Low Permeability Oil Reservoirs Research Articles

Fabrication of a Spontaneous Emulsification System for Low-Permeable Oil Reservoirs and Study of an Enhanced Oil Recovery Mechanism Based on the Nuclear Magnetic Resonance Method

An emulsifier that can spontaneously emulsify oil by a gentle disturbance is an ideal displacement agent for enhanced oil recovery (EOR) in low-permeability reservoirs. Herein, a novel spontaneous emulsification (SE) system with a low concentration of alkali was fabricated in this work. An optimum SE system was screened by interfacial tension (IFT) measurement; the diameter distribution and microscopic morphology of emulsions were observed by an optical microscope and multiple light scattering; the EOR mechanism was studied by nuclear magnetic resonance (NMR) and magnetic resonance imaging (MRI); and the applicability of the SE system in heterogeneous reservoirs was further explored by parallel-core flooding tests. The result showed that the ion pairs formed as a result of the electrostatic attraction of surfactant head groups between cetyltrimethylammonium bromide (CTAB) and nonylphenol polyoxyethylene ether carboxylate (SS-231), which caused the IFT of the CTAB/SS-231 system to reach the ultralow level. The synergistic effect between alkali and surfactants occurred by adding only 0.1 wt % NaOH, which greatly enhanced the capability of emulsification. As a result, the IFT of the SE system (0.4 wt % CTAB/SS-231 + 0.1 wt % NaOH, with massCTAB/massSS-231 = 3:7) could reach 2.1 × 10–3 mN/m, and the SE system could emulsify the crude oil by inverting once. The crude oil in small pores and throats could be displaced by the SE system because the in situ emulsions formed by the SE system were small enough to flow through the small pores; therefore, they exhibited a higher EOR efficiency than the weak emulsification (WE) system. In addition, the SE system showed stronger capabilities in conformance control as a result of the deformation and migration of emulsions. This work revealed the EOR mechanism of the SE system from the level of the pore structure using NMR and MRI, which is important for evaluating the production efficiency of low-permeability reservoirs. Furthermore, the low concentration of alkali (0.1%) in the SE system avoids the scale formation of low-permeability reservoirs effectively.

Enhancing Oil Recovery from Low-Permeability Reservoirs with a Thermoviscosifying Water-Soluble Polymer.

Water-soluble polymers, mainly partially hydrolyzed polyacrylamide (HPAM), have been used in the enhanced oil recovery (EOR) process. However, the poor salt tolerance, weak thermal stability and unsatisfactory injectivity impede its use in low-permeability hostile oil reservoirs. Here, we examined the adaptivity of a thermoviscosifying polymer (TVP) in comparison with HPAM for chemical EOR under simulated conditions (45 °C, 4500 mg/L salinity containing 65 mg/L Ca2+ and Mg2+) of low-permeability oil reservoirs in Daqing Oilfield. The results show that the viscosity of the 0.1% TVP solution can reach 48 mPa·s, six times that of HPAM. After 90 days of thermal aging at 45 °C, the TVP solution had 71% viscosity retention, 18% higher than that of the HPAM solution. While both polymer solutions could smoothly propagate in porous media, with permeability of around 100 milliDarcy, TVP exhibited stronger mobility reduction and permeability reduction than HPAM. After 0.7 pore volume of 0.1% polymer solution was injected, TVP achieved an incremental oil recovery factor of 13.64% after water flooding, 3.54% higher than that of HPAM under identical conditions. All these results demonstrate that TVP has great potential to be used in low-permeability oil reservoirs for chemical EOR.

Threshold pressure experiment of liquid flows through nanochannels and tight cores

Compared with low-permeability oil reservoirs, tight oil reservoirs have more nanopores, complex pore structure, and more obvious nonlinear seepage characteristics. Under the macro-scale channel flow, the influence of micro-forces is often ignored, but micro-forces of the micro-nano-scale have become the main factors affecting the flow. The micro-nano-scale flow is different from the macro-scale flow, and the flow requires the force between the fluid and the micro-nano tubes. The article conducts the threshold pressure experiment of nanochannels and cores, and results show that exists a pressure threshold under liquid flows through nanochannels and cores. The influence of the threshold pressure gradient in the micro-nanochannels is analyzed, and it is found that the nature of the fluid and the diameter of the pores affect the threshold pressure of micro the tube; core experiments prove the threshold pressure gradient exists in the core. The main factors affecting the threshold pressure gradient of the core are the permeability of the core and the nature of the experimental fluid.

