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Geothermal energy refers to the heat stored in the subsurface that can be extracted by producing the hot fluids (water and/or steam) in contact with the hot formation. A major issue that may restrict the extraction of geothermal energy is precipitation of mineral scales which can occur within the reservoir, inside the wellbore, or surface facilities. The objective of this paper is to find the most efficient scale treatment strategy to prevent mineral scaling.
Continuous injection of chemical scale inhibitor (SI) downhole in the production well, is the most common method to prevent mineral scale in geothermal plants. This method although effective does not protect the near-wellbore area, where the highest pressure drop is expected. To address this issue, two methods will be studied, bullheading the production well with SI, commonly known as squeeze treatment, and injecting SI in the injection well. Optimum designs for both methods were identified considering different levels of SI adsorption, and also permeability variation in fractured and non-fractured formations.
As expected, the volume of SI required in continuous injection in producer was lower than the other two methods. However, in cases where the highest risk of precipitation is in the near-wellbore area or it is below the continuous injection point, it is necessary to apply one of the suggested methods. While the squeeze treatment protects only the formation around the producer well, treatments deployed in injector wells will protect the whole system and this extra protection may offset the extra volume of chemical necessary. The application of SI in injector well was studied in both continuous and batch mode with different injection frequencies. It was shown in continuous injection that even though less SI volume is used, the SI breakthrough time in producer can be so long that a series of squeeze treatments might be required to protect the well. The simulation results showed that in high adsorption formations, squeeze treatment is more efficient than deploying SI in the injector well. However, in cases of low adsorption and fractured reservoirs, the scenario commonly found in geothermal plants, SI injection at the injector is more optimal.
Two different scale treatment methodologies were studied in geothermal wells, including squeeze treatment in producer and SI injection in the injector and the results were compared with the continuous SI injection in producer, which is the most current treatment in geothermal wells. It was illustrated in fractured geothermal reservoirs with relatively low levels of adsorption, that SI injection in the injector is the most optimum treatment that can effectively protect the whole plant from scaling.
The current trend of the oil and gas market is focused on the efficient use of natural resources, observing safety standards, and causing the minimum environmental impact. Under this premise, new oil reservoirs in the Gulf of Mexico follow this trend in operation and production; therefore, it is necessary to study in detail the processes to comply with these standards to become a leader for future installations.
The proposal for this paper is to discuss technical aspects of the process design used for a "Production, Drilling, Utilities, and Quarters" (PDUQ) facility located at the southeast basin of the Gulf of Mexico. Specifically, the challenges associated with the handling and disposal of NGLs.
The process systems were designed based on the well composition and the PVT analysis.
While the gas is compressed in different compression stages, the natural gas heavier compounds are condensed due to the intrinsic hydrocarbon’s nature, forming NGL; this is vaporized at the storage tanks, and then sent either to the flare or back to the VRU, wasting energy. Also, heavier gas components would condense into the pipeline, and consequently, the pressure drop would increase, demanding an increase of pigging operation’s frequency.
The base case study has considered mixing the NGL with the sales gas, giving, as a result, the accumulation of liquids in the sales gas pipeline. For such reason, to avoid potential operational problems, two cases study for handling and stabilizing NGL were developed to analyze the potential use of NGL to increase oil production and improve its API gravity.
Case 1-Transferring produced NGL to oil train, consists of mixing the NGLs in the intermediate pressure separation stage to capture the heavier compounds, increasing the oil production and improving its API gravity.
Case 2-Stripping NGL to increase gas production, develops a process to handle and stabilize the NGLs, and then to mix them with the crude oil.
From both cases, additional oil production, better API gravity, and reduction of liquids in the sales gas were obtained. The results indicate that the strategy selected for Case 1 produces a higher increase in oil production and further improves its API gravity, however the power and duty requirements are higher. Additionally, the export gas quality is improved, and the pressure drop in sales gas pipeline is reduced; therefore, lower frequency on pigging operations is required.
A preliminary economic assessment is developed considering CAPEX, OPEX, ROI, Net present value, and investment efficiency. Based on this assessment, Case 1 is found to be the most profitable solution.
