Low-permeability Formations Research Articles

Performance evaluation of a novel CO2-induced clean fracturing fluid in low permeability formations

After the limitations of polymer-based fracturing due to poor clean-up property during flowback after fracturing treatment, viscoelastic surfactant (VES) received very huge attention in the last three decades, especially in low permeability reservoirs. In this study, a Novel CO 2 -induced clean fracturing fluid (SDS-TMTAD-CO 2 ) is formulated with simulated formation water (23,003 mg L −1 ) after optimization experiments according to the proposed parameters (i.e., 70 °C, economical, easily preparation, and environment-friendly). The results of rheological experiments show that the apparent viscosity of the fracturing fluid system increases to a certain extent under high salt conditions and possesses sufficient self-healing property against high shear tolerance. At different temperatures (25, 50, and 70 °C), the thermodynamic properties, fluid viscoelasticity, and proppant carrying capacity meet the requirements of the fracturing fluid industry standards. After adding kerosene (0.02 mol L −1 ); the gel breaking fluid viscosity (3.2 mPa s), anti-swelling rate (91.3%), and interfacial tension (2.3 × 10 −2 mN m −1 ) are holding promising conditions during the flowback period, clay swelling, and residual oil saturation, respectively. The filtration and core damage experimental results meet the national industry standard for fracturing fluids. The SEM results show that the fluid system after reaction forms a unified adsorption film on the core surface. Hopefully, this fluid system will be proved as a good candidate by means of excellent proppant transportation ability, anti-swelling, easy gel structure breaking, low filtration, and less formation damage in low permeable formations with an increase in productivity. • Easy preparation of an economical and environment-friendly CO 2 -induced clean fracturing fluid system (SDS-TMTAD-CO 2 ). • Rheological and functional performances of the system meet the “SY/T 6376-2008, SY/T 5107-2016, and SY/T 5971-2016” standards. • Can fracture the low permeable formations with less filtration and low formation damage.

A review of experimental studies on the proppant settling in hydraulic fractures

The hike of hydraulic fracturing in North America and beyond leads to significantly enhanced hydrocarbon production especially in low-permeability geological formations. Proppant settling is one of the most important particle motions during a hydraulic fracturing process, which to a large extent determines the created fracture's conductivity. This paper provides a critical review of the proppant settling in hydraulic fractures, with an emphasis on the experimental studies published in the past several decades. Six factors are identified out of a proppant/fracturing-fluid/fracture system: wall retardation, fluid rheology, proppant non-uniformity, proppant surface wettability, proppant concentration, and fracture complexity. Influences of these factors on the proppant settling are summarized based on the analysis of published experimental data, images, and correlations. Notwithstanding the extensive experimental studies, more experiments are in demand to systematically investigate proppant settling behavior in various kinds of fracturing fluids confined by hydraulic fractures. In addition, a gap is found to exist between the experimental studies of proppant transport and the application of the experimental findings to numerical simulations of hydraulic fracturing. • We conduct a comprehensive review of experimental studies on proppant settling in hydraulic fractures. • Six influential factors on proppant settling are identified. • More experiments are needed to study proppant settling behavior in non-Newtonian fracturing fluids. • More work is needed to properly apply experimental findings to numerical simulations and field operations.

Study on asynchronous injection and production of horizontal Wells in ultra-low permeability thin layer low abundance oil field

The ultra-low permeability, thin layer and low abundance GLN area is developed by waterinjection with horizontal and straight combined well pattern. With the extension of development time, the water appears in multiple sections and directions in horizontal Wells, and the well area gradually enters the stage of medium and high water cut, which shows the characteristics of rising when water is injected, falling when liquid is stopped, and limiting the profile control pressure in multiple rounds of Wells. Therefore, developing the “note when mining, mining without note” asynchronous injection-production adjustment of horizontal well technology, make full use of the artificial fracture of high permeability channel and matrix suction effect between low permeable formation permeability, increase the crack near the matrix suction swept volume, to achieve the purpose of the horizontal well steady liquid water control, up to the level of the special low permeability thin layer low abundance wellblock improve recovery factor. Through the mechanism of injection-production, the use of pore throat boundaries, the respect such as injection-production timing and parameter optimization research, combined with the reservoir numerical simulation and theoretical formula, conduct asynchronous injection-production field practice, improved the development effect of horizontal well, and have achieved good economic benefits, for the next class of reservoir level wellblock middle and high water cut stage to explore a new way of governance.

