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Fluid-Loss-Control Additives (FLAs) are used to maintain a consistent fluid volume within a cement slurry to ensure that the slurry performance properties remain within an acceptable range. The variability of each of these parameters (slurry performance properties) is dependent upon the water content of the slurry. If the water content is less than intended, the opposite will normally occur. The magnitude of change is directly related to the amount of fluid lost from the slurry. Because predictability of performance is typically the most important parameter in a cementing operation, considerable attention has been paid to mechanical control of slurry density during the mixing of the slurry to assure reproducibility.
Glotov, A. V. (TomskNIPIneft JSC) | Michailov, N. N. (Oil and Gas Research Institute of RAS) | Molokov, P. B. (National Research Nuclear University MEPhI) | Lopushyak, Yu. M. (Mayskoye Gold Mining Company LLC) | Shaldybin, M. V. (TomskNIPIneft JSC)
Evaluating of core saturation in case of oil source rocks of the Bazhenov formation by standard methods is not trivial task that hinders systematic measurements. An example is the existing method of distilling water in the Zaks (or Dean-Stark) apparatus, which does not allow to determine small amounts of water with high accuracy, in addition, the method is not "in-line" - it takes up to a week for one measurement. This leads to use for reserve calculation and planning mining values of oil saturation, which are not confirmed by actual data or determined on single core samples. The method was offered authors, based on combination of thermal and spectrometric techniques, let allowed measuring water saturation and oil saturation for core 12 oil fields. The results obtained indicate about significant variation in saturation by cross section of the Bazhenov formation, and the modal values of water saturation exceed those, that are usually used for reserve calculation. «Scale» factor significantly influences on the core properties, and actual values of water saturation may be higher. The degree of mobility of water in open porous space is important value. Established opinion that all water in the Bazhenov formation is associated with clays minerals is not confirmed by specially conducted researches. The dependence of water content and clayiness is linear with a high dispersion. The lowest values of water content tend to highly siliceous and carbonate rock, and the water in open voids is rather capillary-bound. The obtained values of chemically bound water released in process decomposition of minerals and transformation organic matter during heating, indicate high water content in closed pores. Studying of the features of water release in the temperature range corresponding to the decomposition (pyrolysis) of organic matter and minerals showed the presence of a large amount of water in closed pores.
Kazak, Ekaterina S. (Lomonosov Moscow State University) | Kazak, Andrey V. (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Bilek, Felix (Dresden Groundwater Research Centre)
Summary In this study, we aim to develop a new integrated solution for determining the formation water content and salinity for petrophysical characterization. The workflow includes three core components: the evaporation method (EM) with isotopic analysis, analysis of aqueous extracts, and cation exchange capacity (CEC) study. The EM serves to quickly and accurately measure the contents of both free and loosely clay-bound water. The isotopic composition confirms the origin and genesis of the formation water. Chemical analysis of aqueous extracts gives the lower limit of sodium chloride (NaCl) salinity. The CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks. A representative collection of rock samples is formed based on the petrophysical interpretation of well logs from a complex source rock of the Bazhenov Formation (BF; Western Siberia, Russia). The EM employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, and X-ray diffraction (XRD) analysis. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δO and δH. A modified alcoholic ammonium chloride [(NH4Cl)Alc] method provides the CEC and exchangeable cation concentration of the rock samples with low carbonate content. The studied rock samples had residual formation water up to 4.3 wt%, including free up to 3.9 wt% and loosely clay-bound water up to 0.96 wt%. The latter correlates well to the clay content. The estimated formation water salinity reached tens of grams per liter. At the same time, the isotopic composition confirmed the formation genesis at high depth and generally matched with that of the region's deep stratal waters. The content of chemically bound water reached 6.40 wt% and exceeded both free and loosely bound water contents. The analysis of isotopic composition proved the formation water origin. The CEC fell in the range of 1.5 to 4.73 cmol/kg and depended on the clay content. In this study, we take a qualitative step toward quantifying formation water in shale reservoirs. The research effort delivered an integrated workflow for reliable determination of formation water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs and general reservoir characterization and reserve estimation. The research novelty uses a unique suite of laboratory methods adapted for tight shale rocks holding less than 1 wt% of water.
