the microscopic diffusion of the volatile hydrocarbon components caused by the local concentration gradients. The increase in CO₂ injection rate did not significantly increase the precipitation rate.

As CO₂ was injected at pressure above the minimum miscibility pressure, precipitation occurred throughout the entire reservoir due to the vaporizing drive miscibility process. While precipitation increased with the injection rate, further increase in the injection rate slightly decreased the deposition due to shear. The pressure drop in the water phase caused by the pore throat increased the local water velocity, resulting in a more effective removal of the clogging asphaltene material.

Enhanced Oil Recovery (EOR) is regarded as new and effective technology to produce oil and gas in recent years. EOR technology has been widely used as a method of enhancing remaining oil to several oil fields? production. This experiment provides detailed analysis and approves the effectiveness of algae polymer. It also gives some suggestions, which were based on information obtained from other researches for future test.

Modern hydraulic fracturing designs assume that drilled formations are both isotropic and homogeneous, and fractures are linear and symmetrical. However, unconventional resources are often obtained from formations that are both anisotropic and heterogeneous, resulting in complex fracture behavior. The objective of this study is to evaluate fracture behavior based on the influence of anisotropy and water saturation. Isotropic and homogeneous Austin Chalk, Berea Sister Gray Sandstone, and Silurian Dolomite, laminated anisotropic and heterogeneous Parker Sandstone, Nugget Sandstone, and Winterset Limestone Carbonate, and fully anisotropic and heterogeneous Edwards Brown Carbonate cores were ordered for testing. Brazilian discs were cut according the ISRM and ASTM standards, and prepared as dry, brine saturated, and fresh water saturated samples. All samples were fractured by the Brazilian test, and laminated anisotropic samples were tested at various loading angles (0?, 15?, 30?, 45?, 90?). Tensile strengths were calculated using the peak load of the primary fracture of each sample, and the fractures were observed for geometrical trends. Additionally, the strain development of each fracture was analyzed through the application of Digital Image Correlation (DIC) software. The results determined that anisotropy and saturation can decrease the tensile strength of a formation. The fracture geometries were influenced by planes of anisotropic lamination, and fully anisotropic rocks produced winding, erratic fractures. DIC allowed for closer 101 examination of fracture development, and identified that saturation can cause failure along lamination planes subjected to less than the maximum, load induced stress. This research can be utilized to improve the hydraulic fracturing design models to optimize formation fractures, and increase revenue for the oil and gas industry.

Reactive transport phenomena, such as CO2 sequestration and Microbial EOR, have been of interest in streamline-based simulations. Tracing streamlines launched from a wellbore is important, especially for time-sensitive transport behaviors. However, discretized gridblocks are usually too large as compared to the wellbore radius. Field-scale simulations with local-grid-refinement (LGR) models often consume huge computational time. An embedded grid-free approach to integrate near-wellbore transport behaviors into streamline simulations is developed, which consists of two stages of development: tracing streamlines in a wellblock (a gridblock containing wells) and coupling streamlines with neighboring grids. The velocity field in a wellblock is produced based on a grid-less virtual boundary element method, where streamlines are numerically traced using the fourth-order Runge-Kutta (RK4) method. The local streamline system is then connected with the global streamline system which is produced by Pollock’s algorithm. Finally, the reactive transport equation will be solved along these streamlines.

The presented algorithm for solving near-wellbore streamlines is verified by both a commercial finite element simulator and Pollock-algorithm-based 3D streamline simulator. A series of computational cases of reactive transport simulation are studied to demonstrate the applicability, accuracy, and efficiency of the proposed method. Velocity field, time-of-flight (TOF), streamline pattern, and concentration distribution produced by different approaches are analyzed. Results show that the presented method can accurately perform near-wellbore streamline simulations in a time-efficient manner. The algorithm can be directly applied to one grid containing multiple wells or off-center wells, as well. Furthermore, assuming streamlines are evenly launched from the gridblock boundary or ignoring transport in the wellblock is not always reasonable, and may lead to a significant error.

This study provides a simple and grid-free solution, but is capable of capturing the flow field near the wellbore with significant accuracy and computational efficiency. The method is promising for streamline-based reservoir simulation with time-sensitive transport, and other simulations requiring an accurate assessment of interactions between wells in one particular gridblock.

