Ultra-low Permeability Reservoirs Research Articles

CO2-responsive gel particles and wormlike micelles coupling system for controlling CO2 breakthrough in ultra-low permeability reservoirs

CO2 flooding in ultra-low permeability reservoirs is an effective means to boost oil production, while the complex fractures formed by fracturing in the initial development stage induce severe CO2 channeling. Therefore, a CO2-responsive coupling system, which coupled CO2-responsive gel particles (CRPGP) with CO2-responsive wormlike micelles (CTWM) was prepared to restrain CO2 breakthrough. To testify the EOR capacity during CO2 flooding of the responsive coupling system, the interaction between CRPGP and CTWM, and responsiveness of coupling system was investigated, followed by core flooding and rock slab flooding experiments. Experiment results showed that after the coupling system was exposed with CO2, the particle size of CRPGP increased, spherical micelles of CTWM transformed to wormlike micelles, CRPGP and CTWM were integrated through hydrophobic association among wormlike micelles and hydrophobic chains in CRPGP, and the coupling system’s apparent viscosity increased from 10.4 mPa·s to 2339 mPa·s. Moreover, 0.5 pore volume (PV) CO2-responsive coupling system injection and further CO2 flooding could dramatically boost oil production in fractured cores and rock slabs, which was primarily ascribed to the aggrandizement of sweeping volume resulting from the plugging effect of CRPGP and mobility ratio improvement of the coupling system. Compared with single slug plugging of fractures, multi-stage regulation of fractures could establish a higher-pressure gradient, and more crude oil in the matrix was activated with enhanced oil recovery (EOR) of 22.8%. All the experimental results demonstrated that the CO2-responsive coupling system has great EOR capacity during CO2 flooding, which provided novel insights for ultra-low permeability reservoirs EOR technology that incorporated with CO2 resource utilization and storage.

Mussel-inspired hydrogel particles with selective adhesion characteristics for applications in reservoir fracture control

The complex fractures in low permeability and ultra-low permeability reservoirs may serve as dominant channels, resulting in the channeling of injection water and extremely low sweep efficiency. Polyacrylamide hydrogel particles as fracture control agents can effectively plug and adjust channeling pathways. However, the adhesion between the hydrogel particles and the rock wall is weak, restraining the long-term control effect. In this work, the developed mussel hydrogel particles with selective adhesion properties exhibited excellent reservoir adaptability (96 °C, 4.7 × 104 mg/L). The hydrogel particles can maintain a uniform dispersion during the injection process; they can adhere to the fracture wall in the reservoir environment. Furthermore, the adhesion mechanisms of mussel-inspired hydrogel particles on the fracture wall with different wettability and roughness are elucidated using atomic force microscopy. By showing stronger adhesion to the hydrophilic and neutral-wet surfaces than to the hydrophobic surfaces, mussel-inspired hydrogel particles can selectively control the water-wet channeling pathways. The fractured core model experiment and scanning electron microscopy results show that mussel-inspired adhesive hydrogel particles can withstand the water flushing and maintain stable adhesion to the fracture wall to guarantee long-term control effect, exhibit better flow control effect than ordinary hydrogel particles. This work can help better understand the characteristics of the interaction between the hydrogel particles and the fracture wall, providing guidance for the development of efficient fracture control agents.

Numerical Simulation of Ultra-Low Permeability Reservoirs: Progress and Challenges

Numerical Simulation of Ultra-Low Permeability Reservoirs: Progress and Challenges

Injectivity and plugging characteristics of CO2-responsive gel particles for enhanced oil recovery in fractured ultra-low permeability reservoirs

