Extra-low Permeability Reservoir Research Articles

Optimization of Hydrolyzed Polyacrylamide/Chromium (III)-Acetate Gel-Plugging Process after Preflush Crosslinker in Fractured Extralow Permeability Reservoir at Moderate Temperature

SummaryHydrolyzed polyacrylamide/chromium III [HPAM/Cr (III)]-acetate gel treatment is an effective way for conformance control and water shutoff in various mature reservoirs around the world. However, it encounters severe challenges in the fractured extralow permeability reservoirs with the performance varying between success and failure when channeling caused by through-type fracture exists. The through-type fracture channel that connected injection to production is formed by the connection of hydraulic and natural fractures. This research takes the extralow permeability reservoir in the Ordos Basin as the background, and under the characterization of HPAM/Cr (III)-acetate gel, the effect of a preflush crosslinker on improving gel-plugging performance was studied via experiment, and the corresponding gel-plugging process was optimized. Experimental results showed that the preflush crosslinker could effectively improve the blocking strength and stability of HPAM/Cr (III)-acetate gel for through-type, large-opening fractures. Moreover, a high-quality “gel wall” was formed based on the preflush crosslinker; it worked as a barrier within the fracture and was the key to successfully blocking the millimeter-opening fracture. Under the experimental conditions, the optimized plugging process was as follows: The crosslinker was preflushed 24 hours in advance, and the gelant was injected in three slugs, with the volume of the first slug being 0.5 pore volume (PV). A field trial conducted in Ansai Oil Field demonstrated the potential of HPAM/Cr (III)-acetate gel and its plugging capability of optimized plugging method based on the preflush crosslinker to block through-type water channeling. This research provides valuable experimental data and theoretical guidance for conformance control and water shutoff of HPAM/Cr (III)-acetate gel treatment in fractured extralow permeability reservoirs.

An Efficient Infill Well Placement Optimization Approach for Extra-Low Permeability Reservoir

Abstract The objective of infill well placement optimization is to determine the optimal well locations that maximize the net present value (NPV). The most common method of well infilling in oil field is based on the engineer’s knowledge, which is risky. Additionally, numerous optimization techniques have been proposed to address the issues. However, locating the global optimum in a large-scale practical reservoir model is computationally expensive, even more so in the realistic extra-low permeability reservoir, where fractures are generated and underground conditions are complex. Thus, both determining well locations solely through human experience and obtaining them through traditional optimization methods have disadvantages in actual engineering applications. In this paper, we propose an infill well optimization strategy based on the divide-and-conquer principle that divides the large-scale realistic reservoir model into several types of small-scale conceptual models using human knowledge and then uses the surrogate-assisted evolutionary algorithm to obtain the infill well laws for this reservoir. The diamond inversed nine-spot well patterns are studied and summarized to provide the optimal infill well placement laws for extra-low permeability reservoirs. Additionally, the laws are implemented in W-77 actual reservoir and the oil recovery has an equivalent increase of 2.205%. The results demonstrate the proposed method’s strong engineering potential and application value, as it combines the benefits of human experience and evolutionary algorithms to determine the optimal infill well placement in a realistic extra-low permeability reservoir development scenario.

Characteristics and Genetic Mechanism of Chang Eight Low Permeability and Tight Reservoir of Triassic Yanchang Formation in Central-East Ordos Basin

In this article, the characteristics of Chang 8 reservoir of Triassic Yanchang Formation in northern Shaanxi are studied by using polarizing microscope, field emission scanning electron microscope, image particle size, X-ray diffraction analysis of clay, and constant pressure mercury intrusion. The study shows that the target layer is in a relatively stable and uniform sinking burial period after deposition, and the lithology composition in the area is relatively complex, mainly composed of debris–feldspar sandstone and feldspar sandstone, with the characteristics of fine grain and high content of interstitial material. The porosity of the reservoir is generally between 4% and 12%, with an average of 8.05%. The permeability is generally between 0.03 × 10−3 and 0.5 × 10−3 μm2, with an average of 0.16 × 10−3 μm2. Strong compaction and well-developed cementation of calcareous, siliceous, and authigenic illite are important reasons for the formation of extra-low porosity and extra-low permeability reservoirs. But at the same time, because of the protective effect of chlorite film, some residual intergranular pores are preserved, which makes the some reservoirs with relatively good physical property, forming a local relatively high-porosity and high-permeability section of the “highway.”

