Zhang, Ke (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Li, Shi (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Zhang, Shaojie (Department of Petroleum Engineering, University of North Dakota) | Pu, Hui (Department of Petroleum Engineering, University of North Dakota) | Wu, Xidao (China University of Petroleum)
The success of large-scale chemical enhanced oil recovery (EOR) such as polymer flooding and Alkaline-Surfactant-Polymer (ASP) flooding in Daqing Oilfield plays an important role in sustaining the stable high oil production rate in Daqing. In 2014, Daqing Oilfield officially implemented commercial-scale ASP flooding. It has successively conducted ASP flooding in sixteen areas. The annual crude oil production by chemical EOR in Daqing Oilfield in 2017 was almost 86 million barrels, marking the sixteenth consecutive years of more than 73.3 million barrels (~10million metric tons) of oil per year. ASP flooding produced more than 29.3 million barrels of oil in Daqing in 2018. Much experience and lessons have been learned on large-scale ASP flooding including: major factors that influence the recovery and methods to increase the recovery; measures to obtain the best economic efficiency; and how to tackle the technical challenges in ASP flooding. This paper discusses the field practices during the past five years in Daqing, including crucial application strategies, optimized design of surface facilities, field results, methods to solve technical challenges of ASP flooding, strategies to reduce cost for commercial-scale ASP technology, and future development direction of ASP flooding.
Wang, Kun (University of Calgary) | Liu, Hui (University of Calgary) | Yan, Lin (Exploration and Development Research Institute, PetroChina) | Luo, Jia (University of Calgary) | Wu, Keliu (China University of Petroleum) | Li, Jing (University of Calgary) | Chen, Fuli (Exploration and Development Research Institute, PetroChina) | Dong, Xiaohu (China University of Petroleum) | Chen, Zhangxin (University of Calgary)
In reservoir simulation, an ILU preconditioner is the most widely used preconditioner for preconditioning linear systems due to its simplicity and low computational cost. However, an ILU preconditioner sometimes is not effective enough, especially for a large-scale parallel reservoir simulation problem with a highly heterogeneous geological model. A constrained pressure residual (CPR) preconditioner is considered a more efficient one, which employs two stages of a preconditioning process: the first stage uses the Algebraic Multi-grid (AMG) method to solve a pressure system, and the second stage uses the ILU method to solve the whole system. Its disadvantage is the high computational cost of the AMG method. In order to reduce the computation costs on preconditioners and the resulting linear solvers, we have developed an adaptive preconditioning strategy  to automatically select a preconditioner between an ILU preconditioner and a CPR preconditioner or switch the ILU preconditioner to the CPR preconditioner and vice versa during a linear solution process. In this paper, the adaptive strategy is further analyzed and studied to understand its numerical performance and to choose optimal switch criteria.
He, Youwei (China University of Petroleum, Beijing and Texas A&M University) | Chai, Zhi (Texas A&M University) | Huang, Jingwei (Texas A&M University) | Li, Peng (China University of Petroleum) | Cheng, Shiqing (China University of Petroleum) | Killough, John (Texas A&M University)
Although hydraulic fracturing enables economic production from tight formations, production rates usually decline quickly and result in low hydrocarbon recovery. Moreover, it is difficult for conventional flooding methods to provide enough energy supplement in the tight formations. This paper develops an innovative approach to enhance oil recovery from tight oil reservoirs through inter-fracture injection and production, including synchronous inter-fracture injection-production (SiFIP) and asynchronous inter-fracture injection-production (AiFIP). This improves flooding performance by transforming fluid injection between different wells to between adjacent fracture stages from the same horizontal well.