Although CO2-responsive gel particles (CRGP) injection appears to be a viable strategy for delaying CO2 breakthrough in fractured ultra-low permeability reservoirs, few studies have been conducted to thoroughly evaluate the injectivity and plugging characteristics of CRGP. In the present work, the swelling kinetics of the CRGP at various temperatures and salinities were first characterized through the change in CRGP volume. The rheology properties of CRGP dispersion solution were then evaluated. And then, taking the resistance coefficient, residual resistance coefficient and plugging rate as indexes, the effect of matching coefficient, injection rate, and injection concentration on CRGP injectivity and plugging characteristics was investigated using simulated artificial fractures. Finally, the empirical correlations of injectivity and plugging characteristics parameters were established. According to experimental result, the equilibrium swelling ratio of CRGP was greater than 40-fold at varied salinity conditions. The shear-thinning capabilities of the CRGP dispersion solution, as well as its favorable storage modulus, endowed CRGP with favorable in-depth migration and plugging properties. In addition, in terms of fracture plugging by CRGP, the plugging ratio of CRGP in fractures was higher than 90% when the matching coefficient ranged from 1.0 to 2.0, the injection rate was less than 0.5 mL/min, and CRGP concentration was larger than 3000 mg/L. The acquired empirical relationships were expected to guide the selection of CRGP size, injection concentration, and injection rate for fracture plugging.

Experimental study on CO2 capture by using n-butylamine to plug the gas channeling to enhanced oil recovery

The national policy of peak carbon dioxide emission and carbon neutrality has pointed out the technological direction for the development of the petroleum industry in China. In order to efficiently utilize CO2 gas source to enhance oil recovery, n-butylamine is taken as the plugging channeling agent for experiment study to plug the produced channeling-path during the process of CO2 flooding in ultra-low permeability reservoir. The contents of the experiment included three parts: reaction mechanism of n-butylamine with CO2, evaluation of the injection performance of n-butylamine, and the extent of enhanced oil recovery after plugging the gas channeling by using n-butylamine. Reaction product of n-butylamine and CO2 is white solid, which is a type of organic urea so that it can be used to plug the gas channeling. N-butylamine has a good injection performance after adding protecting slug on the condition of high temperature. 80% of the whole volume of core can be spread after injecting 0.3 PV of n-butylamine. During plugging and displacement experiment of heterogeneous cores, oil recovery can be greatly enhanced by 25–30% after injecting n-butylamine. Experimental results show that it can provide a new train of thought for the gas injection development of fractured, heterogeneous and ultra-low permeability reservoirs by using n-butylamine to plug the high permeability area.

Port-Opening Falloff Test: A Complementary Test to Diagnostic Fracture Injection Test

Summary Conventional fracture injection/falloff tests, such as minifrac or diagnostic fracture injection test (DFIT), are commonly used to characterize shale and tight reservoirs. For ultralow-permeability reservoirs, a reliable DFIT requires a long falloff period after a short injection period. A long falloff observation period of weeks or months is often not economically viable. In addition, the recent economic downturn requires operators to seek cost-effective alternatives to further optimize expenditures. An alternative to a DFIT is a port-opening falloff test (POFOT). Many horizontal completions use a pressure-activated sleeve in the toe of the well to provide formation access after the casing integrity test. Most sleeves open at a pressure in excess of the formation breakdown pressure, after which the wellbore pressure declines toward reservoir pressure. This study first introduces the concept of the POFOT as a novel physical test. A new test method must demonstrate that it accesses the formation of interest and that the data obtained are applicable. A workflow is developed to demonstrate this and is applied to falloff data from POFOTs conducted in five horizontal wells completed in five formations. The results show that the fluid leaving the port is highly likely to break down both the cement sheath and the matrix and create a fracture which then closes. Observation of the well pressure after port opening resembles that from a DFIT. However, without a fixed-duration and constant-rate injection period, there is no accepted method to apply. Nevertheless, both qualitative and quantitative analyses of the falloff data provide a good estimation of reservoir pressure with a reasonable approximation of fracture closure when compared with the estimates from DFIT analysis from offset wells. The key challenges in parameter estimation, besides the development of an appropriate analysis method, are short falloff data and noisy early-time data due to wellbore resonance (WBR), low-resolution gauges, and change in sampling frequency.