Experimental study on the oil production characteristics during the waterflooding of different types of reservoirs in Ordos Basin, NW China

Waterflooding experiments were conducted in micro-models (microscopic scale) and on plunger cores from low permeability, extra-low permeability and ultra-low permeability reservoirs in the Ordos Basin under different displacement pressures using the NMR techniques to find out pore-scale oil occurrence state, oil production characteristics and residual oil distribution during the process of waterflooding and analyze the effect of pore structure and displacement pressure on waterflooding efficiency. Under bound water condition, crude oil mainly occurs in medium and large pores in the low-permeability sample, while small pores and medium pores are the main distribution space of crude oil in extra-low permeability and ultra-low permeability samples. During the waterflooding, crude oil in the medium and large pores of the three types of samples are preferentially produced. With the decrease of permeability of the samples, the waterflooding front sequentially shows uniform displacement, network displacement and finger displacement, and correspondingly the oil recovery factors decrease successively. After waterflooding, the residual oil in low-permeability samples is mainly distributed in medium pores, and appears in membranous and angular dispersed phase; but that in the extra-low and ultra-low permeability samples is mainly distributed in small pores, and appears in continuous phase formed by a bypass flow and dispersed phase. The low-permeability samples have higher and stable oil displacement efficiency, while the oil displacement efficiency of the extra-low permeability and ultra-low permeability samples is lower, but increases to a certain extent with the increase of displacement pressure.

Application of Polymeric microspheres in extra low permeability reservoir in Huabei Oilfield

Aiming at the problems of low water displacement recovery effect in extra low permeability reservoir of Fault-block B10 in Huabei oilfield, the oil recovery technique of surfactant flooding under polymeric microspheres was proposed in this paper. According to the features of polymeric microspheres deep profile control technique, expansion, plugging capacity and migration ability of two samples were evaluated. On the basis of these, a polymeric microspheres matched with the B10 reservoir was selected and tested in the field. Field application indicated that average pressure elevation of each well was up to 4 MPa, corresponding wells efficiency were 88%, comprehensive water was decreased by 6.6% and cumulative incremental oil production was 3350t.Fault block B10 in Huabei Oilfield had an average porosity of 17.6% and an average permeability of 3.5×10−3μm2. It belonged to a low porosity ultra-low permeability reservoir. The surface crude oil viscosity was 90mPa.s, which belonged to ordinary heavy oil reservoir. Many years of water injection had formed a fixed water flow channel in the formation. The water injection wave and volume were not balanced, and the problem of inefficient or ineffective water injection circulation was becoming more and more prominent. At present, the comprehensive water cut had reached 90%. After surfactant flooding in some well groups, due to the serious heterogeneity of reservoir, displacement fingering was obvious and the implementation effect was poor. As a new type of deep profile control and flooding agent, polymer microspheres can form step-by-step plugging after entering the low-permeability reservoir, and greatly adjust the water flooding flow field and expand the sweep volume [1]. In order to explore the adaptability of polymer microsphere to B10 reservoir, a polymer microsphere suitable for B10 reservoir was selected by static expansion of microsphere and dynamic physical model plugging experiment of core. Field application showed that the polymer microsphere had good adaptability in B10 fault block.

Adaptability of Combined Well Pattern to Sedimentary Facies Model in Thin Interbedded, Extra-Low Permeability Reservoirs

Adaptability of Combined Well Pattern to Sedimentary Facies Model in Thin Interbedded, Extra-Low Permeability Reservoirs

Microscopic Characteristics of Oil Displacement With Different CO2 Injection Modes in Extra-Low Permeability Reservoirs

Microscopic Characteristics of Oil Displacement With Different CO2 Injection Modes in Extra-Low Permeability Reservoirs

Evaluating the energy consumption and air emissions of CO2-enhanced oil recovery in China: A partial life cycle assessment of extralow permeability reservoirs

Carbon dioxide enhanced oil recovery (CO2-EOR) can capture, transport and store CO2 emitted by high energy consumption enterprises. Therefore, the use of CO2-EOR enhances oil recovery and is also an effective means of reducing CO2 emissions. Currently, energy and environmental assessments of CO2-EOR have been rare in China. In this study, partial life cycle assessment (LCA) is used to evaluate the energy consumption and air emissions gate to grave in a CO2-EOR test station for extralow permeability reservoirs in northern China. The gate to gate of CO2-EOR defines 5 stages: transportation, liquefaction, injection, oil production and recycling. Through the analysis of these stages, the results show that producing one metric ton of crude oil gate to gate consumes 2472.56 kW hours of electricity and emits 2532.63 kilograms of CO2, 74.18 kg of SO2 and 37.38 kg of NOx. Water flooding that occurs under similar geological conditions is selected and compared with CO2-EOR for energy consumption and air emissions. In the case of producing one metric ton of crude oil, CO2-EOR gate to gate consumes more electricity than water flooding gate to gate and emits more CO2, SO2 and NOx. Compared with the amount of CO2 injection, the net CO2 emissions of CO2-EOR gate to gate to produce one metric ton of crude oil are -1675.15 kg, and the net CO2 emissions of water flooding gate to gate to produce one metric ton of crude oil are 775.83 kg. When considering energy consumption in the downstream segments of CO2-EOR, the net CO2 emissions of CO2-EOR gate to grave to produce one metric ton of crude oil are 0.53 metric tons. The results of this study provide valuable insights into the policy implications and sustainable development of CO2-EOR in China.

