SPE's publication for the Projects, Facilities, and Construction (PFC) technical discipline, Oil and Gas Facilities (OGF), has recently launched a monthly section which will feature synopses of editor-picked SPE technical papers on PFC topics. OGF Selection Editor Gerald Verbeek will pick three papers each month that are then synopsized by SPE editorial staff and published on the OGF website. Verbeek was previously the executive editor for peer-reviewed papers in OGF and was recognized as "A Peer Apart" honoree for peer-review of more than 100 technical papers. He has picked Corrosion and Scaling for the first selection, a topic that affects all involved in oil and gas facilities. "Early in my career I spent about a year as a corrosion engineer to learn the fundamentals, only to discover that without keeping scaling and corrosion in mind, it is impossible to a be a good facilities engineer," said Verbeek in his introductory article about the new section.
Cheng, Zhilin (State Key Laboratory of Petroleum Resources and Engineering in China University of Petroleum) | Ning, Zhengfu (State Key Laboratory of Petroleum Resources and Engineering in China University of Petroleum) | Wang, Qing (State Key Laboratory of Petroleum Resources and Engineering in China University of Petroleum) | Li, Mingqi (State Key Laboratory of Petroleum Resources and Engineering in China University of Petroleum) | Sui, Weibo (State Key Laboratory of Petroleum Resources and Engineering in China University of Petroleum)
As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Surfactants induce spontaneous imbibition of water into oil-wet porous media by wettability alteration and interfacial-tension (IFT) reduction. Although the dependence of imbibition on wettability alteration is well-understood, the role of IFT is not as clear. This is partly because, at low IFT values, most water/oil/amphiphile(s) mixtures form emulsions and/or microemulsions, suggesting that the imbibition is accompanied by a phase change, which has been neglected or incorrectly accounted for in previous studies. In this paper, spontaneous displacement of oil from oil-wet porous media by microemulsion-forming surfactants is investigated through simulations and the results are compared with existing experimental data for low-permeability cores with different aspect ratios and permeabilities. Microemulsion viscosity and oil contact angles, with and without surfactant, were measured to better initialize and constrain the simulation model. Results show that with such processes, the imbibition rate and the oil recovery scale differently with core dimensions. Specifically, the rate of imbibition is faster in cores with larger diameter and height, but the recovery factor is smaller when the core aspect ratio deviates considerably from unity. With regard to the mechanism of water uptake, our results suggest, for the first time, that (i) microemulsion formation (i.e., fluid/fluid interface phenomenon) is fast and favored over the wettability alteration (i.e., rock-surface phenomenon) in short times; (ii) a complete wettability transition from an oil-wet to a mixed microemulsion-wet and surfactant-wet state always occurs at ultralow IFT; (iii) wettability alteration causes a more uniform imbibition profile along the core but creates a more diffused imbibition front; and (iv) total emulsification is a strong assumption and fails to describe the dynamics and the scaling of imbibition. Wettability alteration affects the imbibition dynamics locally by changing the composition path, and at a distance by changing the flow behavior. Simulations predict that even though water is not initially present, it forms inside the core. The implications of these results for optimizing the design of low-IFT imbibition are discussed.
Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.
Fracturing operations consume relatively large amounts of fresh or groundwater, especially in the area of unconventional resources where multi-stage fracturing is required to obtain an economical production rate and improve recovery. In an attempt to conserve groundwater, treated sewage effluent (TSE) has been evaluated and optimized for fracturing treatments to provide the required transport property for the proppant and not induce formation damage by maintaining compatibility with formation brine. Extensive laboratory work has been conducted including viscosity measurements, compatibility testing, and a microbial study to optimize an TSE-based fracturing fluid for unconventional operations. Based on laboratory recommendations, the TSE-based fracturing fluid has been applied successfully on well-A.
Twenty stages of unconventional proppant fracture stimulation utilizing the Plug and Perf (P-n-P) technique across the carbonate source rock have been applied successfully. Two base fluids, freshwater and TSE, were used to evaluate the effectiveness of TSE as a substitute for the freshwater in unconventional fracturing operations. Each water was used in 10 stages. The post-fracturing production results of well-A showed comparable results with the offset wells treated only with freshwater-based fracturing fluids. The pressure logging tests (PLT) conducted on this well confirmed that contribution of intervals treated with TSE-based fracturing fluid was comparable with those treated with fresh water-based fracturing fluid. There was no evidence of scaling issues during the flowback period for both fluid systems. Microbial evaluation of water samples collected during the flowback of well-A showed no presence of bacteria in these samples. This paper will discuss the laboratory work and the field application of TSE-based fracturing fluid.
The water invasion may induce a loss in hydrocarbon mobility, called water blocking.
Liang, Tianbo (China University of Petroleum, Beijing and University of Texas at Austin) | Luo, Xiao (University of Texas at Austin) | Nguyen, Quoc (University of Texas at Austin) | DiCarlo, David A. (University of Texas at Austin)
Fracturing-fluid invasion into the rock matrix can generate water block that potentially reduces hydrocarbon production, especially in low-permeability reservoirs. Here, we experimentally investigate the dynamics of water block under different flow scenarios (i.e., without shut-ins) and rock permeabilities through multiple coreflood experiments. A computed-tomography (CT) scanner is used to obtain the saturation profile within the core throughout the experiment, while the overall hydrocarbon productivity is measured from the overall pressure drop across the core.