Technology Focus: Oilfield Chemistry (September 2021)

As production chemists, we are all aware of the overall concepts of improved oil recovery (IOR) and enhanced oil recovery (EOR). Perhaps, though, fewer of us are aware of the different idiosyncrasies that exist within (and even between) these two broad categories of recovery and then how chemistry and chemicals can have an effect upon these processes. I would like to propose that the lines once were quite distinct between IOR and EOR: IOR was a standard waterflood operation, and EOR (from a chemist’s perspective) was the addition of chemistry to that waterflood (typically polymer or surfactant). Nowadays, the science has evolved massively to create many sub-genres of IOR and EOR. A waterflood is rarely just a waterflood anymore. We can alternate water and gas injection. We can add chemical conformance aids to direct better the flow of water. We can change the salinity of the water to promote better wettability for higher recovery factors. The list goes on. One just has to search out the number of EOR papers vs. (pretty much) every other discipline of production chemistry to see the commitment this industry still has to the research of this discipline. In recent years, the focus has tended to move away from deep-reservoir EOR to focus on near-wellbore stimulation. Interestingly, the mechanistic considerations that we make as production chemists are nearly identical in all cases, and significant synergies exist between these subdisciplines. Therefore, from the recent research published by SPE, two focused topics of IOR/EOR have arisen: the use of nanoparticles and the use of water-shutoff technologies. Nanoparticle use is gaining significant traction in the oil and gas industry, and field applications are now being reported. The area of IOR/EOR is no exception. Water shutoff is not a new technology area. However, are these established, production-sustaining IOR techniques seeing a resurgence caused by the headwinds our industry has faced during the COVID-19 pandemic? Recommended additional reading at OnePetro: www.onepetro.org. OTC 30123 - Thermal and Rheological Investigations on N,N’-Methylenebis Acrylamide Cross-Linked Polyacrylamide Nanocomposite Hydrogels for Water-Shutoff Applications by Mohan Raj Keishnan, Alfiasal University, et al. IPTC 20210 - Chemical and Mechanical Water Shutoff in Horizontal Passive ICD Wells: Experience and Lessons Learned in Giant Darcy Reservoir by Mohamed Abdel-Basset, Schlumberger, et al. SPE 203831 - Efficient Preparation of Nanostarch Particles and Mechanism of Enhanced Oil Recovery in Low-Permeability Oil Reservoirs by Lei Zhang, China University of Geosciences, et al.

Optimization of large-scale fracturing technology and improvement of development effect of hard-to-recover reservoirs

At present, the development of unconventional and low-permeability oil and gas reservoirs has become a hot spot of energy development at home and abroad. The typical feature of this kind of oil and gas reservoirs is that the reservoir permeability is very low, and certain transformation measures need to be taken before they can be put into operation. The reservoir volume transformation technology is one of the important technologies for the effective development of unconventional oil and gas reservoirs. In recent years, in order to improve the development effect of ultra-low permeability reservoir, Hailar complex fault block oilfield has carried out field application tests of volume transformation technology in different types of reservoirs year by year. By increasing the amount of fracturing fluid and fracturing sand, increasing the fracturing sweep volume and improving the reservoir seepage conditions, the effective production of the reservoir is realized. However, from the perspective of fracturing effects of different reservoirs, there will be great differences in fracturing effects under the same fracturing method. It shows that the effect of large-scale fracturing development of oil and gas reservoir is related not only to the fracturing mode, but also to the geological characteristics of the fracturing horizon. The in-depth study of the factors affecting the fracturing effect has important guiding significance for the development of low-permeability reservoirs.

