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Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Sovizi, Javad (Baker Hughes) | Dontsov, Egor (ResFrac Corporation) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Blose, Matthew (BP America Production Company, BPx Energy Inc.) | Hailu, Thomas (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract Predicting fracture behavior is important for well placement design and for optimizing multi-well development production. This requires the use of fracturing models that are calibrated to represent field measurements. However, because hydraulic fracture models include complex physics and uncertainties and have many variables defining these, the problem of calibrating modeling results with field responses is ill-posed. There are more model variables than can be changed than field observations to constrain these. It is always possible to find a calibrated model that reproduces the field data. However, the model is not unique and multiple matching solutions exist. The objective and scope of this work is to define a workflow for constraining these solutions and obtaining a more representative model for forecasting and optimization. We used field data from a multi-pad project in the Delaware play, with actual pump schedules, frac sequence, and time delays as used in the field, for all stages and all wells. We constructed a hydraulic fracturing model using high-confidence rock properties data and calibrated the model to field stimulation treatment data varying the two model variables with highest uncertainty: tectonic strain and average leak-off coefficient, while keeping all other model variables fixed. By reducing the number of adjusting model variables for calibration, we significantly lower the potential for over-fitting. Using an ultra-fast hydraulic fracturing simulator, we solved a global optimization problem to minimize the mismatch between the ISIPs and treatment pressures measured in the field and simulated by the model, for all the stages and all wells. This workflow helps us match the dominant ISIP trends in the field data and delivers higher confidence predictions in the regional stress. However, the uncertainty in the fracture geometry is still large. We also compared these results with traditional workflows that rely on selecting representative stages for calibration to field data. Results show that our workflow defines a better global optimum that best represents the behavior of all stages on all wells, and allows us to provide higher-confidence predictions of fracturing results for subsequent pads. We then used this higher confidence model to conduct sensitivity analysis for improving the well placement in subsequent pads and compared the results of the model predictions with the actual pad results.
Abstract The application of high viscosity friction reducers (HVFRs) in unconventional plays has steadily increased over the past years, not only as alternatives to conventional friction reducers (FRs) but also as a direct replacement for the use of guar-based fluids. HVFRs demonstrate more efficient proppant transport, due to their unique rheological properties, concurrently with a high friction reduction effect allowing higher pumping rates. However, all these benefits come with few critical limitations related to frac water quality, compatibility with other additives, and static proppant suspension, which makes them very similar to conventional crosslinked gels regarding their Quality Assurance and Quality Control (QAQC) requirements at a well location during the field implementation. This paper illustrates the comprehensive laboratory efforts undertaken to evaluate different HVFR and crosslinked gel products, their successful field application supported by a robust and effective field QAQC process, and the critical importance of maintaining effective field-laboratory-field interaction/cycle to optimize the fluid design and maximize the results. Experimental studies on different products were conducted to measure the effect of frac water quality, HVFR loading, breaker loading, and compatibility with other additives used in the fluid recipe such as surfactants, scale inhibitors, and biocides. The ability of HVFR to suspend and transport proppant is not only a function of polymer loading but also highly influenced by fluid velocity as static and semi-dynamic proppant suspension tests demonstrate. Additionally, a full dynamic proppant transport test was also conducted using a multi-branched slot apparatus to simulate the flow inside a complex fracture network. Field execution followed a strict QAQC protocol including water analysis, field laboratory tests, water filtration, mixing procedure, product storage, and transport allowing direct onsite replication of the results that had been previously obtained in the laboratory. Constant communication between the field and the laboratory allowed a successful execution of several treatments in a challenging shale play in the Sichuan Region, China. These treatments achieved record proppant placements and, just as importantly, they demonstrated repeatability and consistency over time; which had not previously been attained. Laboratory testing proved critical in confirming that product segregation was occurring, even if there was no visual observation of this phenomenon, which had resulted in initial difficulties in fluid quality and reliability. The presence of constant QAQC engineering support on location was instrumental in rapidly identifying the potential root cause(s) and efficiently and correctly applying the necessary corrective actions. This paper will highlight the importance of laboratory testing, in order to design and optimize the fluid system. The paper will also demonstrate how critical the onsite QAQC is through actual examples of fluid optimization and field implementation. These two activities, although requiring a substantial resource commitment and effort, are both required to achieve successful execution.