The multi-stage fractured horizontal well (MFHW) comprises of recovery fractures (RFs), injection fractures (IFs) and natural fractures. In all the cases demonstrated in this work, the odd fractures and even fractures are defined as RFs and IFs respectively. Fluid is injected into IFs from injection tubing, and hydrocarbon is recovered synchronously or asynchronously through oil tubing connecting to the RFs. To quantitatively evaluate the performance of SiFIP and AiFIP in tight oil reservoirs, reservoirs are simulated based on the compartmental embedded discrete fracture model (cEDFM). The production performance of different recovery methods is compared, including primary depletion, water flooding, CO2 flooding, water Huff-n-Puff, CO2 Huff-n-Puff, SiFIP (water), SiFIP (CO2), AiFIP (water), AiFIP (CO2). The AiFIP and SiFIP achieve higher cumulative oil production than other methods. AiFIP obtained the highest cumulative oil production, which is more than two times that of primary depletion. The AiFIP (CO2) obtained almost the same cumulative oil production with SiFIP (CO2) with only 50% of CO2 injection rates, and AiFIP (water) obtained 19.3% higher cumulative oil production than SiFIP (water) with only 50% of water injection rates. Therefore, AiFIP is also a better choice when CO2 or water resource is not abundant. Sensitivity analysis is carried out to discuss the impacts of fracture and injection parameters on cumulative oil production. The fracture spacing, fracture networks, and injection rates influence the production significantly, followed by injection-production schedule and fracture length. The recommended well completion schemes of AiFIP and SiFIP methods are also provided, which is significant for the potential application of the proposed methods. This work illustrates the feasibility of SiFIP and AiFIP to enhance hydrocarbon recovery in tight reservoirs.
Wang, Kun (University of Calgary) | Luo, Jia (University of Calgary) | Yan, Lin (Exploration and Development Research Institute, PetroChina) | Wei, Yizheng (Computer Modeling Group Ltd) | Wu, Keliu (China University of Petroleum) | Li, Jing (University of Calgary) | Chen, Fuli (Exploration and Development Research Institute, PetroChina) | Dong, Xiaohu (China University of Petroleum) | Chen, Zhangxin (University of Calgary)
EOS-based phase equilibrium calculations are usually used in compositional simulation to have accurate phase behaviour. Phase equilibrium calculations include two parts: phase stability tests and phase splitting calculations. Since the conventional methods for phase equilibrium calculations need to iteratively solve strongly nonlinear equations, the computational cost spent on the phase equilibrium calculations is huge, especially for the phase stability tests. In this work, we propose artificial neural network (ANN) models to accelerate the phase flash calculations in compositional simulations. For the phase stability tests, an ANN model is built to predict the saturation pressures at given temperature and compositions, and consequently the stability can be obtained by comparing the saturation pressure with the system pressure. The prediction accuracy is more than 99% according to our numerical results. For the phase splitting calculations, another ANN model is trained to provide initial guesses for the conventional methods. With these initial guesses, the nonlinear iterations can converge much faster. The numerical results show that 90% of the computation time spent on the phase flash calculations can be saved with the application of the ANN models.
Alternating high and low concentration polymer flooding has been proposed and applied in some offshore oilfields to improve polymer flooding efficiency, but the research of pressure analysis in alternating polymer flooding reservoir is rare, this work presents a numerical pressure analysis method of three-zone composite model for formation evaluation. The type curves have seven regimes in three-zone composite model. The characteristic is the obvious upturn of pressure derivative curve in transient regime between high concentration and low concentration polymer solution. Formation parameters can be interpreted by history matching and formation evaluation can be conducted based on this model. As an important part of formation evaluation, formation damage as a result of adsorption of polymers in porous media is evaluated by comparing the interpreted permeability with the original value before polymer flooding. The field test data proves that this proposed method can accurately evaluate reservoir characteristics in alternating polymer flooding reservoirs, which emphasizes the potential application of this method in petroleum industry.
Wang, Bohong (China University of Petroleum) | Liao, Qi (China University of Petroleum) | Zheng, Jianqin (China University of Petroleum) | Yuan, Meng (China University of Petroleum) | Zhang, Haoran (China University of Petroleum) | Liang, Yongtu (China University of Petroleum)
The site selection of the facilities in oilfields is one of the important issues for surface engineers. In the progressive development of oilfields, new wells are explored and developed, and new process facilities (PFs) should be constructed to gather and process the fluid from these new wells. The emission of the PFs will affect the surrounding environment, including water sources, forests, and human settlements. Thus, the environment should be considered as one of the key aspects in the design process of facilities. Different locations of facilities in the oilfields will affect both the construction cost and environmental cost. Thus, a balance has to be found. In addition, the uncertainty of production rate of well fluid poses a great challenge to this problem. To solve the above problem, this paper provides a systematic methodology.