Comparative Analysis of CO2, N2, and Gas Mixture Injection on Asphaltene Deposition Pressure in Reservoir Conditions

CO2 and N2 injection is an effective enhanced oil recovery technology in the oilfield especially for low-permeability and extra low-permeability reservoirs. However, these processes can induce an asphaltene deposition during oil production. Asphaltene-deposition-induced formation damage is a fairly severe problem. Therefore, predicting the likelihood of asphaltene deposition in reservoir conditions is crucial. This paper presents the results of flash separation experiments used to investigate the composition of crude oil in shallow and buried-hill reservoirs. Then, PVTsim Nova is used to simulate the composition change and asphaltene deposition of crude oil. Simulation tests indicate that the content of light components C1-C4 and heavy components C36+ decrease with increasing CO2 and N2 injection volumes. However, the extraction of CO2 is significantly stronger than that of N2. In shallow reservoirs, as the CO2 injection volume increases, the deposition pressure range decreases and asphaltenes are easily deposited. Conversely, the asphaltene deposition pressure of crude oil injected with N2 is higher and will not cause serious asphaltene deposition. When the CO2-N2 injection ratio reaches 1:1, the deposition pressure range shows a significant transition. In buried-hill reservoirs, asphaltene deposition is unlikely to occur with CO2, N2, and a gas mixture injection.

The lower limit of the flowing pore throat radius in the extra-low permeability reservoir

In this paper, a method for determining the lower limit of flowing pore throat radius of the extra low permeability reservoir in the periphery of Changyuan Oil Fields is given. The capillary pressure curve is divided into linear type and concave type. The nuclear magnetic resonance (NMR) T2 spectrum is divided into 3 types: the left peak is greater than the right peak, the left peak is equal to the right one, and the left peak is smaller than the right one. The method for determining the lower limit of flowing pore throat radius is, first, converting the nuclear magnetic resonance T2 spectrum to the capillary pressure curve calculated, then fitting the capillary pressure curves measured by the constant speed mercury injection experiment and the capillary pressure curve calculated. After finding the relevant parameters, converting the horizontal axis of the NMR T2 spectra from relaxation time to pore throat radius, and the pore throat radius corresponding to the T2 cutoff value is the lower limit of the flowing pore throat radius. The lower limit of the flowing pore throat radius of the extra low permeability Fuyang Oil Reservoir in the periphery of Changyuan Oil Fields is about 0.68μm

Study on three phase foam for Enhanced Oil Recovery in extra-low permeability reservoirs

Poly (MSt-MMA) nanosphere as foam stabilizing agent was synthesized by emulsion polymerization. The three phase foam was prepared with Disodium 4-Dodecyl-2,4′-Oxydiben Zenesulfonate (DOZS) as foaming agent, Hydrolyzed Polyacrylamide (HPAM) and synthesized poly (MSt-MMA) nanospheres as the mixed foam stabilizing agents. It had outstanding foaming performance and foam stability. The optimal three phase foam system consisting of 0.12 wt% HPAM, 0.04 wt% poly (MSt-MMA) nanospheres and 0.12 wt% DOZS by orthogonal experiment, had high apparent viscosity, which showed that three components had a very good synergistic effect. The three phase foam’s temperature tolerance and salt tolerance were researched in laboratory tests. Flooding oil experiment showed that the average displacement efficiency of three phase foam system was 16.1 wt% in single core experiments and 21.7 wt% in double core experiments. Resistance coefficient of low permeability core was more than those of high permeability core, but their residual resistance coefficients were small. The results of core experiment and pilot test indicated that the three phase foam had good profile control ability and generated low damage to the low permeability layer for extra-low permeability reservoirs. Three phase foam flooding has great prospects for Enhanced Oil Recovery (EOR) in extra-low permeability reservoirs.