Effect of hydrophilic silica nanoparticles on hydrate formation during methane gas migration in a simulated wellbore

Natural gas hydrates are mostly formed in low-permeability and fractured muddy sedimentary formations. Adding suitable nanoparticles to the drilling fluid system can improve its filtrate resistance and fracture plugging, and effectively weaken the invasion of drilling fluid into the reservoir. However, it is likely that nanoparticles promote hydrate formation and accumulation in wellbores which will induce accidents. Therefore, this study investigated the effect of hydrophilic silica nanoparticles with particle sizes of 30 nm, 60 nm, and 80 nm and concentrations of 0.5–4.0 wt% on hydrate formation during upward migration of methane gas using a dynamic simulation system for hydrate formation in a wellbore. The experimental results show that under the condition of methane gas migration, hydrophilic silica nanoparticles inhibit hydrate formation. The inhibition effect increased with the growth in the particle size under a constant concentration, whereas it first increased and then decreased with increasing nanoparticle concentration under a constant particle size. The strongest inhibition effect was observed at a hydrophilic silica nanoparticle concentration of 2.0 wt%. The influence of hydrophilic silica nanoparticles on hydrate formation may be mainly determined by their hydrophilic properties, heat and mass transfer, and gas migration in the wellbore. Our research indicates that hydrophilic silica nanoparticles can be added to hydrate drilling fluid systems if their concentration can be properly controlled.

Investigation of the influence of the heterogeneous permeability distribution on the oil phase displacement processes

The object of research is the filtration processes of displacement of the oil phase under the influence of an injection well in a heterogeneous porous medium. It is possible to evaluate and take into account the effect of reservoir heterogeneity on the distribution of reservoir pressure (and, consequently, on the intensity of the filtration process) using numerical modeling of filtration processes based on the piezoelectric equation. To solve the non-stationary anisotropic problem of piezoconductivity, it is proposed to apply the combined finite-element-difference method of M. Lubkov, which makes it possible to take into account the inhomogeneous distribution of permeability inside the anisotropic oil-bearing formation and at its boundaries, and to adequately calculate the distribution of reservoir pressure. The use of the combined finite-element-difference method allows to combine the advantages of the finite-element method and the finite difference method: to model geometrically complex areas, to find the value at any point of the object under study. At the same time, the use of an implicit difference scheme when finding the nodal values of the grid provides high reliability and convergence of the results. The simulation results show that the distribution of the pressure field between the production and injection wells significantly depends on their location, both in the isotropic landslide and in the anisotropic oil-bearing reservoir. It is shown that the distance between the wells of more than 1 km levels out the effectiveness of the impact of the injection well on the oil filtration process. The influence of the permeability of the oil phase in the shear direction dominates the influence of the permeability in the axial directions (affects the pressure decrease by 4–9.5 %). In the case of a landslide-isotropic reservoir, the wells should be located in the shear (diagonal) direction, which will provide the lowest level of drop in the average reservoir pressure (by 4 %). Based on the information obtained, for the effective use of anisotropic low-permeability formations, it is necessary to place production and injection wells in areas with relatively low anisotropy of the formation permeability, especially to avoid places with the presence of landslide permeability of the formation. The location of the wells is important so that, on the one hand, there is no blockage of oil from the side of reduced permeability, and on the other hand, rapid depletion of the formation from the side of increased permeability does not occur. And also the mutual exchange between the production and injection wells did not stop. When placing a system of production and injection wells in anisotropic formations of an oil field, it is necessary to carry out a systematic analysis of the surrounding anisotropy of the formations in order to place them in such a way that would ensure effective dynamics of filtration processes around these wells. Using the method used, it is possible to predict the impact of an injection well on the distribution of reservoir pressure in the reservoir.