Shi, Yu-min (Key Laboratory for Mechanics in Fluid Solid Coupling Systems, Institute of Mechanics, Chinese Academy of Sciences / School of Engineering Science, University of Chinese Academy of Sciences) | Gao, Fu-ping (Key Laboratory for Mechanics in Fluid Solid Coupling Systems, Institute of Mechanics, Chinese Academy of Sciences / School of Engineering Science, University of Chinese Academy of Sciences) | Liu, Jian-tao (Geophysical Services Division, China Oilfield Services Limited) | Zhu, You-sheng (Geophysical Services Division, China Oilfield Services Limited)
For the High-Pressure High-Temperature (HPHT) pipelines susceptible to global buckling, a reasonable risk assessment is particularly significant for their safe operation and structural integrity. The complex physical and mechanical characteristics of deep-sea sediments could bring great uncertainty to the pipe-soil interaction and the corresponding lateral buckling predictions. In this study, the physical and mechanical characteristics of undisturbed sediment samples recovered from certain deep-water locations of South China Sea are analyzed statistically, which exhibit inherent natural variability. Such statistical variability can be well quantified with the Coefficient of Variation (COV). Results indicate that the COV of mechanical properties is generally more pronounced than that of physical properties. The probability distributions of most soil parameters generally follow normal distributions by statistical hypothesis testing. Reliability analysis for the pipeline lateral buckling is then performed on the basis of analytical models by Hobbs (1984) etc. The pipe-soil friction coefficient is described by a random variable with an appropriate type of probability distribution to reflect the randomness of pipe-soil interaction. Monte Carlo simulations indicate that the probability for pipeline lateral buckling could be up to 50% compared to the deterministic method. Moreover, the COV values of the critical safe temperature, the corresponding buckle length and buckle amplitude are closely related to, but smaller than that of the basic random variable. In comparison with deterministic analyses, the present analyses may provide a beneficial insight into the lateral buckling of HPHT pipelines by considering the statistical characteristics of deep-sea sediments.
As offshore developments extend into deeper waters, the relatively high internal pressure and temperature becomes a dominant factor for the safety of deep-water exposed pipelines. Due to the seabed resistance against the pipeline thermal expansion, axial compressive force generates and accumulates along pipeline length (see Shi et al., 2019). Once the axial force reaches or exceeds the critical buckling force, the pipeline would experience lateral global buckling. Although lateral buckling is not a structural failure mode, the resulting excessive compressive force and bending moment may lead to structural failure. Hence, in the lateral buckling design procedure for exposed pipelines, first decision task is to check the susceptibility to experience buckling (DNV GL-RP-F110, 2018). If a pipeline is not susceptible to global buckling, only the axial walking check needs to be considered. Otherwise, the limit state check for the uncontrolled post-buckling would be further performed (DNV GL-ST-F101, 2017).
Jackson, Mark (University of Western Australia Fluid Sciences and Resources) | Hoskin, Ben (Oilfield Technologies Pty Ltd) | Ling, Nicholas (University of Western Australia Fluid Sciences and Resources) | Johns, Michael (University of Western Australia Fluid Sciences and Resources) | Gudimetla, Ravi (BHP Petroleum) | Conitsiotis, Christian (BHP Petroleum)
Water-oil emulsion formation is commonly observed at wellhead chokes and topsides control valves, with the impact mitigated by chemical injection. The presence of emulsions downhole in Pyrenees wells was inferred from their significant production rate impact and confirmed by the uplift observed from downhole chemical injection. The Pyrenees fields are located in the Exmouth sub-basin offshore Western Australia. Through analogy between individual Inflow Control Device (ICD) orifice elements and wellhead chokes, ICDs were suspected as the source. This paper describes experimental confirmation of emulsion formation by orifice type inflow control devices in Pyrenees field horizontal well completions and proceeds to characterise the emulsions formed. A purpose built flow rig combined Pyrenees crude oil and produced water under low shear, simulating reservoir flow conditions, before flowing through an orifice element at rates equal to peak and mid-life production. With liquid flow rate held constant, water cut was increased in 10% steps from 0 to 100% water content. A key component of the experimental system is a benchtop Nuclear Magnetic Resonance spectrometer equipped for non-invasive Pulsed Field Gradient measurement of the Droplet Size Distribution of the emulsions formed. Droplet size distribution is a fundamental fluid property that significantly impacts emulsion rheology. The heavy end component of the crude oil was characterised by a novel Enhanced Saturate Aromatic Resin and Asphaltene analysis procedure to facilitate benchmarking of Pyrenees with emulsion formation tendencies of other producing assets. This quantitative demonstration of emulsion formation by orifice type ICDs at near reservoir conditions is novel, as is observation of partial emulsification, and represents initial steps towards generalisation of models for emulsion formation and their transport properties.