The vertical and horizontal mechanical properties of a VTI medium can be obtained from five stiffness coefficients (C₃₃, C₄₄, C₆₆, C₁₃, and C₁₂) using velocities at different angles and density measurements. However, when using well log data for vertical wells, only three out of the five elastic constants can be calculated. The sonic tool cannot measure C₁₃ and C₁₂; thus, different empirical models have been proposed to determine them, making assumptions that do not provide completely accurate results. In this paper, a new empirical model is introduced to obtain the stiffness coefficients. Datasets of dynamic core measurements of shales from different parts of the world are compiled and later, analyzed. The method was based on establishing correlations for the stiffness coefficients, both for each formation and for all formations put together. There were two sets of correlations—those with C ₃₃ as the dependent variable, and those with C₄₄ as the dependent variable. M-ANNIE assumptions were also obtained. Because Stoneley slowness is difficult to measure and can cause errors in the calculations, it was not used.

Finally, isotropic and VTI minimum horizontal stresses are calculated and compared using well log data from the Bakken formation. VTI minimum horizontal stress calculations used the M-ANNIE model and the correlations determined for the Bakken formation core data. Generally, the new model provides results similar to M-ANNIE predictions, and better results than the isotropic and ANNIE models. Although the proposed method produces results similar to those of the M-ANNIE model, which is widely used as a reference model throughout the industry, the proposed method is different in that it can be used under a different set of circumstances when some inputs are available, and others are not. This method reduces the underestimation of minimum horizontal stress made by the isotropic and ANNIE models as well.

This study was motivated by how to use statistical tool to identify the candidacy wells for CO2 Capture and Sequestration based on the idea of using Artificial Neural Networks to predict the leakage index of a well. A Combined Neural-Genetic Algorithm was introduced to avoid BP neural network getting a local minimum because Genetic Algorithm simulates the survival of the fittest among individuals over consecutive generation. Based on the algorithm, 1356 lines of C code were composed using Microsoft Visual Studio 2010. The Combined Neural-Genetic Algorithm developed in this thesis is able to handle large size of data sample with at least 10 factors. Several parameters were considered as factors that may have an effect on the performance of Combined Neural-Genetic Algorithm, including the population size, max epoch, error goal, probability of crossover, probability of mutation, number of neurons in hidden layer, number of factors and size of data sample. The accuracy of the BP neural network and the CPU time are the two major parameters to evaluate the performance of the Combined Neural-Genetic Algorithm. A sensitivity analysis was performed to identify the effect these factor have on the performance. Based on the result of the sensitivity analysis, some recommendations are provided about initializing these factors.

It has been reported that the Macondo tragedy was caused by a faulty cementing operation. This, in turn, has forced operators to pay special attention to this aspect of well completion. One of the contributing factors to the faulty cementing operation of Macondo is said to be an insufficient number of casing centralizers. This is important because the success of any casing cementing operation is largely dependent on the centralization of the casing in the wellbore.

Centralizers are placed on the casing strings at predetermined distances in an effort to retain the casing in the center of the wellbore, thereby maximizing the coverage of cement around the casing. Placement, as well as the number, of centralizers is dependent on the standoff of the casing in the wellbore. Standoff is defined as the minimum distance between the outer diameter of the casing and the wellbore.

For casings under tension, API has recommended formulas to calculate casing standoff in 3D wellbores, which takes into account the inclination and azimuth angles. In addition, literature is available that considers casing under compression due to the fluid forces acting on the casing string and shows a considerable difference in standoff when considering compression as compared to tension alone. Currently all available literature considers the wellbore as rigid only. This paper considers the formation type, ranging from unconsolidated sand to shale, and calculates its effect on standoff. The results show that the formation type may significantly affect the outcome of standoff, and therefore should be considered when calculating standoff.

