High-permeability Reservoirs Research Articles

A Semianalytical Modeling Approach for Hydraulic Fracture Initiation and Orientation from Perforated Wells

Summary Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment's eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for relative-to-the-wellbore (longitudinal or transverse) fracture initiation from perforated wells. These criteria were assessed numerically and found to overestimate the occurrence of transverse fracture initiation, which only takes place under a narrow range of conditions in which the tensile strength of the rock formation is lower than a critical value, and the breakdown pressure falls within a “window.” For a case study performed on the Barnett Shale, transverse fracture initiation is shown to take place for breakdown pressures below 4,762 psi, provided that the formation's tensile strength is below 2,482 psi. A robust 3D finite volume numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence developing correction factors for the existing closed-form approximations. Geomechanical inputs from the Barnett Shale are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The corrected numerically derived expressions can predict initiation pressures for a specific orientation of fracture initiation. Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study, which is under a normal faulting stress regime, the perforations on the side of the borehole yield a wider breakdown pressure window by 71% and higher critical tensile strength by 32.5%, compared to perforations on top of the borehole, implying better promotion of transverse fracture initiation. Leakage of fracturing fluid around the wellbore, between the cemented casing and the surrounding rock, reduces the breakdown pressure window by 11% and the critical tensile strength by 65%. Dimensionless plots are employed to present the range of in-situ stress states in which longitudinal or transverse hydraulic fracture initiation is promoted. This is useful for completion engineers; when targeting low permeability formations such as shale reservoirs, multiple transverse fractures must be induced from the horizontal wells, as opposed to longitudinal fracture initiation, which is desired in higher permeability reservoirs or “frac-and-pack” operations.

Analysis of Oil Displacement Efficiency of Subsequent Water Flooding Reservoir by Polymer Flooding

After many years of development of basic well pattern and polymer flooding, the block reservoir has high comprehensive water cut, high water flooded degree and high proportion of water absorbing thickness of high permeability reservoir. In this paper, the water flooding characteristics of each sedimentary unit in the subsequent water flooding reservoir of polymer flooding, the existence and quality of oil in pores, the oil displacement efficiency and the factors affecting the oil displacement efficiency are analyzed based on the data of water flooded layer of updated wells and the coring data of new wells in recent years.

Research on small-scale sand fracturing and puff technology

Affected by complex fault blocks, sedimentary environment and reservoir physical properties, Jidong Oilfield generally develops small-scale sand bodies, accounting for 24.2% of the produced reserves of medium and low permeability reservoirs. Such sand bodies rely on elastic energy to develop and are difficult to use effectively. In this paper, through the three-dimensional hydraulic physical model experiment and the analysis of the oil layer-dry layer-mudstone mixed sand body, the reasons that affect the model parameters are obtained. The results show that: the length of the high-permeability reservoir area, the length of the intermediate-permeability dry layer area, the rate of change of permeability parameters, the viscosity of the construction fluid, and the construction displacement have an impact on the effect of fracturing enhanced injection energy storage.

Simulation of the process of surfactant-polymer flooding in high-permeable pore-type reservoirs containing high-viscosity oil

Simulation of the process of surfactant-polymer flooding in high-permeable pore-type reservoirs containing high-viscosity oil

Application of Phase Change Tracking Approach in Predicting Condensate Blockage in Tight, Low, and High Permeability Reservoirs

Prediction of the timing and location of condensate build-up around the wellbore in gas condensate reservoirs is essential for the selection of appropriate methods for condensate recovery from these challenging reservoirs. The present work focuses on the use of a novel phase change tracking approach in monitoring the formation of condensate blockage in a gas condensate reservoir. The procedure entails the simulation of tight, low and high permeability reservoirs using global and local grid analysis in determining the size and timing of three common regions (Region 1, near wellbore; Region 2, condensate build-up; and Region 3, single-phase gas) associated with single and two-phase gas and immobile and mobile gas condensate. The results show that permeability has a significant influence on the occurrence of the three regions around the well, which in turn affects the productivity of the gas condensate reservoir studied. Predictions of the timing and location of condensate in reservoirs with different permeability levels of 1 mD to 100 mD indicate that local damage enhances condensate formation by 60% and shortens the duration of the immobile phase by 45%. Meanwhile, the global change in permeability increases condensate formation by 80% and reduces the presence of the immobile phase by 60%. Finally, this predictive approach can help in mitigating condensate blockage around the wellbore during production.