Unconventional Resources (UR) are developing an upstream gathering network, a Gas Separation Plant (GSP), and transmission pipelines for a shale gas development project, based in the eastern region of the Kingdom of Saudi Arabia. The aim of these facilities is to produce nonassociated gas from several unconventional fields with minimum treatment, prior to transmitting both gas and condensate to existing facilities for further treatment. Uncertainties in subsurface and reservoir data for shale gas fields is one of the most challenging aspects of designing surface processing facilities, due to the varied behavior and properties of the production fluids, including rapid depletion in well pressure, Water Gas Ratio (WGR), and Condensate Gas Ratio (CGR). The intent is to design efficient, cost-effective facilities, which can accommodate the expected operating envelope throughout early-life, mid-life and end-life of the facilities.
This abstract will focus primarily on three optimization areas already implemented in the facilities design: (i) Gas gathering system. (ii) Dehydration and propane refrigeration. (iii) Off-gas system.
The gas gathering system has been designed to be operated in three separate phases: (i) Early Life; (ii) Mid Life; and (iii) Late Life, as the well pressures naturally decline. The selected configuration, compares with other facility designs which incorporates separate High Pressure (HP) and Low Pressure (LP) gathering systems. However, in order to minimize CAPEX, the facility has been designed in a flexible arrangement to be operated over the three different phases. Therefore, the operating pressure will be reduced and the wells choked back accordingly.
Tri-ethylene Glycol (TEG) Dehydration unit design has been optimized in the GSP by pre-cooling the process gas upstream of the unit. A small propane refrigeration system was used to chill the upstream process gas. The system reduces the TEG Regeneration equipment sizes, heating duties, and minimizes TEG losses. In addition to that, the propane refrigeration system has been further optimized by utilizing a gas-gas Heat Exchanger (HEX) upstream of the chillers to reduce the required cooling duty.
The GSP design includes an off-gas collection system which recompresses Low Pressure (LP) vent streams and recycles them back into the main process gas stream, avoiding the requirement for a LP Flare system. During the Front-End Engineering Design (FEED) stage of the project, the outlet of the off-gas system was routed to the gas transmission pipeline, to comingle with the dry gas from the TEG system. During the project EPC stage, the off-gas system was optimized by re-routing the off-gas to the Medium Pressure (MP) Separator where it is recycled back into the process. This optimization decreases the required off-gas compressor discharge pressure with associated CAPEX and OPEX reduction. Additionally, liquids separated within the off-gas system are also recycled back to the MP Separator instead of a closed drain system, which avoids venting gas that contains concentrated Benzene, Toluene, Ethylbenzene and Xylene (BTEX).
This unconventional gas development project will be developed over several phases, and this facility is part of Phase 1 development.
With conventional technique for crude oil dehydration, demulsifying agent or "Demulsifier" is used to separate oil, water and emulsion layers at a certain temperature condition. By this method, it leads to demulsifier loss in a crude oil product. The new concept of the dehydration is to recycle and reuse the demulsifer with minimal investment. With this concept, carbonate-based ionic liquids (CBILs) will be used as a demulsifier to separate emulsions and water in oil, resulting in a decrease in OPEX from demulsifier injection. In addition, CBILs represent versatile, green and easy-to-prepare chemicals. Laboratory test results show that the emulsion between oil and water is able to break within 15 minutes at 60°C which is comparable to conventional demulsifier. Moreover, the cost of CBILs is lower than conventional demulsifier. Therefore, this chemical is proved to be more attractive.
Correlations are prevalent in the geotechnical engineering practice. This paper presents a practical machine learning approach for establishing improved geotechnical correlations. In the realm of machine learning, multiple input variables of significance can be readily and coherently incorporated into the model. This approach is illustrated in the context of correlation between undrained shear strength and the combination of depth, water content, liquid limit and plastic limit. The methodology is presented in a general form to facilitate adaptation to other geotechnical correlations.
The machine learning model is created in TensorFlow which is an open source machine learning platform. A dataset which consists of 1013 groups of undrained shear strength from undrained-unconsolidated triaxial test, depth of sample, water content, liquid limit and plastic limit data are compiled. 70 % of the randomised dataset are used for training and validating the model while the remaining 30 % are used to test the performance of the model. The machine learning model consists of an artificial neural network model with one input layer, four hidden layers and one output layer. The training takes several minutes on a laptop equipped with a Graphics Processing Unit.