Characteristics of Carboniferous Volcanic Reservoirs in Beisantai Oilfield, Junggar Basin

In recent years, petroleum exploration in the Carboniferous volcanic rock reservoirs in the Junggar Basin has been the focus of important petroleum energy development in western China. The lithologic identification of volcanic rock reservoirs seriously restricts the accuracy of reservoir prediction and affects the success rate of oil exploration. Different types of volcanic rocks have different petrological characteristics and mineral assemblages, especially affected by the depositional environment. The volcanic rocks in different regions have their own uniqueness. This paper takes the Carboniferous volcanic reservoirs in Xiquan block, Beisantai Oilfield, Junggar Basin as the research target. Through a large number of core observations, casting slices, scanning electron microscopy, and X-ray diffraction methods, the Carboniferous volcanic rocks are analyzed. The petrology, pore characteristics, physical properties, and diagenetic evolution history of the reservoir are analyzed. The study shows that the volcanic facies in the Xiquan block can be divided into explosive facies, overflow facies, and volcanic sedimentary facies, among which the explosive facies is subdivided into empty subfacies (volcanic breccia-breccia tuff combination) and thermal base wave subfacies (tuff). The lithology of the reservoir is pyroclastic rock and volcanic lava, belonging to medium-porous and ultralow permeability reservoirs, and the storage space can be divided into three types: primary pores, secondary pores, and fractures. The lithology of key exploration is breccia tuff, followed by breccia tuff and volcanic breccia.

Study on Stress Sensitivity of Ultra-Low Permeability Sandstone Reservoir Considering Starting Pressure Gradient

When studying the influence of nonlinear seepage on the water flooding development of ultra-low permeability reservoirs, it is difficult to accurately characterize the nonlinear seepage state of ultra-low permeability reservoirs using conventional reservoir numerical simulation methods. A large number of field development and tests in the oil fields show that there are indeed starting pressure gradients and stress sensitivity effects in ultra-low permeability sandstone reservoirs. In this study, taking the tight sandstone of the Chang 6 Member in the Yanchang Formation as an example, the rock displacement vector was utilized to equivalently characterize the stress-sensitive effect of the reservoir based on a novel numerical simulation software tNavigator. Furthermore, the starting pressure gradient and the feasibility of a new stress-sensitive equivalent characterization method were verified combining the poroelastic media physics equations. In addition, we systematically studied the impact of stress-sensitive effects on oil well productivity under the influence of starting pressure gradient and considering petrophysical properties. The results show that the existence of the starting pressure gradient can improve the stress sensitivity of the matrix reservoir. Considering the starting pressure gradient, when the rock shear modulus is 14.29 GPa, the cumulative oil production decreases by 4.1%; when the rock shear modulus is 11.36 GPa, the cumulative oil production decreases by 11.2%. Finally, a numerical simulation was conducted with Block B in the Zhouwan-Wugucheng area, and the model can accurately predict the reservoir stress sensitivity based on the starting pressure gradient. When both the starting pressure gradient and stress sensitivity are considered, the crude oil recovery degree of the target layer decreases by 11.7%; when only the starting pressure gradient is considered, the crude oil recovery degree decreases by 8.8%; and when only the stress sensitivity is considered, the crude oil recovery degree decreases by 0.5%.

Horizontal well spacing optimization and gas injection simulation for the ultra-low-permeability Yongjin reservoir

Optimal spacing for vertical wells can be effectively predicted with several published methods, but methods suitable for assessing the proper horizontal well spacing are rare. This work proposes a method for calculating the optimal horizontal well spacing for an ultra-low permeability reservoir – the Yongjin reservoir in the Juggar Basin, northwestern China. The result shows that a spacing of 640 m is the most economical for the development of the reservoir. To better develop the reservoir, simulation approaches are used and a new model is built based on the calculated well spacing. Since the reservoir has an ultra-low permeability, gas injection is regarded as the preferred enhanced oil recovery (EOR) method. Injection of different gases including carbon dioxide, methane, nitrogen and mixed gas are modelled. The results show that carbon dioxide injection is the most efficient and economical for the development of the reservoir. However, if the reservoir produces enough methane, reinjecting methane is even better than injecting carbon dioxide.

