In the Middle East, extended reach horizontal wells (on the order of 25,000 feet of horizontal displacement) are commonly acid stimulated by jetting acid out of drill pipe. The acid is jetted onto the face of the openhole wellbore as the drill pipe is withdrawn from the well. The jetting action helps to remove the drilling fluid filter cake and promote the acid to penetrate into the formation and form wormholes to stimulate the well. However, with very long sections of wellbore open to flow, the acid placement and subsequent wormhole distribution and penetration depths are uncertain. This study has modeled the acid jetting process using a comprehensive model of acid placement and wormhole propagation in a horizontal well. It is presumed that the acid jetting tool removes the drilling mud filter cake, so that no filter cake exists between the end of the drill pipe and the toe of the well. Correspondingly, the model also assumes that there is an intact, low-permeability filter cake on the borehole wall between the end of the drill pipe and the heel of the well. The drill pipe is modeled as being withdrawn from the well during the acid jetting treatment, as is done in practice. The acidizing simulator predicts the distribution of acid and the depths of wormholes formed as functions of time and position during the acid jetting treatment. The model shows that the acid jetting process as typically applied in these wells preferentially stimulates the toe region of the horizontal well. Comparisons of the simulation predictions with published data for acid jetting treatments in such wells showed good general agreement. Based on the simulation study, this study presents recommendations for improved acid jetting treatment procedures to improve the distribution of acid injected into the formation.

Fractured reservoirs have been traditionally idealized using dual-porosity models. In these models, all matrix and fractures systems have identical properties. However, it is not uncommon for naturally fractured reservoirs to have orthogonal fractures with different properties. In addition, for hydraulically fractured reservoirs that have preexisting natural fractures such as shale gas reservoirs, it is almost certain that these types of fractures are present. Therefore, a triple-porosity (dual-fracture) model is developed in this work for characterizing fractured reservoirs with different fractures properties. The model consists of three contiguous porous media: the matrix, less permeable micro-fractures and more permeable macro-fractures. Only the macro-fractures produce to the well while they are fed by the micro-fractures only. Consequently, the matrix feeds the micro-fractures only. Therefore, the flow is sequential from one medium to the other. Four sub-models are derived based on the interporosity flow assumption between adjacent media, i.e., pseudosteady state or transient flow assumption. These are fully transient flow model (Model 1), fully pseudosteady state flow model (Model 4) and two mixed flow models (Model 2 and 3). The solutions were mainly derived for linear flow which makes this model the first triple-porosity model for linear reservoirs. In addition, the Laplace domain solutions are also new and have not been presented in the literature before in this form. Model 1 is used to analyze fractured shale gas horizontal wells. Non-linear regression using least absolute value method is used to match field data, mainly gas rate. Once a match is achieved, the well model is completely described. Consequently, original gas in place (OGIP) can be estimated and well future performance can be forecasted.

Combustion assisted gravity drainage (CAGD) is an integrated horizontal well air injection process for recovery and upgrading of heavy oil and bitumen from tar sands. Short-distance air injection and direct mobilized oil production are the main features of this process that lead to stable sweep and high oil recovery. These characteristics identify the CAGD process as a high-potential oil recovery method either in primary production or as a follow-up process in reservoirs that have been partially depleted. The CAGD process combines the advantages of both gravity drainage and conventional in-situ combustion (ISC). A combustion chamber develops in a wide area in the reservoir around the horizontal injector and consists of flue gases, injected air, and mobilized oil. Gravity drainage is the main mechanism for mobilized oil production and extraction of flue gases from the reservoir. A 3D laboratory cell with dimensions of 0.62 m, 0.41 m, and 0.15 m was designed and constructed to study the CAGD process. The combustion cell was fitted with 48 thermocouples. A horizontal producer was placed near the base of the model and a parallel horizontal injector in the upper part at a distance of 0.13 m. Peace River heavy oil and Athabasca bitumen were used in these experiments. Experimental results showed that oil displacement occurs mainly by gravity drainage. Vigorous oxidation reactions were observed at the early stages near the heel of the injection well, where peak temperatures of about 550ºC to 690ºC were recorded. Produced oil from CAGD was upgraded by 6 and 2ºAPI for Peace River heavy oil and Athabasca bitumen respectively. Steady O2 consumption for both oil samples confirmed the stability of the process. Experimental data showed that the distance between horizontal injection and production wells is very critical. Close vertical spacing has negative effect on the process as coke deposits plug the production well and stop the process prematurely. CAGD was also laboratory tested as a follow-up process. For this reason, air was injected through dual parallel wells in a mature steam chamber. Laboratory results showed that the process can effectively create self-sustained combustion front in the previously steam-operated porous media. A maximum temperature of 617ºC was recorded, with cumulative oil recovery of 12% of original oil in place (OOIP). Post-experiment sand pack analysis indicated that in addition to sweeping the residual oil in the steam chamber, the combustion process created a hard coke shell around the boundaries. This hard shell isolated the steam chamber from the surrounding porous media and reduced the steam leakage. A thermal simulator was used for history matching the laboratory data while capturing the main production mechanisms. Numerical analysis showed very good agreement between predicted and experimental results in terms of fluid production rate, combustion temperature and produced gas composition. The validated simulation model was used to compare the performance of the CAGD process to other practiced thermal recovery methods like steam assistance gravity drainage (SAGD) and toe to heel air injection (THAI). Laboratory results showed that CAGD has the lowest cumulative energy-to-oil ratio while its oil production rate is comparable to SAGD.