Geothermal energy exploitation from depleted high-temperature gas reservoirs by recycling CO2: The superiority and existing problems

CO2 can be used as an alternative injectant to exploit geothermal energy from depleted high-temperature gas reservoirs due to its high mobility and unique thermal properties. However, there has been a lack of systematic analysis on the heat mining mechanism and performance of CO2, as well as the problems that may occur during geothermal energy exploitation at specific gas reservoir conditions. In this paper, a base numerical simulation model of a typical depleted high-temperature gas reservoir was established to simulate the geothermal energy exploitation processes via recycling CO2 and water, with a view to investigate whether and/or at which conditions CO2 is more suitable than water for geothermal energy exploitation. The problems that may occur during the CO2-based geothermal energy exploitation were also analyzed along with proposed feasible solutions. The results indicate that, for a depleted low-permeability gas reservoir with dimensions of 1000 m × 500 m × 50 m and temperature of 150 °C using a single injection-production well group for 40 years of operation, the heat mining rate of CO2 can be up to 3.8 MW at a circulation flow rate of 18 kg s−1 due to its high mobility along with the flow path in the gas reservoir, while the heat mining rate of water is only about 2 MW due to limitations on the injectivity and mobility. The reservoir physical property and injection-production scheme have some effects on the heat mining rate, but CO2 always has better performance than water at most reservoir and operation conditions, even under a high water saturation. The main problems for CO2 circulation are wellbore corrosion and salt precipitation that can occur when the reservoir has high water saturation and high salinity, in which serious salt precipitation can reduce formation permeability and result in a decline of CO2 heat mining rate (e.g. up to 24% reduction). It is proposed to apply a low-salinity water slug before CO2 injection to reduce the damage caused by salt precipitation. For high-permeability gas reservoirs with high water saturation and high salinity, the superiority of CO2 as a heat transmission fluid becomes obscure and water injection is recommended.

Micro-Sweep Characteristics of CO2 Flooding

In this paper a micro multi-phase flow equation is built based on the mechanism of a multi-phase fluid flow in porous media. The authors consider the impact of convection diffusion and the improved component mixing rule. In order to accurately evaluate the fluid flow in a low permeability reservoir, two models are established to simulate simple pore throat structure and complex pore throat structure. The predicted residual oil distribution characteristics of CO2 flooding in low permeability reservoir, calculated by finite element microsimulation, have been further verified by experiment. Furthermore, we analyze the effect of different wettability on microflow characteristics of CO2 flooding. The results show that CO2 flooding improving microsweep volume by convective diffusion is more evident in low permeability reservoirs than in high permeability reservoirs. The residual oil is mainly distributed following a pattern of prismatic, wedge-shape, or membrane microstructure. With decrease in the wetting angle on the fluid-rock boundary, the efficiency of oil displacement is further improved.

Feasibility Study of Carbon Dioxide Plume Geothermal Systems in Germany−Utilising Carbon Dioxide for Energy

To manage greenhouse gas emissions, directives on renewable energy usage have been developed by the European Commission with the objective to reduce overall emissions by 40% by 2030 which presents a significant potential for renewable energy sources. At the same time, it is a challenge for these energy technologies which can only be solved by integrated solutions. Carbon capture and storage combined with geothermal energy could serve as a novel approach to reduce CO2 emissions and at the same time facilitate some of the negative impacts associated with fossil fuel-based power plants. This study focuses on the technical and economic feasibility of combining these technologies based on a published model, data and market research. In the European Union, Germany is the most energy intensive country, and it also has an untapped potential for geothermal energy in the northern as well as the western regions. The CO2 plume geothermal system using supercritical carbon dioxide as the working fluid can be utilized in natural high porosity (10–20%) and permeability (2.5 × 10−14–8.4 × 10−16 m2) reservoirs with temperatures as low as 65.8 °C. The feasibility of the project was assessed based on market conditions and policy support in Germany as well as the geologic background of sandstone reservoirs near industrialized areas (Dortmund, Frankfurt) and the possibility of carbon capture integration and CO2 injection. The levelized cost of electricity for a base case results in € 0.060/kWh. Optimal system type was assessed in a system optimization model. The project has a potential to supply 6600/12000 households with clean energy (electricity/heat) and sequester carbon dioxide at the same time. A trading scheme for carbon dioxide further expands potential opportunities.