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Enhanced regained permeability and fluid flowback from tight sandstone and carbonate oil reservoirs with unique flowback chemistry

AbstractLarge amounts of aqueous‐based fluids used in hydraulic fracturing of tight formations are not fully recovered immediately after treatment, resulting in increased water saturation, water blockage, clay swelling, reduced relative permeability, and long‐lasting formation damage that impedes production. To enhance flowback fluid recovery, nano‐emulsion based flowback aids were developed for oil‐bearing sandstone and carbonate formations. The flowback aids were formulated using a blend of high‐temperature stable ester‐based solvents, alcohols, and surfactants to form optically clear nano‐emulsions. All the developed flowback aids demonstrated low surface tension (22–30 mN/m) and interfacial tension (<6 mN/m), which is necessary for reducing capillary pressure. The particle size of the nano‐emulsions was found to be 5–15 nm. The flowback aids were able to prevent the formation of the emulsion with crude oil. It has been found that nano‐emulsions formulated using non‐ionic and anionic surfactants worked better for sandstone, whereas non‐ionic and cationic surfactant‐based formulations worked better for carbonate. These formulations not only provide quick aqueous fluid displacement in column tests but also greatly enhance the rate of oil flow in core flow experiments conducted with broken slickwater fracturing fluids. It was determined that in the absence of a flowback aid, the regained permeability was around 40%, whereas with flowback aids it was increased to 65%–75%. The paper demonstrates the effectiveness of flowback enhancers to quickly recover the injected aqueous fracturing fluid, thereby reducing water saturation, which in turn enhances productivity, and shows the benefit of applying chemistry for low permeability oil reservoirs.

High-Precision Numerical Simulation on the Cyclic High-Pressure Water Slug Injection in a Low-Permeability Reservoir

The paper presents a novel waterflooding technique, coupling cyclic high-pressure water slug injection with an asynchronous injection and production procedure, to address the inefficient development of low-permeability oil reservoir in Shengli Oilfield, a pilot test with 5-spot well pattern. Based on the first-hand data from the pilot test, the reservoir model is established. With an in-depth understanding of the mechanism of the novel waterflooding technique, different simulation schemes are employed to screen the best scheme to finely investigate the historical performance of the pilot test. The production characteristics of the pilot test are both qualitatively and quantitatively investigated. It is found that the novel waterflooding technique can provide pressure support within a short period. And the formation around the injector is significantly activated and deformed. Once passing the short stage of the small elastic deformation, the reservoir immediately goes through the dilation deformation accompanied with the opening of microfractures so that the reservoir properties are significantly improved, which leads to better reservoir performance. With the multicyclic dilation-recompaction geomechanical model, the impact of pressure cyclic evolution on the reservoir properties and performance under the novel waterflooding mode of cyclic high-pressure water slug injection is taken into consideration. The historical data of the pilot test is well matched. In the study, a high-precision simulation scheme for the novel waterflooding technique in low-permeability reservoirs is proposed, which provides significant technical support for further optimization of the pilot test and large-scale application of the novel waterflooding technique.

Pre-acid system for improving the hydraulic fracturing effect in low-permeability tight gas reservoir

Hydraulic fracturing is an important technical means to improve the development effect of low-permeability oil and gas reservoirs. However, for low pressure, low-permeability, tight, and high-clay sandstone gas reservoirs, conventional propped fracturing can cause serious damage to the reservoir and restrict the fracturing effect. The pre-acid fracturing technology combines acid treatment technology with sand-fracturing technology. A pre-acid system that meets special performance requirements is injected before fracturing. The pre-acid reduces the formation fracture pressure and removes clay damage. During acid flowback, the fracturing fluid is promoted to break the gel, dissolve the fracturing fluid residue and polymer filter cake, clean the supporting cracks, and effectively improve the fracturing effect. This study analyzes the process principle and technical advantages of the pre-acid fracturing technology based on the laboratory evaluation of the fracturing damage mechanism of low-permeability tight gas reservoirs. To meet the performance requirements of low-permeability tight gas reservoirs and pre-acid fracturing technology, a set of polyhydrogen acid system with long-lasting slow reactivity, low damage, and low corrosion was developed and used as the pre-fracturing acid. The acid system is mainly composed of the main agent SA601 and the auxiliary agent SA701. Then, on the basis of laboratory experiments, this acid system is used as the fracturing pre-acid to evaluate the fracturing improvement effect. The results show that the fracturing fluid system can better dissolve the fracturing fluid filter cake and remove the fracturing fluid damage.