Molecular and stable carbon isotope geochemistry of mud-gas-derived hydrocarbons and its application for the assessment of low-permeability reservoirs from the Montney Formation, Western Canada

Mud-gas isotope logging (MGIL) of hydrocarbons (methane, ethane, propane) has become a widely used approach to fingerprint gas-bearing formations during the drilling of vertical and horizontal oil and gas wells often with the goal to assess potential cross-formational gas migration. In this study, we have used mud-gas molecular and isotope data to assess the usefulness of MGIL for the geochemical assessment of a single low-permeability reservoir formation, the Montney Formation in Western Canada. An example from a well completed in British Columbia shows that hydrocarbon samples collected in IsoJars® tend towards more positive carbon isotope ratios compared to data for samples obtained using IsoTubes®, potentially attributed to 13C enriched residual gas retained in the cuttings. Additionally, in publically available mud-gas data from 45 other wells, it was found that the carbon isotope ratios of mud-gas from the Montney Formation are overall consistent with the thermal maturity of this stratigraphic unit, but the data display a relatively scattered trend on a thermal maturity plot based on Δ13CC1-C2 and Δ13CC1-C3. Molecular parameters such as [C1/(C2 + C3)] can be modified via processes such as desorption and diffusion after sampling gases in IsoJars®, while the i-C4/n-C4 ratio was found to be the most consistent molecular parameter between sampling techniques. We conclude that mud-gas molecular and isotope data derived from samples collected in IsoTubes® are suitable for geochemical assessment (e.g. thermal maturity, fluid–fluid correlations) of low permeability hydrocarbon reservoirs such as the Montney Formation.

Integrated modelling approach to oil recovery increase of Achimov formation

Background. Tight sand deposits development has always been a challenging process that frequently requires application of innovative approaches. Horizontal drilling in non-uniform lithology is frequently accompanied by circulation, wellbore stability losses and other complications. Hydraulic fracturing stimulation does not always result in productivity increase, which reduces profitability of development. Due to the incomplete understanding of geological and geomechanical specifics of Achimov deposits, — formations with complex heterogenous structure, low permeability, presence of low-amplitude structural dislocations, — the controlled use of features of formation is hindered and, in turn, makes it necessary to develop an innovative strategy of their surveillance and stimulation. Aim. In purpose to optimize an existing development strategy of Achimov deposits in Vingayakhinskoe oilfield, we have developed and applied an approach involving complex cross-segment modelling. At the same time, verification of hypothesis on possibility to identify and activate naturally fractured zones. Materials and methods. To form criteria for verification of hypothesis of fracture network generation in Achimov deposits, a 1D and 3D geomechanical models have been built in view of the applied approach, along with a model of natural fractures. Development of hydraulic fracturing designs, efficiency of which has been evaluated with respect to such reservoir modeling results as predicted production rate and cumulative production, have been the next step, performed for different geological and geomechanical conditions. Thus, the principal feature of applied approach is coupling between geomechanical modeling, complex multivariant hydraulic fracturing modeling and reservoir modeling with the target to maximize production. Results. The well stimulation strategy, selected based on the results of multivariate integrated modeling, was successfully implemented as part of the pilot high-flow hydraulic fracturing operation, which led to an almost twofold increase in the initial production rates of project wells versus off set wells. Conclusions. The obtained results of the work confirm that the developed integrated modeling approach can serve as a reliable basis for optimizing the development of heterogeneous and low-permeability formations such as Achimov deposits.