The objective function consists two parts: construction costs and environmental cost. The solving algorithm has involved three layers of looping programming to calculate the value of objective function. First the weather conditions are generated by the Monte Carlo method, then the second loop is for the study areas, and the third loop is for the new facilities locations. After all the loops of iterations are completed, the objective functions are calculated, and the influence of the environment can be evaluated. Finally, the best solution can be obtained.
The effectiveness of the proposed method is demonstrated through a design problem in an oilfield. The candidate locations for PFs are previously determined, and the optimal construction plan is solved by our method. The quantitative influence on the environment to these candidate locations can be evaluated. After determining the coefficient of the construction cost and the environmental cost, the best locations for the process facilities with the lowest total cost can be determined.
A multi-objective model for the site selection of process facilities in oilfields is proposed, which has not been done by existing literatures. The construction cost and surrounding environment are both considered in the model. This work has the potential to serve as a decision-support tool for surface engineers in oilfields.
Unconventional oil and gas resources such as shale gas, shale oil, CBM, tight gas and oil have attracted more and more attention worldwide in recent years. However, most of the formations of unconventional oil and gas are suffering from poor geological condition, thus the resources can not be developed without fracturing stimulation. Conventional hydraulic fracturing usually consumes a huge amount of water and also leads to the pollutions of surface water and even residential water. In addition, the formation damage caused by incomplete gel breaking, adsorption of polymers, clay expansion and water blocking are still not fully eliminated.
Thus, in this work, ultra-dry CO2 foam stabilized by graphene oxide (GO) were explored to get a fracturing fluid characterized by low water consumption, environmental friendliness, high efficiency and low formation damage. The foam quality of fracturing fluid in the study was higher than 90%, thus the water consumption of fracturing fluid was lower than 10% of total volume. The foam stability, rheology and dynamic filtration were studied by using a large-scale fracturing fluid test device.
The results showed that the stability and thermal adaptability of ultra-dry CO2 foam were enhanced by the addition of graphene oxide. The interfacial dilatational viscoelastic modulus of CO2/liquid was increased when the graphene oxide was used with saponin, implying that the bubble film interface became solid-like; The ultra-dry CO2 foam enhanced by the graphene oxide showed a shear thinning behavior. The effective viscosity of ultra-dry CO2 foam was increased by adding graphene oxide and its viscosity was higher than 50 mPa·s at a shear rate of 100s-1; Moreover, compared to pure surfactant foam, the filtration control performance of ultra-dry CO2 foam was also enhanced by graphene oxide. At a filtration pressure difference of 3.5MPa, the filtration coefficient of ultra-dry CO2 foam was decreased significantly by the addition of graphene oxide. Although the core damage caused by foam with graphene oxide was slightly higher than that of pure surfactant foam, the permeability damage was still below 10%, implying that the foam as a fracturing fluid is relatively clean to formation.
Ultra-dry CO2 foam fracturing fluid stabilized by graphene oxide provides a new high-performance fracturing system for unconventional oil and gas at water-deficient area. This study will be beneficial to fracturing applications characterized by low water consumption, environmental friendliness, high efficiency and low formation damage.
Lu, Mingjing (China University of Petroleum, Colorado School of Mines) | Su, Yuliang (China University of Petroleum) | Wang, Wendong (China University of Petroleum) | Zhang, Ge (Xianhe Oil producing Plant, Shengli Oilfield, Sinopec)
Refracturing treatment are performed since stimulation effect won't last for entire life. Screening wells for refracturing needs a systematic analysis of huge amounts of data. With literature review, it is obviously that there are many factors controlling the success of refracturing and factors may vary in different oilfields. Proper factors and data processing are the primary principle in candidate selection. The Integrated Multiple Parameters (IMP) method is presented to provide assists in selecting candidate wells.
After deeply researching over 200 restimulated wells, all factors thought to be related with success of refracturing are listed and analyzed, results show that single factor may have great influence on restimulation but no significant patterns can be obtained since too many factors making things complicated. The IMP method proposes five parameters which are all integrated by those single factors. It is emphasized that all parameters have physical or engineering meanings which makes it easier to quantify their correlation in refracturing. Besides, all the parameters are dimensionless which makes it easier for using in mathematical models and statistical analysis.