Chen, Rongqiang (Texas A&M University) | Xue, Xu (Texas A&M University) | Park, Jaeyoung (Texas A&M University) | Yao, Changqing (Texas A&M University) | Chen, Hongquan (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University) | King, Michael J. (Texas A&M University) | Hennings, Peter (University of Texas Bureau of Economic Geology) | Dommisse, Robin (University of Texas Bureau of Economic Geology)
A series of earthquakes was recorded along a mapped fault system near Azle, Texas, in 2013. To identify the mechanism of seismicity, geologic, production/injection, and seismicity data are gathered to build a detailed simulation model with coupled fluid flow and geomechanics to model fluid injection/production and the potential onset of seismicity. Sensitivity studies for a broad range of reservoir and geomechanical parameters are performed to identify the influential parameters for injection wellhead pressure and earthquake data. A Pareto-based multiobjective history matching is performed using these influential parameters. The calibrated results are used to identify the controlling mechanisms for seismicity in the Azle area, North Texas, and their relationship to hydrocarbon production and fluid injection in the vicinity.
Geomechanical interaction has a significant impact on seismicity in the Azle area. Unbalanced loading created by the difference in the net fluid injection and production on different sides of the fault seems to generate accumulation of plastic strain change, likely resulting in the onset of seismicity. Previous studies ignore fluid withdrawal from gas production. Thus, they seem to have significantly underestimated the fluid withdrawal rates, almost by an order of magnitude. The equivalent bottomhole-voidage fluid rate used in this study suggests a drop in history-matched reservoir pore pressure that is consistent with the observed tubinghead pressure trends. Pore pressure increases may not fully explain the seismicity near the Azle area. Instead, geomechanical effects and strain propagation to the basement appear to be the dominant mechanisms. The low fault cohesion and minimum effective horizontal stress obtained from history matching confirm that the faults must be near or at the critically stressed state before the initiation of fluid production/injection. A sensitivity analysis indicates that the minimum effective horizontal stress and fracture gradient play a critical role in the potential risk for seismicity related to fluid injection/production. A streamline flow pattern further shows that there is no fluid movement in the basement formation and the unbalanced loading from different sides of the fault is more likely the controlling mechanism for seismicity.
Downhole magnetic surveys have been most commonly applied in highly magnetized igneous rocks, which have usually been studied within pure geoscience, especially beneath the ocean floor. These rocks preserve the direction of the Earth's field at the time of their formation (i.e., the prevailing magnetic field is "frozen" in the rocks as they solidify, giving them a strong natural remnant magnetization). A primary application has been to identify points in time at which the Earth's magnetic field has undergone a polarity reversal. These reversals have been dated globally (e.g., isotopically in the case of volcanic series or by correlation with biostratigraphy in the case of volcaniclastics) and have given rise to a geomagnetic polarity time scale (GPTS) that is based on laboratory measurements. This, in turn, has allowed dates to be assigned to a given magnetozone that is bounded by reversal phenomena.
This paper describes a methodology to improve facies model robustness, by a systematic integration of well data ("hard" data) and outcrop analog studies ("smooth" data), both implemented as conditioning data in alternative numerical methods. The methodology presented is illustrated by a case study of a fluvial reservoir analog in the Triassic of the Lodeve basin (France).
On this example, most of reservoir grids are populated by kriging-based stochastic algorithms, supported by geostatistical tools controlling lateral continuity, vertical organization, or simple facies organization. If these tools are sufficient to handle simple environments with smooth facies transitions, all are deeply affected by sampling, giving a skewed representation of sedimentological model and consequently, a skewed numerical model. Moreover, these statistics-based methods are generally inefficient to represent complex fluvial systems. If well data and geostatistical tools are necessary to elaborate a robust conceptual model, a secondary constrain must be used in parallel to better handle characteristics of depositional system.
The methodology developed here is reviewing the fundamental steps of facies modeling process: data analysis, conceptual model elaboration coupled with a "back to outcrop" process and finally, the numerical implementation and it associated quality control procedures. This study is supported by an exhaustive dataset, with 6 drillholes including one cored (42m), conventional welllog data (6), GeoRadar profiles (10 lines), CCAL (>150 samples) and supported by a full outcropping cliff of 200m length. The systematic data review allow to define which facies can be identified at well, how these facies are vertically stacked in the well and how they evolve laterally. These observations help to harden a conceptual sedimentological model able to predict the facies partitionning enhanced by hydraulic mechanisms. To fill the gap between concept elaboration and facies modeling implementation, a "back to outcrop" is fundamental to provide critical elements, directly impacting the robustness of geological models. This includes (but not limited to) geobodies dimension, interaction, preservation, at an intermediate scale between wells (<1m) and seismic (>50m). Finally, these observations will be implemented as external constrain in a concept-based algorithm (nested Boolean, Multi-point statistic), to capture more precisely the rules governing the depositional model.