Geochemical reactions and their influence on petrophysical properties of ultra-low permeability oil reservoirs during water and CO2 flooding

Complex geochemical reactions can occur during the water and CO2 flooding for improved oil recovery, influencing the reservoir porosity and permeability, especially for low-permeability reservoirs. Core flooding experiments can be adopted to assess this effect, but it usually takes months or even years to accomplish. In this study, scaling and geochemical reaction experiments were firstly conducted to investigate the precipitation and dissolution of the main minerals induced by water and CO2 injection, based on a typical low-permeability oil reservoir in Xinjiang Oilfield China. Secondly, reactive flow simulation models were then established, based on the experimental data, to evaluate the influence of the geochemical reactions on the porosity and permeability in the reservoir. The experimental results show that the injection water can result in severe mineral precipitation after it mixes with the original formation water, while the injected CO2 can acidize the formation water and result in the dissolution of some minerals (e.g. calcite and silicate) and precipitation of dolomite, which can change the composition of the formation water. The simulation results show that severe carbonate precipitation can occur near the injection well, resulting in a decrease in porosity and permeability after 10 years of water injection. However, the change of rock minerals induced by CO2 injection can cause a slight increase in porosity and permeability near the injector, which benefits the injection of ultra-low permeability reservoirs. Therefore, CO2 flooding is recommended for improved oil recovery.

In-situ characterization of nonlinear flow behavior of fluid in ultra-low permeability oil reservoirs

Correlating velocity-gradient relation is crucial for understanding flow behavior of fluid in low-permeability oil reservoirs. Instead of experimental approaches, this paper utilized downhole pressure data analysis for in-situ characterization of nonlinear flow behavior at low velocity. We introduced a dynamic permeability concept, which connects flow equation and nonlinear flow behavior. We then employed pseudo-linear function, piecewise function and continuous function to characterize the nonlinear flow behavior. The transient pressure type curves response ascended in the late-time flow period with consideration of nonlinear flow effect, suggesting that nonlinear flow equations can affect the characteristic of the type curves. The coefficients of approximation function are considered to be model parameters and are determined by downhole pressure analysis. Through our workflow, we can obtain a velocity-gradient relation, describing the nonlinear flow behavior of in-situ fluid. The practicality and efficiency of our new method are illustrated by comprehensive case studies. The in-situ flow behavior in reservoir scale can be characterized by normalizing multiple velocity-gradient curves derived from individual well analysis. Compared with core-flooding experiments, the proposed method is more convenient and economic to characterize flow behaviors in low-permeability oil reservoirs.

Laboratory study and field verification of a thermo-responsive water shutoff agent

For the low-pressure and low-permeability oil reservoirs, water injection development and hydraulic fracturing stimulation are essential. The ideal water flooding mode is piston-like displacement. However, due to the heterogeneity of reservoirs, most of the injected water flow to oil wells along the dominant channel (i.e., high permeability area, natural fractures, or artificial fractures), which causes the decrease of oil displacement efficiency, the premature water breakthrough of oil wells, and high water content. Hence, over a span of decades, a compelling body of work has focused on the development of water shutoff agents. According to its working mechanism, water shutoff agents were divided into selective and non-selective water shutoff agents. However, the water shutoff agents mentioned above have been tested in more than 350 wells of Changqing oilfield, and the success rate was unsatisfactory. Therefore, this study aimed to develop a thermo-responsive water shutoff agent (TRWSA) with high plugging strength and compact structure. Through a series of laboratory experiments, the key performances of TRWSA for field application were tested and evaluated. First, the initial viscosity of TRWSA was 34.5 mPa s, which could easily pass through any completion tool (e.g., screen pipe and gravel pack) and enter any size fracture. Second, the TRWSA was non-water soluble and its phase-transition characteristics were not affected by guar gum fracturing fluid. Third, the phase transformation position of TRWSA could be determined by adjusting the SA-DST dosage and the wellbore-reservoir temperature. Fourth, its plugging strength was greater than 19.1 MPa and the volume retention rate was up to 99.13%. In addition, the field application results showed that oil production increased from 0.08 m3/d to 5.37 m3/d, and water content decreased from 98.6% to 9.8%. The TRWSA was satisfactory and had a great application prospect.

Analysis of large scale fracturing effect and influencing factors in low permeability oil reservoir

H Oilfield is a complex fault field. Due to poor physical properties, it is still difficult to effectively inject wells after fracturing. In addition, the repeated fracturing effect has deteriorated year by year. Most of the blocks are generally low in production, and the oil recovery speed is less than 0.31 %. Since 2014, large-scale fracturing field tests have been carried out in H Oilfield. By analyzing the influence of various factors on fracturing effect, the grey correlation method was used to analyze the influence of various factors on oil production after fracturing. The results showed that the main factors influencing the fracturing effect in the test area were formation coefficient, porosity, oil saturation, amount of sand carrying fluid, amount of fracturing fluid, and amount of sand added. The research results can be used for reference and guidance to improve the development level of low-permeability oil fields.