Effect of temperature on gas production from hydrate-bearing sediments by using a large 196-L reactor

Methane hydrate exploitation via depressurization for a reservoir with a bottom gas-rich zone was simulated using a large-sized three-dimensional hydrate simulator. A single vertical well system and a system with a combination of vertical and horizontal wells were employed to elucidate the different effects of horizontal and vertical wells on the exploitation process. The results showed that effect of promoting gas production using a horizontal well is not obvious for a high permeability reservoir. A large exploitation temperature drop may lead to ice blockage in the pipelines, and fracturing technology was introduced to solve this blockage problem. Experiments performed above and below the freezing point inferred that the decomposition of the hydrate in different areas of the reactor was not simultaneous, according to analysis of the temperature distribution of the entire reactor during the exploitation process. For exploitation above the freezing point, temperatures in the bottom of the reactor tend to maintain a low level and work against hydrate decomposition. However, for exploitation below the freezing point, the low-temperature area in the bottom of the reactor preferentially converts to ice. Heat release and salt precipitation promoted hydrate decomposition, and the decomposition rate was significantly accelerated.

Diagenetic evolution and formation mechanisms of middle to deep clastic reservoirs in the Nanpu sag, Bohai Bay Basin, East China

Abstract The reservoir properties, diagenetic features and evolution of the Paleogene Shahejie Formation (Es) in the Nanpu sag, Bohai Bay Basin were analyzed based on mineralogical and petrological data, and the main controlling factors and formation mechanisms of medium to deep high-quality reservoir were revealed by multiple regression analysis. The results show that the sedimentary microfacies, rigid grains content, and dissolution process are the key factors controlling the formation of high-quality clastic reservoir in middle to deep depth in the Nanpu sag. The formation mechanisms of middle to deep sandstones of the Es in different structural belts differ widely in formation mechanism. The Es1 (uppermost member of Es) sandstone reservoirs in the Nanpu No.3 structural belt is low porosity, moderate to high permeability reservoir in the mesodiagenesis A2 stage on the whole, and the formation of high-quality reservoirs is mainly attributed to strong compaction resistance ability primarily, and dissolution process secondarily. The Es3 (third member of Es) sandstones in Gaoshangpu structural belt is classified as tight sandstones in the mesodiagenesis A1 stage, in which the development of favorable reservoirs is primarily controlled by dissolution. This study provides references for reservoir evaluation of deep clastic reservoirs and exploration deployment in the Bohai Bay rift basin. As there are high-quality reservoirs, it is believed that the deep clastic reservoirs in the eastern of China, such as Bohai Bay Basin still have significant exploration potential.

Effect of a Partial Pressure Tool on Improving the Heterogeneous Oil Recovery and Polymer Solution Microstructure.

To improve the oil displacement effect of polymer solutions in heterogeneous oil layers and increase the energy utilization rate, Daqing Oilfield proposes a partial pressure tool to control the polymer solution injection amount in high-permeability oil layers and increase the injection amount in low-permeability oil layers to enhance the total oil recovery. To study the effect of the partial pressure tool on enhancing oil recovery and the action mechanism of the tool on polymer molecules in high-permeability reservoirs, core displacement experiments were performed to study the effects of various factors on oil recovery. Microscopic experiments were then carried out to study the differences in molecular morphology and molecular coil size of the microscopic polymer solution before and after the action of the partial pressure tool. The experimental results show that the partial pressure tool increased the oil recovery by 4.4% and that the throttling pressure difference was directly proportional to the oil recovery. The partial pressure tool subjected the polymer solution to shear deformation and reduced the molecular coil size. When the concentration of the solution was changed, the degree of change in the molecular structure and the coil size was small, and the influence on the oil displacement effect was minimal. This experiment is of great significance for improving the energy utilization rate.