A New Method to Estimate Formation Pore Pressure in Fractured Areas of Shale Gas Reservoir

The matrix of shale gas reservoir has the characteristics of low porosity and ultra-low permeability, but also develop natural and hydraulic fractures. Many field operations observed that the formation pore pressure after hydraulic fracturing is higher than the original formation pore pressure. Drilling in the fractured areas of shale gas reservoir, including natural fractures and artificial fractures, always faces greater overflow risk. The pore pressure test after fracturing also shows that the test value is higher than the formation initial pore pressure. However the conventional formation pore pressure predicting methods are difficult to obtain the accurate pore pressure in the fractured areas of shale gas reservoir.In this paper, the causes of formation pore pressure changing and fracturing pressurization effect in the fractured zones of shale gas reservoir are analyzed. Based on the assumption of closed and constant volume material balance and the gas equation of state, the internal mechanism of the increase in pore pressure caused by fracturing operation in low-permeability shale gas formation is theoretically analyzed. A new method to predict pore pressure changing of shale gas reservoir during drilling and hydrofracturing operations is proposed. The pore connectivity of shale gas reservoir is poor, and the permeability is tens of nano-darcy. The permeability is usually between 0.01-0.20 millidarcy when natural fractures are developed. After fracturing, the permeability can be increased by 2-3 times. Based on the principle of effective stress, a pore pressure calculation model with the influence of permeability change is established by using logging data. Three influence terms are considered in the model: the first one is the overburden pressure term, the second one is the skeleton stress term, and the last one is the influence term of permeability change rate on local formation pore pressure. The proposed method shows simple principle, clear mechanism and easy to use in the field. Field applications show that this method could quickly and accurately predict dynamic formation pore pressure changing of shale gas reservoir. It offsets the shortcomings of traditional formation pore pressure calculation methods.

Stochastic Techno-economic Analysis of CO2-circulated Geothermal Energy Production in a Closed Reservoir System

Many wells become abandoned with the depletion of oil and gas reservoirs, and low-enthalpy geothermal energy could be extracted from these abandoned wells. CO2 has been proposed and studied as the working fluid for mining such geothermal energy sources, owing to its favorable thermodynamic properties. The objective of this study is to develop an uncertainty-based simulation-optimization approach to analyze the techno-economic feasibility of CO2-circulated geothermal production in a closed reservoir system. In doing so, we address the particular geothermal reservoir conditions found in North Oman`s foreland basin where several large oil/gas fields are located. The geothermal reservoir conditions in this area can be characterized by inclined and thin layers, partially to fully fault-blocked, and relatively homogeneous and low permeable formations. Such conditions have not been investigated in the context of CO2-circulated geothermal production. Another key novelty of this work is to analyze a triplet horizontal well placement designed particularly for such thinly-bedded fully-closed reservoirs. The main building blocks of the proposed methodology are the application of a non-isothermal, multi-phase, multi-component numerical reservoir simulator, a neural network-based metamodel, Monte Carlo simulations, and genetic algorithm. The findings suggest the proposed well pattern is technically feasible and economically viable to harvest low-enthalpy geothermal energy from the type of depleted reservoirs found in North Oman region.

Impact of Fracture Geometry and Topology on the Connectivity and Flow Properties of Stochastic Fracture Networks

AbstractIn a low permeability formation, connectivity of natural and induced fractures determines overall hydraulic diffusivity in fluid flow through this formation and defines effective rock permeability. Efficient evaluation of fracture connectivity is a nontrivial task. Here, we utilize a topological concept of global efficiency to evaluate this connectivity. We address the impact of key geometrical properties of stochastic fracture networks (fracture lengths, orientations, apertures, and positions of fracture centers) on the macro‐scale flow properties of a shale‐like formation. Six thousand different realizations have been generated to characterize these properties for each fracture network. We find that a reduced graph of a fracture network, which consists of the shortest paths from the inlet nodes (fractures) to all outlet nodes, contributes most to fluid flow. Three‐dimensional (3D) fracture networks usually have higher global efficiency than two‐dimensional (2D) ones, because they have better connectivity. All geometrical properties of fractures influence quality of their connectivity. Aperture distribution impacts strongly global efficiency of a fracture network and its influence is more significant when the system is dominated by large fractures. Fracture clustering lowers global efficiency in both 2D and 3D fracture networks. Global efficiency of 2D and 3D fracture networks also decreases with the increasing exponent of the power‐law distribution of fracture lengths, which means that the connectivity of the system decreases with an increasing number of small fractures. Realistic fracture networks, composed of several sets of fractures with constrained preferred orientations, share all the characteristics of the stochastic fracture networks we have investigated.