The classical approach would have been to correlate the undrained shear strength to liquidity index which is a combined parameter computed from water content, liquid limit and plastic limit. By comparing the predictions of the machine learning model on the test dataset against those computed based on dataset-specific correlation between undrained shear strength and liquidity index, it is evident that a significantly improved correlation is obtained using the machine learning approach.
Due to the intricacy of multi-dimensional regression analysis, classical geotechnical correlations are typically determined by method of curve-fitting with just a single independent variable. Soil, by nature, is a complex material that is characterised by multiple index properties. Therefore, it is intuitive that geotechnical correlations can be improved by incorporating multiple classification properties or measurements. The machine learning approach described in this paper, which is implemented using an open source platform and readily accessible to industry practitioners, alleviates the legacy limitation of a single independent variable leading to improved geotechnical correlations. More importantly, this machine learning approach fits in perfectly with the digitalisation initiative increasing embraced by the oil and gas industry to improve on safety, efficiency and profitability.
Li, Yanlai (China National Offshore Oil Corporation CNOOC Limited, Tianjin, China) | Su, Yanchun (China National Offshore Oil Corporation CNOOC Limited, Tianjin, China) | Yang, Wei (China National Offshore Oil Corporation CNOOC Limited, Tianjin, China) | Meng, Peng (China National Offshore Oil Corporation CNOOC Limited, Tianjin, China) | Wang, Lilei (China National Offshore Oil Corporation CNOOC Limited, Tianjin, China)
The Bohai Bay Basin is very rich in heavy oil. Generally the water flooding recovery of heavy oil reservoirs is only 18-20% in Bohai Oilfield, which has great potential for EOR. Being a mature technology in onshore oilfields, polymer flooding in Bohai Oilfield faces a serious of difficulties including choosing the best polymer injection opportunity in limited platform life, poor applicability of existing polymers and polymer preparation and production fluid treatment restricted by platform space. In recent years, several large heavy oil fields have carried out chemical flooding test. In order to solve the above problems, the early stage polymer injection development mode which breaks the limit of secondary and tertiary oil recovery was practiced to fit the service life of platform; a new kind of hydrophobic associative polymer was designed to meet the demand of viscous crude oil, high hardness water, strong shear force and large well spacing in Bohai Oilfield; a serious new facilities used for polymer instant solution and production fluid treatment was designed to fit the narrow space of platform.
The tests show that the early stage polymer injection development mode in offshore heavy oil fields has achieved good results. It effectively reduces or stabilizes the water cut and increases oil production significantly. Based on the good test results, the scale of injection test in Bohai Oilfield expands continuously. It develops from 1 injection and 5 production in a single well group to 44 injection and 171 production in three oilfields, with polymer flooding reserves reaching 144×106m3. According to statistics, in the recent 5 years, the cumulative oil production of polymer flooding has reached 5.651×106m3, and the recovery rate is increased by 3.9%, which is expected to be 8% in the future. Successful application of the technologies has significantly improved the development effect of offshore heavy oilfields. Even in the low oil price period, it has created tremendous economic value for the company. Nowadays polymer flooding has become a necessary means of stabilizing oil and controlling water in old oilfields in Bohai.
This study provides a systematic method to study the gas/water transport behavior and water retention behavior in gas shale reservoir using analytical and numerical modelling approaches. The critical water saturation determined from the relative permeability curve is regarded as the turning point between two gas production stages: Stage I and Stage II. At Stage I, the gas /water two phase flow dominates shale gas production period, while at Stage II the single gas flow and the flow of water in adsorbed phase are dominative. The improved permeability evolution model incorporates both the gas and water sorption-induced swelling strains. The permeability ratio is a time- and location-dependent parameter and its change can be divided into three stage, namely, the increase at early time, the decrease at mid-term time, and the increase at later production time. With gas depletion, gas pressure drawdown significantly dominates the evolution of permeability ratio. Continuously, the effect of sorption induced matrix shrinkage strain will become dominative with gas pressure decreases to low values. Due to the gas source supplement induced by gas desorption at Stage I, the gas production rate will temporarily increase but then will continuously decrease till to the lowest level at critical water saturation. At Stage II, the gas production rate is significantly influenced by residual water content in shale controlled by the flow of water in adsorbed phase. In addition, the effects of elastic properties (