Study on influence of two-phase filtration transformation on formation of zones of undeveloped oil reserves

In order to study the process of fluid filtration during flooding of an oil field, article uses Rapoport – Lis model of non-piston oil displacement by water. During plane-radial filtration in a homogeneous formation, radii of disturbance zones are determined with and without taking into account the end effect. Influence of changes in value of capillary pressure gradient on distribution of water saturation coefficient in the non-piston displacement zone for high and low permeability reservoirs is revealed. Application of an element model for a five-point injection and production well placement system showed that, using traditional flooding technology, flat-radial fluid filtration is transformed into rectilinear-parallel. At solving equation of water saturation, Barenblatt method of integral relations was used, which allows determining the transformation time. By solving the saturation equation for rectilinear-parallel filtration, change in the value of water saturation coefficient at bottomhole of production well for an unlimited and closed deposit is determined. It is shown that an increase in water cut coefficient of a production well is possible only for a closed formation. To determine coefficient of water saturation in a closed deposit, a differential equation with variable coefficients is obtained, an iterative solution method is proposed. In the element of the five-point system, oil-saturated zones not covered by development were identified. For channels of low filtration resistance, conditions for their location in horizontal and vertical planes are established. It is shown that, at maintaining formation pressure, there is an isobar line in formation, corresponding to initial formation pressure, location of which determines direction of fluid crossflow rates. Intensity of crossflows affects application efficiency of hydrodynamic, physical and chemical, thermal and other methods of enhanced oil recovery.

Salt induced shear thickening behavior of a hydrophobic association polymer and its potential in enhanced oil recovery

Shear thickening solution is rarely encountered but the solution with low concentration and high salinity is really desired in enhanced oil recovery. In this paper, we developed a comb micro-block hydrophobic association polymer (CBHAP). The polymer solution with high salinity showed an obvious shear thickening behavior, even if the polymer concentration was very low (1 g/L). In addition, with the increase in salinity (> 20 g/L) and temperature, shear thickening phenomenon will be more obvious. We analyzed that the unique rheological behavior was influenced by the comb micro-blocked structure and the forces transition from intramolecular to intermolecular when the curled polymer chains were stretched under shearing. In porous media, high permeability and low flow rate were beneficial to achieve the shear thickening flow. The unique property will endow CBHAP better mobility control ability than conventional polymers, especially in high permeability reservoirs or fractured reservoirs.

Optimizing Acid Fracture Design in Calcite Formations: Guidelines Using a Fully Integrated Model

Summary The performance of acid-fractured wells depends on the conductivity distribution along the acid-penetration length, which is a function of reservoir properties, treatment design, and execution. The previously published models for fractured-well performance assume constant fracture conductivity, which cannot be achieved in acid-fracturing operations. This work proposes a design optimization method where acid-fracture and reservoir models are integrated. Fracture-conductivity distribution along the fracture surface is considered in the optimization process. In the new integrated model, the acid transport and reaction are joined to the fracture-propagation and heat-transfer models. The dissolution patterns along fracture surfaces are generated, and this is converted to a conductivity distribution. To predict the fractured-well productivity, the reservoir model is built using the input reservoir properties, as well as the calculated acid-fracture geometry and conductivity distribution. The acid-fracturing parameters that lead to the optimal fracture productivity are determined with this integrated model. This method shows that there is an optimal productivity that can be obtained for a given acid treatment volume and reservoir properties. Design parameters such as flow rate, viscosity, acid concentration, acid treatment volume, and pad and overflush volumes can be selected to achieve optimal well performance. Reservoir permeability has an important impact on how acid-fracture jobs should be designed. At low-reservoir permeability, a more evenly distributed conductivity and a long acid-penetration length are preferred. This can be accomplished by injecting a retarded acid system at moderate- to high-flow rate. However, excessive fracture-height growth should be prevented by carefully designing the injection rate and viscosity. For high-permeability reservoirs, higher conductivity along a shorter acid-penetration length is targeted. This can be obtained by selecting a more-reactive acid system such as straight acid and injecting at moderate rates, or by lowering the injection rate of retarded acids. A minimum amount of pad should be used in this case. Still, the flow rate should be highly sufficient to keep the fracture open during acid injection. We also show how acid concentration and fluid stages can be designed to optimize productivity and presents a procedure for selecting the acid treatment volume. A theoretical model, which integrates acid fracturing and reservoir flow, is used to implement the guidelines on optimizing acid-fracture design parameters. In this paper we provide a scientific approach to determine acid treatment volume that yields optimal outcomes for acid fracturing.