Design and Safety Considerations for Coiled Tubing Operations in Geothermal Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30408, “Design and Safety Considerations To Perform Coiled Tubing Operations in Large-Diameter, High-Temperature Geothermal Wells,” by Ishaan Singh, SPE, Danny Aryo Wijoseno, SPE, and Kellen Wolf, Schlumberger, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 17–19 August. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The productive section in a high-pressure, high-temperature (HP/HT) geothermal Field A in the Philippines features shallow and deep reservoirs separated by a low-permeability formation. However, recent years have seen a reduction in production levels. To activate and enhance well production, coiled tubing (CT) nitrogen-lift operations were required. CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations. The outcome helped the design of a new cooling-loop system and allowed optimization of the nitrogen-lift technique. As a result, two large-diameter geothermal wells were lifted safely with 2-in. CT. Introduction This study describes design and safety considerations in performing CT operations in high-temperature, large- diameter geothermal wells. The customized high-temperature-grade seal material was chosen to withstand high bottomhole temperatures (BHT) (600°F), and a heat exchanger riser system was designed and tested on the job to handle high-surface-temperature steam (350–400°F), thus mitigating potential well-control incidents. Challenges of Seal Damage Caused by High Surface Temperatures in Live Well Intervention The CT interventions in quenched HP/HT geothermal wells reduce the risk of surface equipment failure. The seal material readily available in the market is rated to 250°F, but, if quenching is not possible, the high-temperature steam (approximately 350–400°F) may flow into the pressure-control equipment, leading to seal damage and CT contingencies. At high temperatures (400°F), these seals are unusable. It becomes essential to use a surface heat exchange riser (HER) system to prevent this issue. Design and Execution of HER Systems in Field A To avoid any well contingency and to keep pressure-control equipment safe, HER systems can be used. Some basic designs for HERs are described in the complete paper. For this study, a customized 4.06-in. HER cooling system (Design 1, shown in Fig. 1) was designed to accommodate 2-in. CT pipe. Design 1 was chosen from an evaluation of three design candidates outlined in the complete paper. The wellhead stack featured seal elements rated to high temperatures (400°F). To prevent high- temperature steam from entering the wellhead stack, the blowout preventer, and other surface- equipment elements, an efficient HER system was designed wherein, while the CT is still in the well performing CT operations, the cold water can be pumped into the CT-stack annulus from the top flow cross through the cooling riser to the bottom flow cross and back to the return tank. The temperature of the cooling loop was continuously monitored to ensure that it was well below 212°F (the boiling point of water).

Effects of Velocity and Permeability on Tracer Dispersion in Porous Media

During micro-scale tracer flow in porous media, the permeability and fluid velocity significantly affect the fluid dispersion properties of the media. However, the relationships between the dispersion coefficient, permeability, and fluid velocity in core samples are still not clearly understood. Two sets of experiments were designed to study the effects of tracer fluid flow velocity and porous medium permeability on the dispersion phenomenon in a core environment, using natural and sand-filled cores, respectively. From experimental data-fitting by a mathematical model, the relationship between the dispersion coefficient, flow velocity, and permeability was identified, allowing the analysis of the underlying mechanism behind this phenomenon. The results show that a higher volumetric flow rate and lower permeability cause a delay in the tracer breakthrough time and an increase in the dispersion coefficient. The core experimental results show that the dispersion coefficient is negatively correlated with the permeability and positively correlated with the superficial velocity. The corresponding regression equations indicate linear relations between the dispersion coefficient, core permeability, and fluid velocity, resulting from the micron scale of grain diameters in cores. The combination of high velocity and low permeability yields a large dispersion coefficient. The effects of latitudinal dispersion in porous media cannot be ignored in low-permeability cores or formations. These findings can help to improve the understanding of tracer flow in porous media, the design of injection parameters, and the interpretation of tracer concentration distribution in inter-well tracer tests.