The essence of many issues in different fields is the transport and piling of particles in fluid within a limited space. A semi-analytical model is developed in this study to describe the motions of a particle in fluid and simulate the piling process of particles in a fracture. As a result, the configuration of a particle pile and the time at which the pile totally seal the fracture face are predicted. This model possesses a wide range of applications. Two types of applications of this model are introduced, including the prediction of proppant screen-out in hydraulic fracturing vertical and horizontal wells and the simulation of curing the lost circulation. Results of case studies are consistent with the field data with minor errors. Sensitivity analyses with the proposed model were conducted for each type of application. Major factors affecting the model calculation results are identified for the purpose of optimizing the performance of hydraulic fracturing and curing the lost circulation. Sensitivity analyses conducted for the proppant screen-out prediction during fracturing vertical and horizontal wells indicate following conclusions: 1) The use of high fluid viscosity can avoid the premature settlement of proppant and significantly delay the screen-out time. 2) The sse of proppant with low density in the practical range could delay the screen-out time, but the effect is not as significant as other factors analyzed in this study. 3) A high injection rate allows the proppant pile to build farther from the wellbore, while it will lead to a quick screen-out. 4) Larger proppant size can easily cause screen-out sooner. 5) Wide distributionof proppant size can delay screen-out. 6) The use of low ratio of proppant volume to fluid volume can minimize the probability of the occurrence of screen-out. Sensitivity analyses for the cure of lost circulation demonstrate following conclusions: 1) Lost circulation can be cured faster when low fluid viscosity is used. 2) High density LCM can facilitate the cure of lost circulation. 3) Low mud density can mitigate lost circulation, but its effect is not as significant as other factors. 4) The concentration of LCM should be determined based on the severity of lost circulation. This semi-analytical model provides engineers a general tool to solve different issues involved in different fields. It can also be utilized to identify main factors responsible for different issues to minimize their detrimental effects.

Ceramic proppants are commonly used in hydraulic fractures. However, people typically focus on controlling properties of proppants such as the material, specific gravity, and particle size, and less attention is paid to the effect of proppant wettability. The purpose of this study is to investigate the effect of proppant wettability on two-phase flow efficiency in fractured water-wet sandstones. The results show that oil-wet proppants are more effective in improving oil flow efficiency than water-wet proppants in both low-water saturation cores and high-water saturation cores. Therefore, small sized oil-wet proppants have better performance than large sized oil-wet proppants.

Hydraulic Fracturing is a cost-effective technique that has been widely integrated and applied to commercial production of oil and gas from unconventional reservoirs. Advancement of this technique brings more complexity into it, making optimization process more complicated in terms of economic analysis and decision making. Selection of proppant for treatment is a crucial and essential decision that has a significant impact on fracturing stimulation and well economics. This analysis indicates advantages and disadvantages of different types of proppant and provides a comparison of proppant performances considering proppant type, mesh size and concentration in order to identify the best scenario of proppant application in terms of economical profitability.

Abstract In this work, we studied the Eagle Ford Shale and experimented in detail to create a baseline to address the relative permeability of specific ions in shale. The study identifies that: (1) Ions are dispersed in a specific sequence (Na⁺, Ca²⁺, Mg²⁺). (2) As ions are dispersed, this allows the gas bubbles out of the shale/soil and forces the flakes and fragments to float to the top of the water on the vessel. The floating particles, depending on the type of cations released from the shale mass move towards a specific ion electrode. (3) Detachment or bursting of gas bubbles may initiate a shift or break in the shale/soil formation. (4) Calcium electrical potential, Eh, goes from negative to positive. This indicates an unstable potential with respect to time around the length of the well bore. (5) The release of ions depends on the diffusion properties of water penetrating the shale/soil mass. The motion of the shale/soil floating material is a vortex-like motion.

We conclude that by using SAR, it will help predict where the wellbore is stable or unstable based on the curve where certain drops or peaks or located. By creating a baseline measure using deionized water it is possible to predict the relative permeability of wellbore drilling of the Eagle Ford Shale using SAR.

Taking note of the ionic relative permeability as observed in our experiments, we decided to use the SAR method for estimating the relative permeability of shale/soil to various ions. All of this is based on where the most ionic flow occurs under given wellbore conditions. This understanding is further applicable to the design of certain type of frac fluids or design of a compatible drilling fluid for drilling a specific shale/soil.

The lack of cutting transportation during drilling operations can lead to large amounts of non productive time and costly solutions to address the issue. The objective of this study was to investigate the cutting velocity through an experimental approach. Dimensionless groups were formed based on the independent variables that affected cutting velocity. The experimental approach was analyzed through film software, which allowed for the cutting velocities to be calculated. Regression models of cutting velocity with respect to each dimensionless group were formed and validated through a statistical analysis. Only the second dimensionless group (?2) representing the volume of cuttings injected into the drillpipe with respect to the cubed value of the outer diameter of the drillpipe was proven to be insignificant.