Advantageous Reservoir Characterization Technology in Extra Low Permeability Oil Reservoirs

This paper took extra low permeability reservoirs in Dagang Liujianfang Oilfield as an example and analyzed different types of microscopic pore structures by SEM, casting thin sections fluorescence microscope, and so on. With adoption of rate-controlled mercury penetration, NMR, and some other advanced techniques, based on evaluation parameters, namely, throat radius, volume percentage of mobile fluid, start-up pressure gradient, and clay content, the classification and assessment method of extra low permeability reservoirs was improved and the parameter boundaries of the advantageous reservoirs were established. The physical properties of reservoirs with different depth are different. Clay mineral variation range is 7.0%, and throat radius variation range is 1.81 μm, and start pressure gradient range is 0.23 MPa/m, and movable fluid percentage change range is 17.4%. The class IV reservoirs account for 9.56%, class II reservoirs account for 12.16%, and class III reservoirs account for 78.29%. According to the comparison of different development methods, class II reservoir is most suitable for waterflooding development, and class IV reservoir is most suitable for gas injection development. Taking into account the gas injection in the upper section of the reservoir, the next section of water injection development will achieve the best results.

Fractured horizontal well productivity prediction in tight oil reservoirs

Horizontal wells productivity prediction and its influence factors analysis have important meanings in development of tight oil reservoirs. The purpose of a reservoir engineering study is to maintain a stable production rate. Although a scientific development plan can benefit yield stability, it needs to match with adjustments of a well production system. Especially for extra low permeability and tight oil reservoirs, an unsteady well production system may increase difficulties of well productivity prediction. Taking a tight oil reservoir in Daqing oilfield as the research subject, on the basis of an unsteady percolation mechanics theory and the superposition principle, a numerical model is built to calculate and analyze the fractured horizontal well productivity. In order to study horizontal well productivity better, a power law exponential decline model is also used to calculate and predict well productivity. Comparing with the numerical model and the power law model, the results show that the numerical model can be used to analyze productivity influence factors, and both models have a good match with actual production data for wells with the stable production system wells. Considering a well's unsteady production system and a model's practicability, the power law model can also be used to calculate and predict horizontal wells productivity in this research oilfield. The results of this study provide a reference for horizontal well productivity calculations and prediction in similar reservoirs.

Co-optimization of CO2 sequestration and enhanced oil recovery in extra-low permeability reservoir in Shanbei

ABSTRACTThis article put forward a theoretical system, which is used to analyze co-optimization of CO2 sequestration and enhanced oil recovery by using the methods or theories including the design of experiments, numerical simulation, net present value, and the response surface methods. A CO2 flooding operation in an immiscible water-alternating-gas process of Shanbei extra-low permeability reservoir was estimated preliminarily by using the methods proposed in this article. The result shows that optimized values obtained from predicted values were in good agreement with the values obtained from the simulation model and it is possible to optimize a coupled CO2 sequestration and enhanced oil recovery project.

Application of Acrylate Copolymers in the Drilling-in Completion Fluid for Low and Extra Low Permeability Reservoirs

To address the problems of current drilling-in fluids and the particularity of formation damage in low and extra low permeability reservoirs, two kinds of additives (fluoroacrylate polymer FCS-08 and acrylate polymer LCM-08) have been developed, and a novel approach, which combined wettability reversal, water lock prevention, and film-forming, has been put forward. By adding in the FCS-08 and LCM-8, drilling-in completion fluid characterized by “rock surface properties improvement” is invented. This drilling-in fluid had better effect on reservoir protection and achieved the “zero damage” near the borehole. The daily oil production has been increased by 20%.

Threshold pressure gradient of fluid flow through multi-porous media in low and extra-low permeability reservoirs

After analyzing many studies of fluid flow theory of multi-porous media in low and extra-low permeability reservoirs and the numerical simulation of non-Darcy flow, we found that a negative flow rate occurs in the existing non-Darcy flow equation, which is unreasonable. We believe that the existing equation can only be considered as a discriminant to judging Darcy flow or non-Darcy flow, and cannot be taken as a fluid flow governing equation of multi-porous media. Our analysis of the experimental results shows that the threshold pressure gradient (TPG) of low and extra-low permeability reservoirs is excessively high, and does not conform to fluid flow through multi-porous media in the actual reservoir situation. Therefore, we present a reasonable TPG ranging from 0.006 to 0.04 MPa/m at the well depth of 1500 m and oil drainage distance of 500 m. The results of our study also indicate that the non-Darcy flow phenomenon will disappear when the TPG reaches a certain value. In addition, the TPG or non-Darcy flow in low and extra-low permeability reservoirs does not need to be considered in the productivity prediction and reservoir numerical simulation. At present, the black oil model or dual-porous media is suitable for simulating low and extra-low permeability reservoirs.