Experimental study on CO2/Water flooding mechanism and oil recovery in ultralow - Permeability sandstone with online LF-NMR

The investigation of the mechanism of CO2/water flooding in ultralow-permeability oil reservoir is critical to the enhanced oil recovery. In this study, a series of core flooding experiments in pore and pore-fracture cores subjected to different in situ stresses was conducted, and online LF-NMR technology was employed to dynamically monitor the multiphase flow and pore-fracture behavior. The results show that the percolation pore dominates the volumetric sweep efficiency, the capillary pressure caused by sandstone wettability controls the oil recovery in adsorption pore, and viscosity fingering and thief channeling mainly occurred in migration pore. The oil recovery is primarily contributed by the percolation pore and migration pore in CO2 flooding, and all pores averagely contribute to the oil recovery in water flooding. In addition, the oil recovery in the pore core decreased with the increase of the in situ stress (15–35 MPa) in CO2/water flooding. Compared with the increase of pore-fracture core oil recovery responding to the increased in situ stress in water flooding, the highest pore-fracture core oil recovery presented at 25 MPa followed by 35 MPa and 15 MPa in CO2 flooding. The oil saturated in fracture and fracture-connected pore was firstly displaced, and the evolved heterogeneous morphology of the residual oil was characterized by the increased fractal dimension from 1.5 to 1.7 in CO2 flooding and 1.78 to 1.82 in water flooding responding to the increased in situ stress. The pore core oil recovery rate in CO2 flooding is about 10 times than that in water flooding. The peak value of oil recovery presented at 25 MPa for CO2/water flooding, and the fracture influence is more obvious in water flooding. The findings provide significant guidance to the engineering practice of enhanced oil recovery in ultralow-permeability reservoir.

Study on the optimization of injection modes and injection parameters for natural gas in ultra-low permeability reservoir

The heavy gas breakthrough is a serious problem when developing the ultra-low permeability reservoir by natural gas, one available way to deal with this difficulty is to adjust the injection mode, such as the water alternating gas (WAG) injection and the intermittent gas (IG) injection. In order to slow down the gas breakthrough and to enhance oil displacement efficiency in ultra-low permeability reservoir better, the injection modes are compared and the injection parameters are optimized. Based on the ultra-low permeability core experiments, the WAG flooding and the IG flooding after gas fingering are simulated. The displacement efficiencies and the injection differential pressures of these two injection modes are compared. And the suitable injection mode in ultra-low permeability reservoir is confirmed. Furthermore, the experiments with the selected injection mode for several flooding rounds and different flooding periods are made, and the optimized injection parameters are achieved. The results show that both the WAG injection and the IG injection can slow down the gas breakthrough and improve the oil displacement efficiency. The oil displacement efficiency improvement of WAG injection and the IG injection is close, but the pressure of WAG injection is much higher than the one of IG injection. The IG injection can be confirmed as the optimized injection mode in the ultra-low permeability reservoir after gas fingering as the pressure requirement. The economic IG flooding round is 7 at most as the oil displacement efficiency stops improving till the flooding round increases to 7. The optimized IG flooding period after gas breakthrough in ultra-low permeability reservoir is 6 h under the differential pressure of 2MPa limited by the dissolving ability of natural gas.

An Approach for Predicting the Effective Stress Field in Low-Permeability Reservoirs Based on Reservoir-Geomechanics Coupling

Low-permeability reservoirs are important to the future growth of oil and gas reserves and production in China. Predicting the effective stress, σe, in reservoirs is vitally important due to its considerable impact on reservoir development through hydraulic fracturing. This paper presents methods for predicting the σe field in ultralow-permeability reservoirs through reservoir–geomechanics coupling, which involve the simulation and coupling of the tectonic stress σ and pore pressure Pp fields based on three-dimensional (3D) geological models. First, 3D geological models were constructed based on basic data for the oilfield where the reservoir of interest is located. Then, finite element and finite difference simulations were performed to construct the σ and Pp fields, respectively, in the reservoir. Different types of initial σe were coupled based on 3D geological models. Subsequently, a dynamic σe field in the reservoir was established based on oilfield production data in conjunction with the transformation, optimization, and coupling of specific grid property parameters obtained from different numerical methods. Finally, the proposed methods were tested on real-world data acquired from well area X in an oilfield in Shaanxi Province, China. The results show that the proposed methods can be used to establish the σ and Pp fields in a reservoir based on 3D geological models combined with different numerical methods, and subsequently predict the σe value in the reservoir.