Once the remaining regression models were validated, multiple linear regression analyses were conducted to relate each dimensionless parameter to the cutting velocity. This introduced a new empirical model to represent the cutting velocity based on the five significant dimensionless groups outlined in this study. The multiple linear regression model yielded an R-squared value of .81, which suggests a strong correlation for the data. This model was also validated through statistics. Each parameter except for the intercept of the model was confirmed to be significant. Other parameters that were excluded from the model due to the lack of equipment precision could be examined. A sensitivity analysis was conducted to highlight how each dimensionless group directly affected the cutting velocity. New correlations and trends may be estimated with more data from additional experiments outside the range of this study. Overall, this will allow the foundation of the model to be further improved.

Superhydrophobic coating reduces the fluid/solid interaction leading to ultra-hydrophobicity or the Lotus effect. The objective of this study is to determine how this phenomenon can be applied in petroleum production systems to enhance fluid flow in propped fractures using superhydrophobic coating on the surface of proppants. Permeability and wettability of coated sandstone samples are compared with the non-coated ones to create a base case for the study. Later sand packs are tested to determine the magnitude of enhancement in fracture conductivity after the modification is applied on sand proppants. The samples are measured for their absolute permeability and relative permeabilities to test the changes in flow for both the single-phase and two-phase fluid flow. The test results show a considerable increase of up to 98% for the single-phase flow and a 23% for the two-phase flow for the sand pack samples. The wettability test confirms that the coating modifies the samples from its initial water-wet state to a partial-wet state. Since the production rate of tight and shale reservoirs is low especially in liquid-rich reservoirs, a significant amount of water is injected for reservoir stimulation; enhancement in fracture conductivity as a result of proppant surface modification can have a meaningful impact on the recovery of these reservoirs. This study uses experimental techniques to show the effectiveness of superhydrophobic coating on the reduction of friction which can lead to enhancement in fracture conductivity.

Steam stimulation is by far the most widely used tertiary oil recovery method. Heavy oil finds its most effective way of production in thermal recovery method. Also with technical effectiveness, steam stimulation brings in cost effectiveness. In-situ steam generation and injection is the most important enhancement to the conventional thermal steam injection technique. Blackbird™ Energy LLC, has developed and a new generation in-situ steam generator with a view to make an almost unproductive heavy oil reservoir in North East Texas to start producing.

In this research, a reservoir simulation study has been performed to history match of pure depletion as well as three months of thermal stimulation done on the reservoir. To mimic the reservoir conditions, Schlumberger Eclipse 300 compositional Simulator has been used. Overall this research performs an evaluation of the newly developed in-situ steam generator capabilities.

The various predictive runs have been made with changing key performance parameters such as location of steam generator and time of application of thermal energy. There has been reported a considerable increase in production of the heavy oil. As a result, in-situ steam injection has been proved to be an effective and environment friendly recovery technique and should be widely considered for replacing conventional steam generators.

This experiment was designed to study iron control systems in fracking and well stimulation jobs at higher pH. Experimental study of iron control at high pH of this kind has not previously been reported in the literature. In addition, almost all of the widely used iron control chemicals today work at lower pH (≤4).

In this experiment, newly enhanced chemicals, such as EnerFlow 780, SC803, EDTA, Poly Itaconic acid, and TN801 were used and the following new result were found. In the absence of iron control chemicals, iron precipitation occurred at pH of 1.85 and completely precipitated at 3.5. SC803 has shown a very unique characteristic. The chelating characteristic of this product increases with pH. At lower pH (≤4), this product has shown weaker performance in curbing iron precipitation. Only 37% (average) initial iron was prevented from precipitating at this pH. However, when the pH was increased to above 4, its sequestering characteristic became more and more until it reached pH 13. Minimum precipitation was observed at pH of 11 & 12, which are 4.3% and 4.7%, respectively. Furthermore, SC803 was observed to cause unforeseen yellowish iron precipitation at lower pH.

TN801, a blend of SC803, EDTA and Poly Itaconic acid, showed the best result of the all the individual chemicals tested. It effectively curbed an average of 96% iron precipitation in all pH less than 13. EDTA and Poly Itaconic acid were added to enhance the performance of SC803 at lower pH. The result showed 86.8% maximum enhancement at lower pH and 0.3% at higher pH. TN801 was also able to dissolve 50% of crystalline iron sulfide, despite the fact that it is insoluble in nature. Furthermore, TN801 was tested on field and the anticipated result was achieved.