Many hydraulically fractured shale gas horizontal wells in the Barnett shale have been observed to exhibit transient linear behavior. This transient linear behavior is characterized by a one-half slope on a log-log plot of rate against time. This transient linear flow regime is believed to be caused by transient drainage of low permeability matrix blocks into adjoining fractures. This transient flow regime is the only flow regime available for analysis in many wells. The hydraulically fractured shale gas reservoir system was described in this work by a linear dual porosity model. This consisted of a bounded rectangular reservoir with slab matrix blocks draining into adjoining fractures and subsequently to a horizontal well in the centre. The horizontal well fully penetrates the rectangular reservoir. Convergence skin is incorporated into the linear model to account for the presence of the horizontal wellbore. Five flow regions were identified with this model. Region 1 is due to transient flow only in the fractures. Region 2 is bilinear flow and occurs when the matrix drainage begins simultaneously with the transient flow in the fractures. Region 3 is the response for a homogeneous reservoir. Region 4 is dominated by transient matrix drainage and is the transient flow regime of interest. Region 5 is the boundary dominated transient response. New working equations were developed and presented for analysis of Regions 1 to 4. No equation was presented for Region 5 as it requires a combination of material balance and productivity index equations beyond the scope of this work. It is concluded that the transient linear region observed in field data occurs in Region 4 – drainage of the matrix. A procedure is presented for analysis. The only parameter that can be determined with available data is the matrix drainage area, Acm. It was also demonstrated in this work that the effect of skin under constant rate and constant bottomhole pressure conditions is not similar for a linear reservoir. The constant rate case is the usual parallel lines with an offset but the constant bottomhole pressure shows a gradual diminishing effect of skin. A new analytical equation was presented to describe the constant bottomhole pressure effect of skin in a linear reservoir. It was also demonstrated that different shape factor formulations (Warren and Root, Zimmerman and Kazemi) result in similar Region 4 transient linear response provided that the appropriate f(s) modifications consistent with lAc calculations are conducted. It was also demonstrated that different matrix geometry exhibit the same Region 4 transient linear response when the area-volume ratios are similar.

In gas-condensate reservoirs, gas productivity declines due to the increasing accumulation of liquids in the near wellbore region as the bottom-hole pressure declines below the dew point pressure. This phenomenon occurs even in reservoirs containing lean gas-condensate fluid. Various methods were addressed to remediate the productivity decline, for example, fracturing, gas injection, solvent injection and chemical treatment. Among them, gas injection techniques have been used as options to prevent retrograde condensation by vaporizing condensate and/or by enhancing condensate recovery in gas-condensate reservoirs. It is of utmost importance that the behavior of liquid accumulation near the wellbore should be described properly as that provides a better understanding of the productivity decline due to the originated from impaired relative mobility of gas. In this research, several gas injection techniques were assessed by using compositional simulators. The feasibility of different methods such as periodic hot gas injection and gas reinjection using horizontal wells were assessed using different reservoir fluid and injection conditions. It is shown that both the temperature and composition of the injection fluids play a key role in the remediation of productivity and condensate recovery. The combined effect of these parameters were investigated and the resulting impact on gas and condensate production was calculated by numerical simulations in this study. Design parameters pertaining to field development and operations including well configuration and injection/production scheme were also investigated in this study along with the above parameters. Based on the results, guidelines on design issues relating gas injection parameters were suggested. The various simulation cases with different parameters helped with gaining insight into the strategy of gas injection techniques to remediate the gas productivity and condensate recovery. / text