Quantifying the role of hydrothermal alteration in creating geothermal and epithermal mineral resources: The Ohakuri ignimbrite (Taupō Volcanic Zone, New Zealand)

Hydrothermal fluids can alter the chemical and physical properties of the materials through which they pass and can therefore modify the efficiency of fluid circulation. The role of hydrothermal alteration in the development of geothermal and epithermal mineral resources, systems that require the efficient hydrothermal circulation provided by fracture networks, is investigated here from a petrophysical standpoint using samples collected from a well exposed and variably altered palaeo-hydrothermal system hosted in the Ohakuri ignimbrite deposit in the Taupō Volcanic Zone (New Zealand). Our new laboratory data show that, although quartz and adularia precipitation reduces matrix porosity and permeability, it increases the uniaxial compressive strength, Young’s modulus, and propensity for brittle behaviour. The fractures formed in highly altered rocks containing quartz and adularia are also more planar than those formed in their less altered counterparts. All of these factors combine to enhance the likelihood that a silicified rock-mass will host permeability-enhancing fractures. Indeed, the highly altered silicified rocks of the Ohakuri ignimbrite deposit are much more fractured than less altered outcrops. By contrast, smectite alteration at the margins of the hydrothermal system does not significantly increase strength or Young’s modulus, or significantly decrease permeability, and creates a relatively unfractured rock-mass. Using our new laboratory data, we provide permeability modelling that shows that the equivalent permeability of a silicified rock-mass will be higher than that of a less altered rock-mass or a rock-mass characterised by smectite alteration, the latter of which provides a low-permeability cap required for an economically viable hydrothermal resource. Our new data show, using a petrophysical approach, how hydrothermal alteration can produce rock-masses that are both suitable for geothermal energy exploitation (high-permeability reservoir and low-permeability cap) and more likely to host high-grade epithermal mineral veins, such as gold and silver (localised fluid flow).

Numerical Modeling of Gas Migration and Hydrate Formation in Heterogeneous Marine Sediments

The formation of marine gas hydrates is controlled by gas migration and accumulation from lower sediments and by the conditions of the hydrate stability zone. Permeability and porosity are important factors to evaluate the gas migration capacity and reservoir sealing capacity, and to determine the distribution of hydrates in the stable region. Based on currently available geological data from field measurements in the Shenhu area of Baiyun Sag in the northern South China Sea, numerical simulations were conducted to estimate the influence of heterogeneities in porosity and permeability on the processes of hydrate formation and accumulation. The simulation results show that: (1) The heterogeneity of the hydrate stability zone will affect the methane migration within it and influence the formation and accumulation of hydrates. This is one of the reasons for the formation of heterogeneous hydrates. (2) When the reservoir is layered heterogeneously, stratified differences in gas lateral migration and hydrate formation will occur in the sediment, and the horizontal distribution range of the hydrate in a high porosity and permeability reservoir is wider. (3) To determine the dominant enrichment area of hydrate in a reservoir, we should consider both vertical and lateral conditions of the sedimentary layer, and the spatial coupling configuration relationships among the hydrate stability region, reservoir space and gas migration and drainage conditions should be considered comprehensively. The results are helpful to further understand the rules of hydrate accumulation in the Shenhu area on the northern slope of the South China Sea, and provide some references for future hydrate exploration and the estimation of reserves.