Nuclear magnetic resonance (NMR) has become an increasingly important tool for estimating porosity, permeability, and fluid characteristics in oil and gas reservoirs since its introduction in the 1950s. While NMR has become common practice in conventional reservoirs, its application is relatively new to unconventional reservoirs such as the Eagle Ford Shale. Porosity and permeability estimates prove difficult in these exceptionally tight rocks and are routinely below the detection limit and/or resolution of low frequency (2 MHz or less) NMR. High frequency (400 MHz) NMR has been applied to address these issues; however, previous studies have been limited to crushed rock samples or millimeter-sized core plugs.

In response, a custom-built NMR probe has been constructed, capable of measuring 0.75-inch diameter, 0.45-inch length core plugs at 400 MHz, to determine if larger core plug sizes yield higher resolution T ₂ distributions in the Eagle Ford Shale. The tool is composed of two primary elements, the structural framework and the radio frequency circuit. Each element was designed and constructed iteratively to test various layouts while maintaining functionality. The probe's structural design was initially based on retired, commercial probes then modified to operate within a Bruker Ascend™ 400WB NMR spectrometer. Designs were drafted and 3D-printed multiple times to determine proper physical dimensions and clearances. Once designs were deemed satisfactory, structural components were manufactured and assembled to create the structural framework. A radio frequency circuit was then built to measure T₂ distributions at the desired frequency and sample size. Multiple inductor designs and capacitor combinations were tested until a stable circuit, capable of matching impedance and tuning to the proper frequency, was achieved. The probe's stability and data quality were then confirmed by measuring the NMR spectra of deuterated water in a Teflon container.

The NMR probe was validated by comparing high frequency (400 MHz) data acquired in-house to low frequency (2 MHz) data measured at a commercial laboratory. Twelve core plugs (0.75-inch diameter, 1-inch length) were cut from two Eagle Ford Shale subsurface cores located in Gonzales and La Salle counties, Texas. Low frequency T₂ distributions were measured twice: first after drying core plug samples in a vacuum oven and again after spontaneous imbibition with various brine solutions (deionized water, 8 wt.% KCl, or 17.9 wt.% KCl) for one week. These contrasting saturation states were applied to highlight immovable water in the core plugs. For high frequency data measurements, samples were trimmed to 0.45-inch lengths to fit inside the newly-built NMR probe, leaving two sub-samples for each of the original core plugs. T₂ distributions were first acquired "as-is" (e.g., without drying or imbibition). After as-is data acquisition, samples were dried in a vacuum oven then allowed to spontaneously imbibe the same brine solutions used in the low frequency study. T₂ distributions were measured again after imbibition and compared to the low frequency data acquired by the commercial laboratory.

Qualitatively, high frequency T₂ distributions resemble low frequency data; however, the absolute T ₂ values are routinely higher by one order of magnitude. The difference may be caused by data acquisition, data processing, fluid-rock interactions, magnetic field inhomogeneities, or some combination thereof. In spite of not attaining the higher-resolution T₂ distributions desired, the project still provides a proof-of-concept that T ₂ relaxation times can be measured in conventional-sized core plugs using 400 MHz NMR. Although limited in its outcomes, the study delivers promising results and elicits future research into utilizing high frequency NMR spectroscopy as a petrophysical tool for unconventional reservoirs.

The shale boom has introduced new technology into the oil and gas industry. It has created a new source of energy and has helped create a surplus in volume. With the recent decrease in oil prices, engineers must be creative and again use technology to make wells more productive. This study is done to observe the role of fracture conductivity in a hydraulically fractured well using a commercially available software. This will allow for engineers to improve fracking techniques. From this, it helps to consider the reliability of simulation software.

A typical well in the Eagle Ford Shale formation was selected to model. Completion data was gathered for a horizontal well that had seventeen fracture stages. In the simulation models, the fracture fluid volume was held constant to honor the original well production data. The fracture conductivity was studied using two different methods. The first involved observing one single fracture using different combinations of fracture conductivity throughout the fracture length. The second method incorporated the entire well and observed interactions between fractures with different altered fracture conductivities. Only one fracture was used per stage based off an existing fracture model. Production data with respect to time was analyzed and compared to real time field data.

After production results were analyzed, it can be seen that the models give a reliable representation of a horizontal well in the Eagle Ford Shale. When viewing the results of the single fracture stage, the cumulative productions are very similar, and when comparing the entire well with seventeen stages, the cumulative production begins to change slightly from model to model. Still, the difference in models does not merit an endorsement of a new completion technique for fracture conductivity. The results indicate that infinite acting flow takes over because of the low permeability reservoir.