A New Integrated Technique for Saturation Height Function Modeling based on Modified EQR Method

Equivalent Radius (EQR) is a relatively new normalized capillary pressure method for modeling of the saturation height function. In this method petrophysical data such as well logs, special and routine core analysis have been used in an integrated manner.
 The main purpose of this study is to investigate dynamic behavior of the fluid flow through porous media with a new integrated technique for saturation height function modeling. Amongst different methods, EQR method that originally developed by Engstrom in 1996 has been selected for further study. Although this method can model the initial water saturation with high accuracy but it only can be applicable for low permeability formations. However, there is still an incomplete understanding its application for other rock units with higher degree of porosity and permeability. For this purpose, we present a Modified EQR (MEQR) based on iterative curve fitting procedure. To demonstrate the capabilities of MEQR method, one of the Iranian oil field data located in southwest of Iran with quite high degree of permeability in its porous sandstone layers has been used.
 It is shown that this technique can accurately predict the initial water saturation in all rock types and in each cell of the reservoir with very good correlation coefficient achieved in comparison with interpreted saturation well logs.

Water Distribution from Artificial Recharge via Infiltration Basin under Constant Head Conditions

The vadose zone plays a significant role during artificial recharge via the infiltration basin. Its thickness, lithology, heterogeneity, among others greatly affect the recharge efficiency. The main objective of this research is to establish the role of the vadose zone and the impacts of infiltration basin features and vadose zone factors on water distributions. In this work, an ideal conceptual model was considered, and mathematical models were built using HYDRUS (2D/3D) software package version 2.05. A total of 138 numerical experiments were implemented under seven types of experimental conditions. The experimental data were analyzed with the aid of correlation and regression analysis. The results showed that infiltration basin features and vadose zone factors had various impacts on water distribution, low permeability formation had various effects on evaporation depending on its depth, and there were consistent, similar, or different variation trends between infiltration and recharge. In conclusion, it is recommended that when the vadose zones are to be chosen as an infiltration basin site, the trade-off among the infiltration, recharge, storage, and evaporation should be seriously considered. This paper may contribute to a better understanding of the vadose zone as a buffer zone for artificial recharge.

Effect of Seepage Force on the Wellbore Breakdown of a Vertical Wellbore

As a fluid flows through a porous media, a drag force, called seepage force in the paper, will be formed on the matrix of the media in the fluid flowing direction. However, the seepage force is normally ignored in the analysis of wellbore fracturing during hydraulic fracturing operation. In this paper, an analytical model for seepage force around a vertical wellbore is presented based on linear elasticity theory, and the effect of the seepage force on wellbore breakdown has been analyzed. Also studied are the effects of the two horizontal principal stresses and the reservoir permeability on the action of seepage force. The paper proves that seepage force lowers formation breakdown pressure of a vertical wellbores; the deeper a formation is, the greater action of the seepage force; seepage force contributes more to breakdown formation with small difference of the two horizontal stresses such as unconventional reservoirs; seepage force increases as rock permeability decreases, and it should not be ignored in hydraulic fracturing analysis, especially for low-permeability formation.

The effect of the viscosity-dependent boundary layer on tight oil flow behavior in CO2 Huff-Puff processes: A unified dimensional Pre-Darcy flow model

There are numerous percolation studies of unconventional reservoirs showing that in tight or low-permeability formations, the oil flow behavior could be described by the Pre-Darcy mechanism. However, for the CO 2 Huff-n-Puff operations, the most presented low-velocity Pre-Darcy flow models may result in an erroneous evaluation due to the intensive boundary layer thickness changes caused by the CO 2 extraction and dissolution. In this paper, with multiple parameters fitting the seepage experimental results of the studied area, a unified dimensional Pre-Darcy flow model for CO 2 enhanced oil recovery (EOR) is derived from the classic Poiseuille model. Then, the proposed flow model is applied in the compositional simulator for analyzing the viscosity-dependent boundary layer (VDBL) effect, applicability evaluation in Huff-Puff EOR, and field history matching. The results indicate that the VDBL effect improves the oil mobility in injection periods and lowers the residual oil saturation at the front of the CO 2 convection-diffusion area in reproduction periods. Additionally, the nonlinear parameter α and the shape parameter β enhance the proposed model's applicability for the Huff process and the Puff process respectively. Finally, by adjusting the parameters α and β for different permeability intervals of the geological model, the flow model is successfully applied in the oil production matching of the Y6 well, which exhibits its reliability in the history matching. • A unified dimensional flow model is derived from the classic Poiseuille model to characterize the oil seepage behavior. • The proposed flow model is applied in the compositional simulator for analyzing the VDBL effect. • The flow model is successfully applied in history matching of the Songliao tight field in China to exhibit its reliability.

Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.

Borehole stability in shale formations: Effects of Thermal˗Mechanical˗Chemical parameters on well design

Borehole instability in the petroleum industry is mainly because of mechanical, chemical, and thermal factors which result in substantial yearly expenditures. The essential part of analysing borehole stability is choosing an optimum rock strength criterion. Many rock strength criteria have been used for rock failure analysis, however all mechanical, chemical and thermal effects are seldom coupled with rock failure criteria to evaluate borehole stability. This paper presents six rock strength criteria coupled with a poro˗chemo˗thermo˗elastic model to analyse borehole stability in shale formations. This model considers the mechanical, chemical, and thermal effects within the stress distribution around a wellbore to evaluate shear and tensile failure. The effects of time and wellbore configuration (i.e. azimuth and inclination angles) on the stability of borehole in shale formations have also been examined. Furthermore, the minimum mud pressures are estimated by investigating wellbore stability at both the borehole wall and the entire near˗borehole area (i.e. inside the formation). Finally, a sensitivity analysis was performed to quantify and compare the effect of each mechanical, chemical, and thermal parameter as well as their level of importance on wellbore stability analysis. The results of dimensionless sensitivity coefficients indicate that, depending on the applied rock failure criteria, the parameters have different order of importance in analysing borehole stability. The impact of error in determination of input parameters on the magnitude of error in critical mud pressure was also presented. The results of this paper will help to effectively control time-dependent borehole instability in low-permeable shale formations, thereby lowering drilling nonproductive time and costs.

A simulation study on the effect of the dispersion on the process of enhanced oil recovery

Gas injection is a potential proven enhanced oil recovery technique due to the difficulty of injecting water in the low permeability reservoir. In the process of gas flooding, there is mass transfer between fracture-matrix, which is called diffusion due to the fluid velocity difference in matrix and fractures. In the complex fracture network formed by hydraulic fracturing in the low permeability formation, this mass transfer is widely existed. However, it is often neglected in the past studies about optimization design of gas flooding. In this paper, embedded discrete fracture model (EDFM) using vectorization programming is built which is easy to obtain pressure gradient and velocity to characterize dispersion caused by velocity difference between matrix and fracture. And the EDFM is used to simulate the gas flooding for a typical well, which is in good agreement with Eclipse verified the accuracy of the model. Through a series of comparisons, the influences of different fracture network mode, matrix permeability, dispersion and gas injection rate on gas flooding are analyzed and the well performance is comprehensively evaluated considering the fracture network and the dispersion in the gas flooding.

Analysis of Seepage Law of Precipitation in Horizontal Wells with Low Permeability Formation

Based on the euler model of multiphase flow in FLUENT and standard k-epsilon model, considering the influence of negative pressure inlet position (pump position) and nitial water head height (water head thickness), a 3d Pipe flow-seepage coupling pumping model for horizontal wells is built and calculated iteratively. On this basis, a detailed study is carried out on how to improve the fluid collection efficiency of horizontal wells. The results show that: (1) the fluid velocity at the negative pressure inlet increases as the pressure inlet location decreases from the top of the horizontal well to the heel, in the process of the depth change from heel to toe in the horizontal section, the fluid velocity at the negative pressure inlet increases first and then decreases; (2) the pressure increases in a certain proportion with the increase of the initial water head (that is, the thickness of water layer), and then the efficiency of horizontal well is improved; (3) Combined with numerical simulation analysis, in the model experiment, fluid flow causes uneven distribution of sand around the horizontal well, leading to a certain degree of pore annihilation, which causes pressure fluctuation along the horizontal well and reduces the production efficiency.