Shareholders of Russia's second-largest gas producer, Novatek, have approved $11 billion in external financing for the Arctic LNG 2 project on which Novatek has pledged its 60% equity stake in the project as collateral. The approval came 23 April at the company's annual shareholders' meeting. In making the announcement, Novatek CEO Leonid Mikhelson said that responsibility for fundraising will be split three ways between Russia, China, and the tandem of Japan and Europe acting together. The $21-billion project, which received final investment approval in 2019, is expected to launch production in 2023 as Novatek expands its LNG exports east and west along Russia's now navigable Arctic coast. Arctic LNG 2 will reach full capacity of almost 20 mtpa in 2026, according to the company.
Xie, Jun (Petrochina Southwest Oil and Gas Field Company) | Tang, Jizhou (Harvard University) | Sun, Sijie (Harvard University) | Li, Yuwei (Northeast Petroleum University) | Song, Yi (Petrochina Southwest Oil and Gas Field Company) | Huang, Haoyong (Petrochina Southwest Oil and Gas Field Company) | Pei, Hao (Harvard University) | Zhang, Fengshou (Tongji University)
Abstract Slurry, as a proppant-laden fluid for hydraulic fracturing, is pumped into initial perforated cracks to generate a conductive pathway for hydrocarbon movement. Recently, numerous studies have been done to investigate mechanisms of proppant transport within vertical fractures. However, the distribution of proppant during stimulation becomes much more complicated if bedding planes (BPs), natural fractures (NFs) or other discontinuities pervasively distributed throughout the formation. Thus, how to capture the transport and placement mechanisms of proppant particles in the opened BPs becomes a significant issue. In this paper, we propose a closed-form continuous proppant transport model based on the conservation of total proppant volume and sedimentation of proppant particles. This model enables to integrate with the fluid flow section of a 3-D hydro-mechanical coupled fracture propagation model and then predict the distribution of proppant velocity and slurry volume fraction within a dynamic fracture network. Stokes’ law is applied to determine the sedimentation velocity. In the fracture propagation model, rock deformation is governed by the analytical solution of penny-shaped crack to determine fracture width. Fluid flow is characterized by finite differentiation scheme and then the fluid velocity is obtained. These two parameters above are inputs for the proppant transport model and both slurry viscosity and density are updated in this step. Afterwards, both fracture width and fluid velocity would be altered in the fracture model. Analysis of the proppant distribution within crossing-shaped fracture is conducted to study mechanisms of proppant transport along opened BPs. From our numerical analysis, we find that the distribution of proppant concentration is independent with the fluid viscosity, but highly dependent on the volume fraction of pumping slurry, under a given pumping pressure. Due to the difference of viscosity and proppant volume fraction at locations of upper and lower BPs, we observe that two symmetric BPs are unevenly opened, with different channel length along BP. Moreover, the width of opened upper BP is much smaller than that of opened lower BP as a result of discrepancy of proppant sedimentation. Last but not the least, a criterion of flow bed mobilization is established for dynamically tracking the sedimentation along the BP. Then the effect of different parameters (such as proppant size, proppant density, fluid viscosity, injection rate) on proppant distribution along opened BPs is also studied. Our model fully considers the proppant transport and settlement, proppant bed formation and interaction between fracture and proppant, which helps to predict the influence of proppant during fracturing treatment. Additionally, our model is also capable of dynamically tracking the settlement of proppant along opened BPs.