A bull heading operation is a static non-circulating well control method used to regain integrity of the wellbore. This method is used when there is no drill/tubing string in the wellbore to circulate the kick out of the wellbore. A bull-heading operation requires the use of hydraulic force to overcome the static shut-in pressures of the reservoirs and provide a differential pressure. This differential pressure is required to overcome wellbore and formation friction forces and drive the kill fluid, at a desired flow rate, down the wellbore.

In tight conventional reservoirs it is very difficult to accurately simulate the requirements needed to conduct a Bullhead operation. Is it critical to properly estimate the maximum anticipated surface pressure expected during any well control operation. If not done accurately, the equipment used during this operation can surpass its limitations, leading to compromising the integrity of the equipment. The key component to estimate is the differential pressure required to force the oil back into the reservoir at a required kill fluid velocity. A specific kill fluid velocity is required to hydraulically kill the well by preventing the reservoir fluids from u tubing with the heavier kill fluid. Bullhead simulations don’t focus on injection pressure modeling, which is believed the reason why the required differential pressure is being underestimated in deep-water applications. The goals of this project is to create a reservoir model, analyze the three-dimensional fluid flow that will occur during a bull heading operation, and conduct a sensitivity analysis on the parameters that affect the injection pressure. This will allow us to accurately estimate the injection pressure required to force the oil back into the reservoir and also determine what impact certain reservoir properties have on injection pressure.

Rock fracture mechanics theories have been used for more than 50 years in the oil and gas industry. Fracture mechanics is about understanding what will happen to the rocks in the subsurface when subjected to fracture stress. Much of what is used in hydraulic fracturing theory and design was developed by other engineering disciplines many years ago. However, rock formations often cannot be treated as isotropic and homogeneous. These assumptions affect the calculation of in-situ stresses which are important for designing hydraulic fracture and knowing the stability of wellbore. A Geomechanical model is built to investigate these problems and to predict the alterations and changes of the Geomechanical properties of the reservoir.

After the reservoir characterization and determination of the magnitude and direction of in–situ stresses, our next step is to prepare a 3-D Geomechanical model in ANSYS Workbench. Elastic anisotropy of the formation is included in the 3-D numerical models. The model will represent the Bakken Formation, having all its properties. After preparing a mesh for this model to carry out further studies, we apply stresses to the model so that it represents the depth at which the Bakken Formation is encountered while keeping the drilling conditions in mind. We analyze wellbore stability and predict wellbore behavior under stress alteration caused by drilling.

The average pore size in producing unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary and surface disjoining force interactions, such as van der Waals, structural, and adsorption, affect the phase behavior that is not considered to be significantly, different than in conventional reservoirs. In this dissertation, a comprehensive discussion of the thermodynamics required to model phase behavior of unconventional, liquids-rich reservoirs is presented. Three oil compositions from different unconventional reservoirs are used to generate results.

The impact of confinement manifests itself in the form of reduction of the liquid pressure at which the first gas bubble forms when compared to the bulk fluid measurements in PVT cells. It is shown that the suppression of the bubble-point pressure impacts the saturated portion of the liquid formation volume factor and extends the undersaturated portion of the curve. The equilibrium gas composition is different for each supersaturation level and the gas is composed of lighter components as the supersaturation, i.e., the bubble-point suppression, increases. The minimum radius of the pore that is required to form a specified size bubble is also investigated and the range of pore sizes required under different assumptions is reported.

The impact of this phase behavior deviation on the flow of confined fluids is investigated using a black-oil simulator, COZSim, which evaluates gas and oil fluid properties at corresponding phase pressures. The simulator was independently developed in a DOE project with the capability to incorporate the findings of this research. The results of the analysis show that there is a difference in gas production and gas saturation distribution in the reservoir with and without the confinement impact on the PVT properties. The produced GOR is lower when the confinement is considered due to the bubble-point suppression. These results indicate that the use of bulk fluid measurements in modeling and predicting the performances of nano-porous unconventional reservoirs may result in significant underestimation of the reservoir potential.