The five dimensionless parameters are developed considering the most important aspects of candidate wells selection which are showed as followed: fracture reorientation, well completion, reservoir depletion, production decline, oil-water well connectivity. Parameters are calculated for all the restimulated wells to dig into their correlation with the outcomes of refracturing. A simple decision model is built to help with screening wells for refracturing. Results shows that it is more executable to evaluate and predict the success of refracturing with these dimensionless parameters. Fracture reorientation parameter is the primary one to be considered since it leads to fracture reorientation which brings significant production increment. Then two types of potential wells are picked: (a) wells with dissatisfied initial well completion, low production decline rate and high oil-water connectivity parameter; (b) wells with satisfied initial well completion, high well completion parameter, low production decline parameter, reservoir depletion parameter and low oil-water connectivity parameter for wells that are not easy for fracture reorientation. Wells selected are proved to be refracturing potential which verify the reliability and accuracy of IMP method.
The IMP method is an improved approach integrating most of the important factors which makes candidate selection much more predictable and it succeeds in screening out more than 80% of the potential wells in field test. Also, it can be applied widely in different oilfields since all the parameters are dimensionless. By combining with some mathematical methods such as neural networks, it can even predict increment of the restimulation treatment.
Mi, Lidong (Sinopec Petroleum Exploration and Production Research Institute) | Yan, Bicheng (China University of Petroleum) | Liu, Qianjun (Texas A&M University) | Ren, Zongxiao (China University of Petroleum)
The fracture description plays an important role in shale gas well production performance prediction, late production refracturing design and infill well trajectory design. Based on the development and geological parameters of Fuling shale gas field, the enhanced discrete fracture network (EDFN) numerical simulator is used to study the influence of fracture length, total fracture length, stage spacing and relative position of fractures on the contribution ratio of fracture stage. According to the relationship among JY46-3HF gas production profile, gas production contribution ratio and fracture characteristic parameters, a fracture network model is established. The simulation results of gas production contribution ratio of each fracture stage are highly consistent with the measured data. The research results show that: the contribution ratio of gas production in each fracture stage is positively related to the total cumulative fracture length, and the fracture spacing and relative position of fractures affect the contribution ratio of fracture stage to shale gas well by the size of matrix area controlled by fracture.
Liu, Junyi (Shengli Petroleum Engineering Corporation Limited of SINOPEC) | Guo, Baoyu (Shengli Petroleum Engineering Corporation Limited of SINOPEC) | Qiu, Zhengsong (China University of Petroleum)
With the promotion of oil and gas development around the world, the exploration scope has been gradually extended to complicated geological reservoirs, such as deep or ultra-deep, unconventional, deep-water reservoirs, and lost circulation and wellbore instability have been becoming the most serious problems, which puts forward higher requirements on the drilling fluid technology. In order to solve these technical problems, the wellbore strengthening mechanism, tight fracture plugging methods and simulation experimental method for drilling fluids were studied respectively in this paper. Firstly, the wellbore strengthening mechanism of the stress cage method that improves wellbore pressure containment was firstly investigated based on ABAQUS finite element modeling analysis. It was found that wellbore pressure containment could be improved by enhancing plugging performance of drilling fluids to plug and prop natural or induced fractures to eliminate fracture propagation and increase hoop stress. The key performance of loss prevention materials has been proved to play a prominent role to achieve wellbore strengthening effect and strengthen the wellbore. According to the basic principle of "force-chain" in granular matter mechanics, the key fine technical indices were proposed to evaluate the particle strength, particle resiliency and surface friction of loss prevention materials. Meanwhile, the corresponding physical model of tight fracture plugging zones was established to reveal the tight fracture plugging mechanism at micro scale and the optimization method of tight plugging drilling fluids was also put forward, and it was concluded that using reasonable particle type, particle size distribution and concentration control, rigid particles, resilient particles and fibers were synergized to plug fractures, so as to form tight pressure containment plugging zones with a strong force chain network and greatly improve the wellbore pressure containment. The novel experimental apparatus for evaluation and dynamic simulation on the plugging characteristics of drilling fluids was developed, which could simulate the loss and plugging process of fractures with different openings under different formation pressures and temperatures.