On the basis of the saturation and pressure measurements, we interpret the potential physical mechanism regarding the productivity reduction from water block and its self-mitigation facilitated by the capillary imbibition. Our interpretation also matches the observed scaling with rock permeability and the optimal shut-in time.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing) | Gu, Yuanyuan (China University of Petroleum, Beijing)
Alkali/surfactant/polymer (ASP) flooding is one of the most-promising enhanced-oil-recovery (EOR) technologies. Strong alkali (NaOH) was used in early field tests mainly because of its stronger emulsification ability and wider surfactant range, which can meet the requirements of ultralow interfacial tension (IFT). However, subsequent field tests indicated that the advantages of a strong alkali did not outweigh the disadvantages caused by serious scaling and production-capacity loss. Although a critical comparison of strong alkali ASP (SASP) and weak alkali ASP (WASP) on the basis of field tests is quite difficult and complex, considering the small differences in reservoir characteristics, injected fluid, and operational changes, the two completed field tests in Daqing provided us with valuable and important information.
The petrophysical features of the two field tests were similar. The well spacings and well patterns of the two field tests were critically the same, and the same screening standards and design ideas were followed. The incremental recoveries of WASP and SASP were nearly the same, while WASP had a higher peak oil production than SASP after the injection took effect. WASP was proved to have less liquid-producing-capacity loss than SASP. The emulsification effects of WASP were weaker than those of SASP, which also lowered the difficulty and cost of the treatment of the emulsified fluid. The chromatographic separation was different in the two pilot tests, in which WASP had alleviated chromatographic separation. Breakthrough of the polymer occurred before the alkali followed by the surfactant, and this occurred at 0.06 pore volumes (PV) for SASP but was delayed until 0.13 PV for the WASP flooding. The scaling of SASP was much-more severe than that of WASP, leading to a much-higher treatment cost. The economic performances of the two tests, which are of vital importance in a low-oil-price era, were quite different, and WASP had much-better performance than SASP. The input/output ratios of WASP in B-2-X and SASP in B-1-DD were 1:3.7 and 1:2.3, respectively. The returns on investment (ROIs) of WASP in B-2-X and SASP in B-1-DD were 19.1 and 12.9%, respectively, whereas the financial internal rates of return (FIRRs) after tax were 22.3 and 18.0%, respectively. The average FIRR of local oil-industry projects is 12%. Field tests indicated that WASP is both technically and economically better than SASP under the conditions in the Daqing oil field.
Deposits on surfaces in water - bearing systems, also known as ”fouling,” can lead to substantial losses in the performance of industrial processes as well as a decrease in product quality and asset life. Early detection and reduction of such deposits can, to a considerable extent, avoid such losses. However, most of the surfaces that become fouled, for example, in process water transport pipes, membrane systems, power plants, food and beverage industries to name a few, are difficult to access and the analysis of the water phase do not reveal the extent of the deposits. Furthermore, it is of interest to distinguish between microbiological and nonmicrobiological deposits. Although they occur together, different counter measures are necessary. Therefore, sensors are required that indicate the development of surface fouling in real time, non-destructively, in situ and can discriminate between abiotic and biotic based deposits. A new and novel sensor has been developed that provides said discriminate detection by utilizing conventional heat transfer reduction sensory coupled with ultrasonic detection of materials on the same surface concurrently. The technical aspects of the design, operation, and application will be discussed in the paper. Real time graphical detection followed by automated reduction control runs will also be presented as well as revealing if the deposit is biotic or abiotic.
One of the main causes of performance loss, quality and runnability problems in industrial systems is related to contaminants and deposits. These deposits are composed of inorganic, organic and / or microbial matter, respectively. Most of the deposits contain various or even all types of these contaminants and form complex matrices. Of these, microbiological contaminations, also named biofouling, are one of the biggest issues and risks in water bearing industrial systems. They cannot only cause deposits that impact the function and efficiency of the systems. They often are the cause for health risks (e.g., Legionella). Fouling can be generalized into four forms, inorganic, suspended solids, organic, and microbiological. Of these forms of fouling, it is only inorganic crystallization fouling that does not lead to the worst form of corrosion, namely localized. This type of corrosion eventually transitions into high pitting penetration rates that drastically reduce the asset life.
The majority of the fouling which occurs in aqueous systems are detected indirectly by means of reduced process side throughput, increased time to get to operating temperature and or pressure, pressure drop, approach temperature increase, or the use of extensive instrumentation to calculate ”at that time” heat exchange U-coefficients and or cleanliness factors. Under certain circumstances, some of these methods are not sufficiently accurate unless normalized. Or the measurements taken have not been corrected for cooling water or process flow changes, shear stress change and bulk cooling water change or surface temperature changes. There may be a large lag time to foulant detection which can lead to foulant aging and dehydration to a point of being irreversible fouled, whereby chemistry and chemical adjustment in the water side environment would not provide cleansing of the surface and maintain a clean state. An example would be the comparative time for a side stream annular heat transfer test section to detect fouling of a well instrumented utility surface condenser, wherein they were both operated at the same surface temperature and shear stress (velocity corrected for the geometry) on the same cooling water.4 The steam surface condenser heat transfer surface area for 175 MW would be 150,000 ft2 (13,935 × 106 mm2) would require a large quantity of foulant coverage to be detected compared to the annular test section which has 0.05 ft2 (4645 mm2) of foulant detection surface.