The limit of drilling ERD comes from the excessive friction between the drill string and borehole. This study investigates the potential of increasing the limit of horizontal displacement through optimization of drilling fluid and bottom hole assemblies. We conclude that lubricating bottom hole with water can significantly increase the maximum permissible WOB. This effect is more pronounced in drilling tight sands than shales with gas. Cooling the bottom hole with gas expansion after bit nozzles can greatly increase the maximum permissible WOB in drilling formations with geothermal temperatures above 200 °C. Three mathematical methods have been developed for calculating the limit of horizontal displacement in extended drilling with gas. The Rigorous Method is recommended because it gives conservative result. Among several factors affecting the ERD with gas, friction coefficient and the weight of pipe in the horizontal section are the two controlling factors. Adequate weight of BHA in the curve section should be used to overcome the friction.

Scale control in oilfield operations is the intervention technique deployed to remove the assemblage of solid deposits from the surface of oil and gas well tubular and associated equipment. Common mineral scales that plague production operations are Barium Sulfate, Strontium Sulfate, Calcium Carbonate, and Iron Sulfide. Some of these scales can be dissolved with acid while others cannot. Barium Sulfate which is common at perforations and downstream of chokes is notorious for its resistance to chemical treatment because of its low acid solubility.

This study investigates the effect of different chemical inhibitors on Barium Sulfate scale. The tube blocking test is widely used to evaluate the efficiency of these chemical inhibitors. Although the principal method of investigation was the tube blocking apparatus, preliminary analysis and optimization were done using the static bottle test and a scale inhibitor performance prediction software called French Creek. The static bottle test was used as a screening method whereby ionic interaction between anionic, cationic and inhibitor solutions gave a clear difference in turbidity or otherwise. The French Creek interface allowed multiple iterations over a range of operating conditions and treatment options. A tube blocking apparatus was constructed to simulate the buildup of scale deposits in an oil pipeline. The set up was operated at pressure and temperature of 100psi and 90°C respectively. Of all the additives tested, phosphonate based chemical had the lowest minimum inhibitor concentration.

U.S. domestic shale-gas production is economic owing to the new completion practice of horizontal wells and multiple hydraulic fractures. The performance of these fractures is improved through the placement of proppant. The change in the stress can affect fracture conductivity considerably. The objective of this study is to experimentally determine the impact of rock stress and time on aperture and permeability of hydraulic fractures in shale gas reservoirs.

Seven experiments were conducted to measure pressure and time dependent closure and permeability of hydraulic fractures created in Barnett shale under different confining pressure. Result shows that pressure dependence of permeability of these fractures obeys Walsh’s permeability models. Time dependence of permeability at high stresses reveals that proppant embedment occurred to the Barnett shale cores.

Analytical models were derived in this work to predict the Maximum Permissible Pressure (MaxPP) and Minimum Permissible Pressure (MinPP) in CO₂ sequestration and other fluid injection wells. The outer radius of the cement sheath should be estimated on the basis of cement placement efficiency measured by the CBL.

The West Hastings Oil Field and Oyster Bayou Oil Field in Gulf of Mexico region were analyzed to identify the potential leakage of the current CO ₂ injection wells using the analytical models. Potential problems for the current wells were identified. There are potential risks for the CO ₂ injection wells with relatively smaller wellbore diameter and casing diameter.

36 CO₂ injection wells of the West Hastings and Oyster Bayou fields were taken as learning wells to train the neural network model, which was tested by 21 wells in the fields. The results show that the neural network model could be used for predicting the potential likelihood of leakage for CO₂ injection wells, which could be an alternative and convenient way to assess the risk of leakage CO₂ .

Sensitivity analysis was also performed considering cement mechanical properties, well structure and reservoir pressure. Results show that improving cement sheath mechanical properties (cement tensile strength, cement cohesive strength, internal friction angle) is not a very effective means of decreasing potential leakage of CO₂ during CO₂ EOR and carbon sequestration processes. The potential risk of leakage for CO₂ injection wells should be decreased by maximizing the outer radius of the cement sheath and improving the cement placement efficiency. For the current CO₂ EOR activities and carbon sequestration processes, the well head maximum water injection pressure could be increased as the reservoir pressure increases.