Many geoscientists endorse Carbon Capture and Storage (CCS) as a potential strategy for mitigating emissions of greenhouse gases. Deep saline aquifers have been reported to have larger CO 2 storage capacity than other formation types because of their availability worldwide and less competitive usage. This work proposes an analytical model for screening potential CO 2 storage sites and investigates injection strategies that can be employed to enhance CO 2 storage. The analytical model provides of estimates CO 2 storage efficiency, formation pressure profiles, and CO 2 –brine interface location. The results from the analytical model were compared to those from a sophisticated and reliable numerical model (TOUGH 2 ). The models showed excellent agreement when input conditions applied in both were similar. Results from sensitivity studies indicate that the agreement between the analytical model and TOUGH2 strongly depends on irreducible brine saturation, gravity and on the relationship between relative permeability and brine saturation. A series of numerical experiments have been conducted to study the pros and cons of different injection strategies for CO 2 storage in confined saline aquifers. Vertical, horizontal, and joint vertical and horizontal injection wells were considered. Simulations results show that horizontal wells could be utilized to improve CO 2 storage capacity and efficiency in confined aquifers under pressure-limited conditions with relative permeability ratios greater than or equal to 0:01. In addition, joint wells are more efficient than single vertical wells and less efficient than single horizontal wells for CO 2 storage in anisotropic aquifers.

[pt] A produção de petróleo em alta vazão a partir de reservatórios formados por arenitos friáveis requer a instalação de sistemas de contenção de sólidos para preservar equipamentos de superfície e subsuperfície. Os projetos de explotação para campos constituídos por estes reservatórios têm na completação uma etapa fundamental na construção do poço. Dentre as diversas operações de completação, a instalação de sistemas de contenção de sólidos é uma das mais complexas e envolve uma ampla gama de recursos humanos e financeiros. A alteração no estado de tensões atuante sobre a formação é uma das principais fontes de carregamento dos sistemas de contenção mecânica de sólidos instalados em poços horizontais. O objetivo deste trabalho é desenvolver um modelo para avaliação do desempenho de sistemas de contenção de sólidos do tipo gravel pack quando submetidos aos esforços relacionados ao comportamento geomecânico das formações produtoras e a variação de pressões durante a vida produtiva de um poço de petróleo, permitindo a otimização de projetos destes sistemas sob a ótica da resistência ao colapso das telas. O carregamento imposto sobre estes sistemas é avaliado através da implementação do modelo de Mohr Coulomb solucionado numericamente através do método de elementos finitos (MEF). O programa comercial ABAQUS™ é utilizado em função da sua flexibilidade para solução de modelos não-lineares. Foram analisados sistemas de contenção de areia com os conjuntos de telas tipicamente utilizados na indústria de petróleo. Em nenhum cenário analisado foram verificados indícios de colapso dos tubos indicando a possibilidade de redução da sua resistência mecânica. / [en] Global increase in energy demand and the lack of opportunities on shore or in shallow waters are driving production of hydrocarbons towards deep and ultra deepwater basins, where reservoirs are usually formed by weak and unconsolidated sandstones that require sand control methods to prevent damage in surface and subsurface equipments. Guidelines to select sand control systems are primarily based on sand exclusion, seeking to optimize balance between oil rate and fines production. Another aspect, often overlooked, is collapse strength of the system formed by the sand control equipment and the formation itself, subjected to mechanical loadings that change during life of the well. This contribution presents a method to evaluate collapse strength of sand control systems taking into account mechanical interaction between the formation and sand control screens. Elastoplastic models are used to represent granular materials. Three sand control systems were studied: gravel pack with premium screens, stand alone premium screens and pre-packed screens. A model to describe contact between granular materials (gravel and formation) and soil-pipe interaction is proposed. Results demonstrate that perforated base pipes used in premium screens may be oversized for applications under regular operating conditions.