Study of thermally-induced enhancement in nanopores, microcracks, porosity and permeability of rocks from different ultra-low permeability reservoirs

Improving permeability is the crucial mechanism for further enhancing oil and gas recovery of ultra-low permeability reservoirs. To investigate the temperature sensitivity and stress sensitivity of permeability under an actual reservoir condition, heating treatment and real-time measurement of pulse-decay gas permeability (PDP) of cores collected from three different ultra-low permeability reservoirs were conducted in our self-developed high-temperature pseudo-triaxial core holder. To clarify the intrinsic relationship between the microstructure development and porosity-permeability enhancement, stereo light microscope (SLM) observation, computerized tomography (CT) scan and nuclear magnetic resonance (NMR) test were used to quantitatively characterize the dynamic variations in thermal cracks, nanopores and porosity. Based on the lithology analysis and thermal analysis, the primary mechanisms of nanopore evolution and thermal cracking for different ultra-low permeability rocks were analyzed in detail. The experimental results show that the permeability of Chang 8 ultra-low permeability sandstone and Longmaxi shale cores only increased by about one order of magnitude above the threshold temperature of 500 °C, while the permeability of Jimsar shale cores increased significantly by two orders of magnitude above the threshold temperature of 300 °C. Above their threshold temperatures, the permeability showed stronger stress sensitivity. The SLM observation and CT scan revealed that thermal cracks propagated rapidly above the threshold temperatures, which resulted in a substantial increase in temperature sensitivity and stress sensitivity of permeability. NMR test shows that the porosity of ultra-low permeability cores performed an increasing trend as the temperature rose. However, the nanopore structure in Chang 8 ultra-low permeability sandstone monotonously developed toward larger micron-sized pores, while the Longmaxi shale and Jimsar shale eventually re-evolved into smaller nanopores. We found that kerogen pyrolysis was the most critical mechanism leading to the microstructure, porosity and permeability enhancement in organic-rich shale. For organic-poor ultra-low permeability sandstone and shale, the quartz phase transition from α to β was considered as the key reaction for the thermal cracking and permeability improvement. By comparison, heating treatment has a higher thermal stimulation potential in shale cores from medium-to-low maturity shale oil reservoirs.

Experimental and Numerical Simulation Study on the Influence of Fracture Distribution on Gas Channeling in Ultralow-Permeability Reservoirs

AbstractFracture development in ultralow-permeability reservoirs results in gas channeling and lower oil recovery during CO2 flooding. In this study, the physical properties of a light oil-CO2 syst...

Prediction Method of Well Pattern Infilling Effect in Ultra-low Permeability Reservoir of X Oilfield

In this paper, firstly, the introduction of well pattern infill in ultra-low permeability reservoir is analyzed in detail, and then combined with the change law of well pattern infill in ultra-low permeability reservoir and the prediction process of well pattern infill in ultra-low permeability reservoir, the prediction results of well pattern infill in ultra-low permeability reservoir are summarized.

Quantitative characterization of pore size and structural features in ultra-low permeability reservoirs based on X-ray computed tomography

The pore structure of ultra-low permeability sandstone (0.1 mD < K < 1 mD) is complex and has high heterogeneity, which leads to great challenges in reservoir characterization and effective evaluation. To study the effect of the heterogeneity of ultra-low permeability sandstone on permeability, a digital core model was established using X-ray computer tomography (CT) technology. Then a three-dimensional pore network model (PNM) in core samples was created using the “maximum ball method” algorithm. Finally, the geometric topology features of ultra-low permeability reservoirs were quantitatively characterized. According to the physical properties and test results of samples, the porosity distribution of targeted area ranged between 5.92% and 10.08%, and the permeability distribution range was 0.145 mD–0.75 mD, which was typical for an ultra-low permeability reservoir. The distribution of pore throat radii ranged from 0.27 μm to 1.29 μm, the shape factor was 0.04–0.06, the disconnected pores of the four samples made up between 16.89% and 58.71% of all pores, and the fractal dimension fluctuated between 1.05 and 1.5. Plane porosity also showed certain fractal characteristics. Correlation analysis showed that the disconnected isolated pores and the micron-scale pore throat radii of the reservoir sandstone were the main factors resulting in ultra-low permeability. The above-mentioned quantitative characterization parameters can be subsequently used to conduct microscopic seepage simulation studies of such reservoirs. • Build digital core based on CT scanning system. • Extract the core pore network model, and render the pore pressure, throat flowrate, and electricity conductivity. • A digital core pore structure evaluation method for Utral-low permeability sandstones was developed.