Natural gas and oil exploration and production from shale formations have gained a great momentum in many regions in the past five years. Producing hydrocarbons from shale is challenging because of low productivity of wells. Optimal design of transverse fractures is a key to achieving successful well completion and field economics. The minimum fracture spacing and the fracture propagation trajectory are the determinant for the successful transverse fracture optimization. Various states of anisotropic stress have been applied to the simulated models with assigning criteria for fracture initiation and propagation. One of the factors that need to be addressed is the trajectory of a fracture in the presence of varying stress fields. The injection of treatment fluid in the initial crack exerts pressure from inside and the stress field around the fracture tip controls fracture extension direction. The new analytical model presented in this paper is used to quickly predict hydraulic fracture propagation trajectory based on completion situation. The fracture geometry obtained by this model is a reliable resource for designing the multi-stage hydraulic fracture spacing in shale gas formation and evaluating hydraulic fracturing horizontal well completion. Result of the analytical method has been verified by a Finite Element Method for a typical fracturing condition in a shale gas formation.

The importance of cement integrity in the downhole well cannot be over looked. Cement designed for a particular well may not work for another well. As a result, there is a need to design well cement based on appropriate well conditions in order to achieve good integrity during the life time of the well. This research focused on micro-annulus and crack problems associated with downhole well cements. Waste tires have contributed to environmental problems.

Waste tires can be crushed into small particles and used for construction purposes. This is seen as a promising avenue to get rid of the waste tires. This research focused on the possibility of adding tire rubber particles to well cement to reduce the effect of micro-annuli and cracks in well cement. Tire rubber particles of 4 different sizes were used in this research, which was then divided into two parts. The first part dealt with rheology and compressive strength of concretes. These parameters were used to select cement designs with optimum value for subsequent tests. The other part included permeability and creep tests. Permeability measured the amount of water the concrete materials could yield while the creep test measured strain developed when concrete specimen was subjected to a constant stress for 30 minutes and the amount of strain recovered when the concrete specimen was unloaded for another 30 minutes. Creep compliance was done to measure the rate at which strain was developing, which is a function of time under constant stress.

Concrete containing the largest rubber particle size had good amount of strain recovery after unloading while concrete samples containing the smallest rubber particle size had the lowest amount of strain recovery.

Rock geo-mechanical properties are important in petroleum engineering. The determination of reservoir’s mechanical properties is critical to reduce drilling risk and maximizing well and reservoir productivity. Rock geo-mechanical properties vary not only with rock types, but also with measurement method, samples geometry (sample size and length to diameter ratio), and other factors. Because rocks are heterogeneous media, sample geometry can significantly affect measured rock mechanical properties, including unconfined and confined compressive strength, Young’s Modulus, and Poisson’s ratio. In this study, uniaxial compressive tests were conducted on 31 different dimensions of Berea sandstone samples to study the geometry effects on rock geo-mechanical properties. The objective of this research is to provide a fundamental understanding of the geometry effects. Correlations equations were established and standardizing factors were generated to minimize the geometry effects and get more reliable rock mechanical properties. Failure mode of the tested samples was also studied in this work.

Production of natural gas from unconventional gas-hydrate reservoirs faces kinds of challenges and uncertainties. One of the main and most common problems in gas-hydrates drilling is the dissociated gas from gas hydrates with decrease of pressure, increase of temperature, or combination of them. A reliable method that can be applied to predict the temperature profile of fluid during circulating in the drilling pipe and the annulus is needed. An analytical model was developed in this study for predicting temperature profiles in drilling gas-hydrate deposits. A case study is provided and indicates a good consistency between model-implications and field observations. According to the sensitivity analyses, the temperature profile of fluid in the drill pipe can be affected by the thickness of drill pipe, density and heat capacity of drill mud, pumping rate of drill mud, geo-thermal gradient, and the surface geo-temperature. The bottom hole temperature is dominated by the temperature and flow rate of the injected drilling fluid, thermal conductivity of cement, heat capacity and density of drill mud, geo-thermal gradient and geothermal temperature at surface, thickness of drill pipe, and cement sheath. Higher geothermal gradient and surface geothermal temperature can lead to a higher temperature profile of fluid in the annulus. The Joule-Thomason cooling effect below the drill bit nozzles will rapidly diminish in a short interval above the bottom hole by the heating effect of geo-thermal gradient. The rate of penetration of drill bit has negligible effect on the fluid temperature profile due to the low percentage of heat flow contributed by the drill cuttings.

After primary and secondary recovery there is still oil remaining in the reservoir, so tertiary recovery is introduced. This is also known as EOR. Enhanced oil recovery has been widely used with different types of polymers. Algae polymer is a new development with its own advantages and limitations. In order to discover the economic potential of algae polymer, this paper focuses on the recovery factor of algae polymer and compares it with other published results.