A 16×16×5.6 in. scaled, three-dimensional, physical model of a quarter of a 9-spot pattern was constructed to study the application of two processes designed to improve the efficiency of steam injection. The first process to be tested is the use of propane as a steam additive with the purpose of increasing recovery and accelerating oil production. The second process involves the use of a novel production configuration that makes use of a vertical injector and a smart horizontal producer in an attempt to mitigate the effects of steam override. The experimental model was scaled using the conditions in the San Ardo field in California and crude oil from the same field was used for the tests. Superheated steam at 190 – 200ºC was injected at 48 cm3/min (cold water equivalent) while maintaining the flowing pressures in the production wells at 50 psig. Liquid samples from each producer in the model were collected and treated to break emulsion and analyzed to determine water and oil volumes. Two different production configurations were tested: (1) a vertical well system with a vertical injector and three vertical producers and (2) a vertical injector-smart horizontal well system that consisted of a vertical injector and a smart horizontal producer divided into three sections. Runs were conducted using pure steam injection and steam-propane injection in the two well configurations. Experimental results indicated the following. First, for the vertical configuration, the addition of propane accelerated oil production by 53% and increased ultimate recovery by an additional 7% of the original oil in place when compared to pure steam injection. Second, the implementation of the smart horizontal system increased ultimate oil recovery when compared to the recovery obtained by employing the conventional vertical well system (49% versus 42% of the OOIP).

The conventional approach for estimation of in-situ porosity is the combined use of neutron and density logs. These nuclear borehole measurements are influenced by fundamental petrophysical, fluid, and geometrical properties of the probed formation including saturating fluids, matrix composition, mud-filtrate invasion and shoulder beds. Advanced interpretation methods that include numerical modeling and inversion are necessary to reduce environmental effects and non-uniqueness in the estimation of porosity. The objective of this dissertation is two-fold: (1) to develop a numerical procedure to rapidly and accurately simulate nuclear borehole measurements, and (2) to simulate nuclear borehole measurements in conjunction with inversion techniques. Of special interest is the case of composite rock formations of sand-shale laminations penetrated by high-angle and horizontal (HA/HZ) wells. In order to quantify shoulder-bed effects on neutron and density borehole measurements, we perform Monte Carlo simulations across formations of various thicknesses and borehole deviation angles with the multiple-particle transport code MCNP. In so doing, we assume dual-detector tool configurations that are analogous to those of commercial neutron and density wireline measuring devices. Simulations indicate significant variations of vertical (axial) resolution of neutron and density measurements acquired in HA/HZ wells. In addition, combined azimuthal- and dip-angle effects can originate biases on porosity estimation and bed boundary detection, which are critical for the assessment of hydrocarbon reserves. To enable inversion and more quantitative integration with other borehole measurements, we develop and successfully test a linear iterative refinement approximation to rapidly simulate neutron, density, and passive gamma-ray borehole measurements. Linear iterative refinement accounts for spatial variations of Monte Carlo-derived flux sensitivity functions (FSFs) used to simulate nuclear measurements acquired in non-homogeneous formations. We use first-order Born approximations to simulate variations of a detector response due to spatial variations of formation energy-dependent cross-section. The method incorporates two- (2D) and three-dimensional (3D) capabilities of FSFs to simulate neutron and density measurements acquired in vertical and HA/HZ wells, respectively. We calculate FSFs for a wide range of formation cross-section variations and for borehole environmental effects to quantify the spatial sensitivity and resolution of neutron and density measurements. Results confirm that the spatial resolution limits of neutron measurements can be significantly influenced by the proximity of layers with large contrasts in porosity. Finally, we implement 2D sector-based inversion of azimuthal logging-while-drilling (LWD) density field measurements with the fast simulation technique. Results indicate that inversion improves the petrophysical interpretation of density measurements acquired in HA/HZ wells. Density images constructed with inversion yield improved porosity-feet estimations compared to standard and enhanced compensation techniques used commercially to post-process mono-sensor densities. / text

Electrical Submersible Pumping (ESP) is a well known artificial lift technique in reservoirs having high-water cut and low gas-oil ratio. It is known as an effective and economical method of producing large volumes of fluid under different well conditions. ESP equipments are capable of producing in a range of 200 b/d to 60.000 b/d. A case study was done, by designing 10 deviated or horizontal wells selected from the Y-oilfield in Western Siberia. SubPUMP software developed by IHS Energy is used for designing the ESP systems of these wells. These 10 wells will be working with variable speed drives. After selecting the available equipment from the inventory, the best running frequencies are selected for these wells. Evaluations of the designs are made from the pump performance graphs of each well. The pumps should work within their optimum efficiency ranges. These ranges can be seen from the pump performance curves. If the designs made are not within these efficiency ranges, designs should be evaluated and selecting new equipment should be should be an option. Because working outside the optimum efficiency ranges will decrease the production, shorten the runlifes of the pumps and the production will not be stable.