Optimal Selection Method for Sweet Spots in Low-Permeability Multilayered Reservoirs

Low-permeability oil reservoirs account for more than two-thirds of China’s proven reserves, and most of them are multilayered; the traditional sweet spots focus on single-layered reservoirs. The sweet spots of low-permeability reservoirs have two meanings: the geologically superior reservoir and the beneficial development of the reservoir. In this study, a concept of reservoir stratification coefficient is proposed to evaluate the characteristics of multilayered reservoirs, and three indicators are proposed, namely, reservoir stratification coefficient, energy storage coefficient, and stratigraphic coefficient, as the indicators of sweet spots of multilayered reservoirs. The three indicators are combined into a single indicator using a weighted approach, and the sweet spots can be identified based on the combined indicator. The Xiliu A area of the North China oilfield was selected for a case study. According to the structural, sedimentary, and reservoir characteristics of the block, combined with the development and production conditions, the Sha 3 Member I oil group was selected as the study object of sweet spots of the low-permeability reservoir. The results show that the reservoir stratification coefficient, energy storage coefficient, and stratigraphic coefficient proposed in this study are effective indicators for the preferential selection of sweet spots, which can reflect the longitudinal heterogeneity, energy storage size, and flow capacity of multilayered reservoirs. After a comparative analysis with actual blocks, it was found that the results obtained using the method are consistent with the actual capacity of the reservoir. The production capacity is high. The evaluation effect is ideal, and the applicability is good. Thus, this study provides a new technical method for the evaluation of similar multilayered reservoirs. The findings of this study can help for a better understanding of the development and production conditions and optimization basis of low-permeability reservoirs.

Multi-objective optimization and experiment of nylon cord rubber in expandable packer

Nylon cord rubber has the advantages of small residual deformation and is easy to lift and lower the tubing string in low-permeability oil and gas reservoirs. However, it is associated with low-pressure resistance and poor sealing performance. To enhance the performance of nylon cord rubber, a three-dimensional numerical model of the nylon cord rubber was established and its accuracy experimentally determined. The Plackett–Burman test, the Steepest climbing test and the Response surface method were used to acquire the polynomial response surface model connecting structural parameters with bearing and sealing pressure. Using genetic algorithms, optimal structural parameters of nylon cord rubber were determined depending on field operation. The reliability of the optimized results was verified by laboratory tests. It was shown that after optimization, the bearing capacity of the expandable packer increased by 25% while the sealing performance increased by 66%. In addition, the bearing pressure was 70 MPa while the sealing pressure was 50 MPa. These measurements effectively met the on-site requirements of high-pressure and fine fracturing in low-permeability oil and gas reservoirs.

Screening and optimization of [formula omitted]-WAG injection and fish-bone well structures in low permeability reservoirs using artificial neural network

Low permeability oil reservoirs yield low production rates and recovery factors because of their low porosity, low permeability, and low oil mobility. The low production from low permeability reservoirs prohibits many reservoirs from being economically producible. For those reservoirs to be considered for production, advanced production techniques are needed to increase the recovery rates. Previous research efforts concluded that utilizing advanced well structures and Carbon Dioxide based Water Alternating Gas (CO2 -WAG) injection are the most successful techniques to improve oil production from low permeability oil reservoirs. However, evaluating the implementation of a combination of those two production techniques to a low permeability reservoir is an expensive process due to the long run time needed to acquire the results using numerical simulation. Furthermore, optimization and history matching processes for these complicated production plans require more time and high computation power.In this study, we developed a reliable Artificial Neural Network-based toolbox (ANN-Based toolbox) to evaluate, optimize and history match the implementation of CO2 -WAG injection to a reservoir including a fish-bone structure producing well in low permeability oil reservoirs. The developed ANN-Based toolbox provides the results faster than the Numerical Simulation (few minutes compared to several hours) and requires lower computational power. This speed in acquiring the results helps to study more scenarios to optimize the production schemes.The ANN toolbox is developed to perform three tasks; production forecasting, production schemes design, and history matching. The production forecasting proxies are employed as a screening and forecasting toolbox to predict the time-based production rates for the reservoir under consideration when different production schemes are applied. The production schemes prediction proxies are employed to predict the production scheme that would fulfill desired production rates. Finally, the history matching proxy is developed to update the reservoir characteristics based on the production data. The developed proxies are validated using an extensive blind testing dataset, and the results of the testing dataset are presented to validate the capabilities of the developed toolbox. Furthermore, the developed toolbox was used to optimize a CO2 -WAG design scheme for a case study reservoir from Sirri A field. The results provided by the ANN toolbox showed the capabilities of the proposed EOR technique to increase the production in Sirri field by 10%.