Abstract The description of chemical kinetics is very import to the simulation of reactive transport for enhanced oil recovery (EOR). Characterizing petroleum ignition is especially important for simulation and prediction of In-Situ Combustion (ISC). In order to model crude oil oxidation reactions accurately, an experimental workflow is introduced to obtain kinetic parameters for ISC chemical reaction models. An optimization algorithm assists to match the reaction model parameters to the experimental results, and this validated model is used to predict ignition of crude oil in porous media. Apparent activation energy is estimated from ramped temperature oxidation experiments under several heating rates, including 1.5, 2.0, 2.5, 3.0, 5, 10, 15, and 20 °C/min. These experiments are separated into a small heating rates group (1.5, 2.0, 2.5, 3.0 °/min) and large heating rates (5, 10, 15, 20 °/min). The results show that experiments with small heating rates capture the details of reaction kinetics such that the estimated activation energy is more accurate, with the validated simulation model able to make accurate predictions for this particular crude oil. After matching the kinetics parameters, we predict the ignition conditions as a function of the air flow rates and the heat loss rates. The ignition envelope indicates that the window for air flow rates to ignite the oil decreases if the heat loss rate is high. Greater heat losses require more thermal energy to be released from the reaction to overcome losses and for ignition to occur. This leads to a narrower range of ignition air flow rates due to convective heat transfer. The uncertainty quantification results provide a confidence region for the ignition envelope impacted by the threshold temperature of the ignition criterion. The novelty of this work is the description of optimized combustion reaction models with rigorous experimental verification and uncertainty quantification for reactive transport simulations.
Sinopec announced this week that production at China's largest shale-gas development has jumped 20% year-over-year. This is based on first quarter results that showed natural-gas production from the Fuling gas field in Chongqing reached a cumulative output of 1.78 Bcm, or nearly 63 Bcf. The boost comes after Sinopec brought 28 new wells on stream this year, the state-owned oil and gas producer said in an announcement. Sinopec is China's second-largest gas producer and said during its earnings call that it is aiming for an annual increase in gas output of 10% over the next 3 years. The operator produced a total of 30.2 Bcm in 2020 and is aiming for 34 Bcm this year. Sinopec's next expected milestones are 38 Bcm in 2022 and 42 Bcm in 2023.
Summary The ability of geochemistry techniques in reservoir-continuity studies has already been proved. Most of the traditional methods mainly involve analyzing nonpolar components of crude oil and overlooking polar components. Despite valuable information obtained from nonpolar components, these compounds are sometimes affected by various alterations or likely provide only a piece of the reservoir-compartmentalization puzzle. In this paper, an integrated geochemical approach that uses nonpolar (i.e., saturates and aromatics) and polar (i.e., asphaltenes) components of crude oil was performed to evaluate reservoir continuity efficiently. The Shadegan Oil Field in the Dezful Embayment in southwest Iran was investigated for reservoir-continuity studies to show the efficiency of this proposed technique. The selected interparaffin peak ratios and light hydrocarbons [the C7 oil correlation star diagram (C7CSD)] from whole-oil gas chromatography (GC) (WOGC) chromatograms were used to obtain oil fingerprints from the nonpolar fraction of crude oils. The Fourier-transform infrared (FTIR) spectroscopy of asphaltenes was applied to obtain oil fingerprints from the polar fraction of crude oils. The pairwise comparison of studied wells by each technique was summarized in a similarity matrix with green, yellow, and red colors to show connectivity, limited connectivity, and disconnectivity according to oil fingerprints. Finally, a compartmentalization model was prepared from the integrated results of different techniques considering the worst-case scenarios regarding the occurrence or absence of reservoir continuity when relying on individual methods for the studied field. Results show that the Shadegan Oil Field comprises three zones in the Asmari Reservoir and two zones in the Bangestan Reservoir. Reservoir-engineering data, including pressure data and pressure/volume/temperature (PVT), completely corroborated the obtained results from the geochemical approach. The consistency of results suggested FTIR oil fingerprinting of asphaltene as a novel and straightforward technique, which is a complementary or even alternative method with respect to previous geochemical methods.