Experimental Study of the Effect of Injection Different Kinds of Water on Extra Low Permeability Reservoir

The experiment study effect of injection different kinds of water on extra low permeability reservoir of Yushulin Oilfield. In the condition of actual temperature and pressure of the reservoir, through the experimental study the effect of injection different kinds of water on extra low permeability core. Experiments include injecting clean water, injecting clean water with scale inhibitor, injecting traditional treated sewage, injecting deep treated sewage, injecting deep treated sewage with scale inhibitor. The experimental results show that: Long term injecting clean water and clean water with scale inhibitor are harmless to core; Injecting traditional treated sewage, high content of oil and impurity bring injection pressure go up, the permeability of core down sharply; Injecting deep treated (aeration + flotation (PAC+PAM) + filtration + ultra filtration (FeCl3)) sewage must be added scale inhibitor, otherwise injection pressure continuously increase, permeability of the core continuously decrease, which seriously affect injection water.

A new approach to estimating recovery factor for extra-low permeability water-flooding sandstone reservoirs

The methods of estimating recovery factor of newly added measured reserves in existing petroleum reserves standardization of China are unsuitable for sandstone oil reservoirs of extra-low permeability with water flooding, so new empirical formula method and analogous method for estimating recovery factor of the reservoirs are studied. The key parameters influencing recovery factor are permeability, formation oil viscosity, porosity, mobility and well spacing density. Based on the requirements such as longer development time, reliable reserves and available reservoir parameters, 37 sandstone oil reservoirs of extra-low permeability were selected, and 19 recovery factor models were summarized. With consideration of high multiple regression coefficient and low standard error, 4 empirical formulae suitable for reservoir of water-flood development with vertical well were established. Comparison of calculated results from the empirical formulae and calibrated recovery factors of PetroChina recently shows that the formulae match well. It is important to choose reservoir with successful pilots and/or developed in large scale as benchmark reservoirs in the analogy estimation. Based on the principle of keeping consistent of analogous method with production performance, a practical example of Chang 8 reservoir, Triassic, FX oilfield was given to illustrate the determination of recovery factor of extra-low permeability reservoir. Empirical formula method and analogous method have their advantages and disadvantages, reserves estimators should pay great attention to the reliability of data, to application condition for empirical formula method and to the avoidance of single reservoirs in analogous method.

A Study of Influential Factors of Advance Water Injection in Extra-Low Permeability Reservoir

This paper study on the permeability, start-up pressure gradient and stress sensitivity of advance water injection in extra-low permeability reservoir in Fuyu Oil layer of Daqing Oilfield. Experimental results show that the reasonable formation pressure level should be at about 120% in the advance water injection experiment, advanced water injection in the the early stage have higher oil production, the water breakthrough, earlier than synchronous water injection has certain inhibitory effect of water cut rise; Under the premise of advance water injection can overcome the start-up pressure, the lower the level of the reservoir permeability, the higher improve recovery efficiency of the proportion; permeability retention rate increase by about 22% with 5×10-3μm2 core and effectively overcome the stress sensitivity of low permeability reservoir damage; Advanced water injection can overcome stress sensitivity and restoring formation pressure, all that influence the start-up pressure gradient, which significantly reduce the start-up pressure gradient.

Study on the Optimal Design Methodology of Fracture Spacing in Low-Permeability Reservoir Horizontal Well

Threshold pressure gradient for extra-low permeability reservoir is studied experimentally. A production model is established which couples wellbore pipe flow, fracture linear flow and reservoir non-Darcy flow. The influence of bottom-hole pressure and reservoir permeability on threshold distance is performed based on the model. A fracture spacing design method is provided for different bottom-hole pressure and reservoir permeability. Results show that threshold pressure gradient increases considerably as permeability decreases when permeability is below 0.02 mD; threshold pressure gradient is relatively lower when permeability is greater than 0.1 mD; threshold pressure gradient decreases gradually and flattens when permeability lies between 0.02 mD and 0.1 mD. Simulated threshold pressure gradient of formation water is as one-third as that of crude oil. While permeability is between 0.01-0.05 mD, 0.05-0.1 mD, 0.1-0.5 mD and 0.5-1.0 mD, the optimal fracture spacing is about 9 m, 16 m; 36 m and 50 m.