Adaptability Evaluation of Nitrogen Foam Flooding After Water-Flooding in Low-Permeability Light Oil Reservoirs

Adaptability Evaluation of Nitrogen Foam Flooding After Water-Flooding in Low-Permeability Light Oil Reservoirs

A Simplified Capillary Bundle Model for CO2-Alternating-Water Injection Using an Equivalent Resistance Method

CO2-alternating-water injection is an effective way of enhancing recovery for low-permeability oil reservoirs. The injection process is one of the essential issues that are facing severe challenges because of the low permeability and poor pore space connectivity. Previous researchers mentioned that water injection ability could be decreased by around 20% after the CO2-flooding; hence, it is necessary to quantify the water injectivity variation during an alternated injection process. In this paper, a CO2 convection-diffusion model is established based on the seepage law of CO2 and dissipation effect. The relationship between the width of miscible flooding and injection time is defined. Besides, an equivalent resistance method is introduced for developing a capillary bundle model for featuring an unequal diameter for CO2 water vapor alternate flooding. CO2-oil and CO2-water interactions are analyzed using the new model. The effects of oil viscosity, pore throat ratio, CO2 slug size, and equivalent permeability of the capillary bundle on water injection are analyzed. The result indicates that water injection ability increases with the rise of CO2 slug size and equivalent permeability of the capillary bundle and decreases with the increase of viscosity and pore throat ratio.

Taylor Dispersion in Nanopores during Miscible CO2 Flooding: Molecular Dynamics Study

The miscible process between carbon dioxide (CO2) and oil in nanopore multiphase flow is essential for CO2-enhanced oil recovery (CO2-EOR) techniques, especially in low permeability oil reservoirs. The interplay between diffusion and convection dominates the miscible process in CO2-EOR. The Taylor dispersion model supposes that the shear flow smears the concentration distribution in the flow direction, thus enhancing the diffusion and convection in the capillary tube. However, the nanoscale applicability of this assumption is unclear. This work simulated the multiphase flows of CO2 and dodecane in nanopores at different flow velocities by using molecular dynamics (MD) simulations to investigate the process. Mass fraction profiles along the flow direction are overestimated using the Taylor dispersion model. Fluid velocity profiles from the MD results confirm the presence of the slippage phenomenon. A comparison between miscible flow and single-phase flow shows that the slip length of miscible flow might be the average of two single-phase flows of a specific component. A modified Taylor dispersion model considering slip boundary condition is obtained using the characteristic flow velocities modified by the slip length. The modified model-produced predictions correlated with the MD results and thus can predict the miscible process of nanoscale multiphase flow in CO2-EOR techniques.

Spatial ecological risk assessment for contaminated soil in oiled fields

Soil total petroleum hydrocarbon (TPH) pollution in oil fields is a worldwide environmental problem. In particular, the dense distribution of oil wells in low-permeability oil reservoirs has caused regional pollution superposition. We proposed a feasible method for the spatial ecological assessment for soil pollution in oil fields. Typical TPH-contaminated soil in the Shengli oil field was examined according to the classification of oil well properties, including the spatial structure, distribution density, and exploitation history. Soil TPH concentrations of each oil filed site was calculated by Monte Carlo simulation. The risks were assessed according to multiple receptors and risk sources. The results indicated that the average TPH concentration was greater than 2100 mg·kg−1. The differences of TPH concentrations were mainly correlated to the exploitation period. The soil TPH content demonstrated a spatial cluster pattern according to the Anselin Local Moran’s Index (p < 0.01). The risk for wheat and earthworms showed that more than 98% of the study area was under a low risk level. However, high risk accounted for only 0.9% when bacteria was used as a bioindicator, and the composition of different risk levels was similar to that of the ecological risk assessed based on the soil quality index.