Analysis of Test Method for Oil and Water Relative Permeability Curve in Tight Reservoirs

With the development of the international economy, the global demand for oil and gas resources has continued to increase in recent years. The development of high-permeability reservoirs has reached the middle and late stages, and resources are depleting. With the large-scale successful exploitation of tight oils in North America, low-permeability tight reservoirs have gradually become the main object of development. Compared with conventional reservoirs, tight reservoirs mainly develop nano- scale pore systems. It causes poor reservoir properties, high interlayer heterogeneity, low porosity and permeability, and generally no natural productivity in reservoirs. In tight reservoirs, the flow of oil-water phases is not affected by the scale, but also the wettability, they make the oil and water phases seepage more complicated. In this paper, the natural core of a tight reservoir in Daqing was selected. Experiments were carried out using two experimental methods: steady-state method and non-steady-state method. The characteristics of oil and water phases percolation in tight reservoirs were analyzed. The results by comparing the two experimental methods showed the steady state method is suitable for measuring the oil and water relative permeability curve of tight reservoirs.

Improving acid fracture design in dolomite formations utilizing a fully integrated acid fracture model

Acid reactivity with dolomite is more sensitive to temperature as compared to calcite formations, resulting in different dissolution profile. Acid fracture fluids are heated inside the fracture, as it flows away from the wellbore, due to the reservoir heat flux. This causes a sharp increase in dolomite reactivity, resulting in a bell-shaped conductivity profile along the fracture half-length. The productivity of such conductivity distributions will be wrongly estimated if a single average conductivity value is used. In the present research, a reservoir simulator that includes variable fracture conductivity was coupled with an integrated acid fracture model. Also, design guidelines for acid fractures in dolomite formations have been proposed.Case studies are presented, showing that in conventional acid fracture designs, the maximum dissolution in dolomite usually occurs away from the wellbore. This negatively affects productivity, as maximum conductivity is desired near the wellbore. This effect is especially significant for fracturing candidate wells in higher permeability reservoirs. This study shows that in good permeability formations, productivity can be improved by acid fractures designed at a lower injection rate. In cases where the desired injection rate is not sufficient to propagate the fracture, good productivity can be obtained by using two acid stages with different injection rates. A higher injection rate is employed to create the desired fracture dimensions, and a smaller rate used to obtain good conductivity in the near-wellbore region. In low permeability reservoirs, it is desirable to alternate injections of retarded acid systems with pad fluid to create longer acid penetration distances. The results show that, in certain conditions, designs following the proposed guidelines can result in substantial productivity improvement compared to the conventional approach.

Aridisols in the Southern Permian Basin of Lithuania: a key to understanding clay cement distribution

The change from fossil to geothermal energy supply includes the necessity to re-evaluate gas reservoirs in the Southern Permian Basin of NW Europe, as higher permeability reservoirs are needed for the exploitation of geothermal energy than natural gas. A key reservoir risk in Permian sandstones in the Southern Permian Basin is the presence of clay cement. The distribution of the clay cement is not properly understood. The negative effect can be attributed to complex grain coatings formed by tangential clay directly around the detrital grains followed by authigenic clay rim cement, both being genetically related. This study presents new results on the origin of the tangential and the authigenic clay. The Southern Permian Basin in Lithuania was a marginal area of the basin with low accommodation rates and extensive aridisol development. Here, sandstones of the Perloja Formation contain abundant clayey matrix in the form of grain and void coatings. The limited burial depth of a few hundreds of metres ensured that the original internal fabric and mineralogy of the clay coatings remained well preserved. Thin section microscopy revealed that the clay coatings are cutans that formed by post-depositional mechanical infiltration (illuviation) of suspensions of clay minerals, iron hydroxides and some clay to silt-sized quartz. Other pedogenic features are the development of nodular calcrete, rootlets, and of infiltrated clay. Aridisols were recurrently eroded by fluvial or aeolian activity causing wide-scale dispersion of siliciclastic grains with more or less complete clay cutans and also carbonate (calcrete) clasts in certain stratigraphic intervals.

Experimental Evaluation of Carbon Dots Stabilized Foam for Enhanced Oil Recovery

Foams are used as divergent fluids for conformance control in enhanced oil recovery (EOR) operations. It is created by mixing a surfactant and a gas in situ in high-permeability reservoirs (e.g., s...