Hou, Yanan (China University of Petroleum (Beijing)) | Peng, Yan (China University of Petroleum (Beijing) (Corresponding author) | Chen, Zhangxin (email: email@example.com)) | Liu, Yishan (University of Calgary and China University of Petroleum (Beijing) (Corresponding author) | Zhang, Guangqing (email: firstname.lastname@example.org)) | Ma, Zhixiao (China University of Petroleum (Beijing)) | Tian, Weibing (China University of Petroleum (Beijing))
Summary Pulsating hydraulic fracturing (PHF) is a promising fracturing technology for unconventional reservoirs because it could improve the hydraulic fracturing efficiency through inducing the fatigue failure of reservoir rocks. Understanding of the pressure wave propagation behavior in wellbores and fractures plays an important role in PHF optimization. In this paper, a transient flow model (TFM) was used to describe the physical process of pressure wave propagation induced by PHF, and this model was solved by the method of characteristics (MOC). Combination of the TFM and MOC was validated with experimental data. The impacts of controlling factors on the pressure wave propagation behavior were fully discussed, and these factors include the frequency of input loading, an injection mode, an injection position, and friction. More than 10,000 sets of pressure wave propagation behaviors in different scenarios were simulated, and their differences were illustrated. In addition, the generation mechanisms of different pressure wave propagation behaviors were explained by the Fourier transform theory and the vibration theory. The important finding is that there is resonance phenomenon in the propagation of the pressure wave, and the resonance frequencies are almost equal to the natural frequencies of a fluid column. As a consequence of resonance phenomenon, the amplitudes of bottomhole pressure (BHP) and fracture tip pressure will increase sharply when the input loading frequency is close to the resonance frequency and less than 5 Hz; otherwise, the resonance phenomenon will disappear. Furthermore, an injection mode can alter the resonance frequency and the amplitude and frequency of the induced pressure wave. In addition, a friction effect can significantly decrease both the resonance frequency and the resonance amplitude. These findings indicate that the optimized input loading frequency should be close to the natural frequency of a fracturing fluid in a wellbore to enhance its BHP.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: email@example.com or firstname.lastname@example.org)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.
Xiaoyan, Wang (Dagang Oilfield and Northeast Petroleum University) | Jian, Zhao (Tuha Oilfield) | Qingguo, Yin (Dagang Oilfield) | Bao, Cao (Northeast Petroleum University (Corresponding author) | Yang, Zhang (email: email@example.com)) | Fengxiang, Zhao (Dagang Oilfield) | Lidong, Zhang (Dagang Oilfield) | Haiying, Cheng (Tuha Oilfield) | Xi, Yan (Dagang Oilfield) | Song, He (Dagang Oilfield)
Summary Achieving effective results using conventional thermal recovery technology is challenging in the deep undisturbed reservoir with extra-heavy oil in the LKQ oil field. Therefore, in this study, a novel approach based on in-situ combustion huff-and-puff technology is proposed. Through physical and numerical simulations of the reservoir, the oil recovery mechanism and key injection and production parameters of early-stage ultraheavy oil were investigated, and a series of key engineering supporting technologies were developed that were confirmed to be feasible via a pilot test. The results revealed that the ultraheavy oil in the LKQ oil field could achieve oxidation combustion under a high ignition temperature of greater than 450°C, where in-situ cracking and upgrading could occur, leading to greatly decreased viscosity of ultraheavy oil and significantly improved mobility. Moreover, it could achieve higher extra-heavy-oil production combined with the energy supplement of flue gas injection. The reasonable cycles of in-situ combustion huff and puff were five cycles, with the first cycle of gas injection of 300 000 m and the gas injection volume per cycle increasing in turn. It was predicted that the incremental oil production of a single well would be 500 t in one cycle. In addition, the supporting technologies were developed, such as a coiled-tubing electric ignition system, an integrated temperature and pressure monitoring system in coiled tubing, anticorrosion cementing and completion technology with high-temperature and high-pressure thermal recovery, and anticorrosion injection-production integrated lifting technology. The proposed method was applied to a pilot test in the YS3 well in the LKQ oil field. The high-pressure ignition was achieved in the 2200-m-deep well using the coiled-tubing electric igniter. The maximum temperature tolerance of the integrated monitoring system in coiled tubing reached up to 1200°C, which provided the functions of distributed temperature and multipoint pressure measurement in the entire wellbore. The combination of Cr-P110 casing and titanium alloy tubing effectively reduced the high-temperature and high-pressure oxygen corrosion of the wellbore. The successful field test of the comprehensive supporting engineering technologies presents a new approach for effective production in deep extra-heavy-oil reservoirs.