Research on the Technology of Profile Control and Flooding in JY Oilfield to Stabilize Production

JY oilfield is mainly an ultra-low permeability reservoir with low reservoir permeability. As the permeability decreases, the starting pressure gradient rises sharply, and the establishment of an effective displacement pressure system is slow. The main reservoir has entered the medium water-cut development stage. On the plane, water flooding intrudes along the dominant channels such as fractures and high-permeability strips, resulting in plane contradictions; on the profile, the production degree decreases, and the injection-production profile is unbalanced. In this paper, through the study of reservoir physical properties, water flooding and control and flooding mechanism and the implementation of fine profile control and flooding on a large scale, the well selection conditions of different reservoirs are obtained, and differentiated countermeasures are formulated. Four optimizations of injection mode to ensure continuous improvement of injection effect and economic benefits.

Evaluation and Potential Analysis of Fracture Network Fracturing in Oil Production X Plant

The oilfields developed by our factory are mainly ultra-low permeability reservoirs, and the problems of non-injection and non-production are prominent. When conventional oil well fracturing is used, there are problems such as insufficient water injection energy, low oil increase rate after fracturing, and short validity period, and it is difficult to achieve benefit management. To this end, since 2013, while controlling the under-injected wells, the application of fracture network fracturing has been gradually increased, and a total of 116 wells have been fractured. The contribution reached 4.13%, and the annual mitigation comprehensive decrease contribution was 3.62%.

Practice and cognition of effective water-flooding development mode in Gaotaizi block of ultra-low permeability reservoir

During nearly 25 years of water injection development in Gaotaizi reservoir of LHP oilfield, due to poor reservoir physical properties, poor adaptability of well pattern and difficulty in establishing effective displacement between oil and water Wells, linear water injection, infill adjustment and refracturing tests have been carried out successively. Although certain effects have been seen, the effects are short and unsatisfactory. In this paper, the microscopic pore structure, sensitivity and seepage characteristics of ultra-low permeability high platform reservoir are studied through core laboratory experiments. New technology of nonlinear test and low permeable physical simulation experiment, the research on the rules of the nonlinear characteristics of the reservoir fluid and the characteristics of movable oil through research has been clear about the dragon bubble oilfield high effective displacement distance platform layer, and the new fracturing technology and the development of the technology to adjust the organic combination, the displacement between well and well past into displacement between Wells and joint network, explore the ultra-low permeability reservoir to improve the single well production, new ways to improve the development effect, with the types of low permeability oilfield development effectively.

Numerical Simulation of Liquid-Solid Coupling in Multi-Angle Fractures in Pressure-Sensitive Reservoirs

This study clarifies the seepage characteristics of complex fractured pressure-sensitive reservoirs, and addresses a common technological problem, that is the alteration of the permeability degree of the reservoir bed (known to be responsible for changes in the direction and velocity of fluid flows between wells). On the basis of a new pressure-sensitive equation that considers the fracture directional pressure-sensitive effect, an oil-gas-water three-phase seepage mathematical model is introduced, which can be applied to pressure-sensitive, full-tensor permeability, ultralow-permeability reservoirs with fracture-induced anisotropy. Accordingly, numerical simulations are conducted to explore the seepage laws for ultralow-permeability reservoirs. The results show that element patterns have the highest recovery percentage under a fracture angle of 45°. Accounting for the pressure-sensitive effect produces a decrease in the recovery percentage. Several patterns are considered: inverted five- seven- and nine-spot patterns and a cross-row well pattern. Finally, two strategies are introduced to counteract the rotation of the direction of the principal permeability due to the fracture directional pressure-sensitive effect.