The final critical step consists in discussing the strengths, limitations and uncertainties associated to these alternative methods. Indeed, the back-to-outcrop process acts as an absolute quality control procedure, highlighting where algorithms or methods are not sufficiently constrained to capture the depositional model. The observations extracted during this process allow a continuous improvement, with the final objective to improve drastically the geological model robustness, and it associated forecasts.
Bin Ishaq, Wala (ADNOC Sour Gas) | Al Darmaki, Fatima (ADNOC Sour Gas) | Lucas, Noel (ADNOC Sour Gas) | Al Mansoori, Mohamed (ADNOC Sour Gas) | Deville De Periere, Matthieu (Badley Ashton and Associates Ltd) | Foote, Alexander (Badley Ashton and Associates Ltd) | Bertouche, Meriem (Badley Ashton and Associates Ltd) | Durlet, Christophe (Laboratoire Biogeosciences)
In the onshore sector of the United Arab Emirates, the Lower Arab D Member (Kimmeridgian) typically encompasses a thick succession of rather homogeneous low-energy mid-ramp carbonate mudstones interbedded with minor storm-induced cm-scale skeletal-rich floatstones. Within these deposits, the pore volume is dominated by locally abundant matrix-hosted micropores, along with variably abundant open to partially cemented fractures, primary intraparticle macropores and rare moulds and vugs. As a result of this variably developed pore system, measured porosity varies from poor to very good, while permeability changes from extremely poor to rarely good. Detailed petrographic observations (thin-sections, SEM) carried out within six cored wells in a sour gas reservoir highlight that the variations in reservoir properties are primarily linked to the micron-scale variations in the micritic fabric. Indeed, anhedral compact micrites with coalescent intercrystalline contacts are associated with very small and poorly connected micropores, while polyhedral to subrounded micrites with facial to subpunctic intercrystalline contacts show locally well-developed micropores and therefore better reservoir potential. δ18O and δ13C isotope measurements do not discriminate both micritic fabrics, indicating a recrystallisation of the matrix within shallow burial conditions. However, bulk XRF measurements, and especially SiO2, Al2O3 and Fe2O3 content indicate that poorly porous anhedral compact micrite host more insoluble material and have been prone to a greater compaction compared to porous polyhedral micrites. Log-derived elastic properties, including Young's Modulus (YME) along with porosity data, have been used in two wells to explore the potential relationship between micritic fabric, porosity, permeability and elastic properties. With the evolution of micritic fabric from anhedral compact to polyhedral / subrounded, Young's Modulus decreases with increasing porosity, indicating a decrease in the overall stiffness of the rock. Based on these two learning wells, specific porosity and YME cut-offs have been identified to discriminate the various micrite fabrics. Those cut-offs have been successfully tested in four other wells used as a blind test for the vertical prediction of the micritic fabrics, in which accurate predictions reached up to 90%. Following these results, porosity and YME cut-offs have been used to produce the first model of the distribution of the various micritic fabrics at the field-scale. These results have a fundamental impact on how sedimentologically homogenous microporous limestones can be described and predicted at the well and field-scales, especially in the context of exploring tight carbonate plays associated with intrashelf basins.
In carbonates, predicting permeability values for gridded reservoir models is very challenging as it involves both the difficult characterization of a very heterogeneous medium, the uncertain extrapolation far from well data, and the up-scaling concern. The quantification of effective permeability for model gridblocks using small scale data from plug measurements or log interpretation is a recurrent concern since the change of support for permeability has proved to be definitively non linear. When a well test interpretation is available, it gives the evolution of the permeability in the vicinity of the wells for a volume much larger than the volumes characterized by cores and logs. In that case, the consistency has to be found between the transient pressure analysis-derived large scale equivalent permeability and the small scale permeability issued from conventional core analysis or log interpretation. It is known that the upscaling can be expressed as some power average of the permeability distribution, and that an analytical formula relates the horizontal permeability in the volume investigated by the well test and the original small-scale permeability distribution in this volume. However, the relation between the upscaling law and the permeability structures is usually documented for a few number of structures, leading to recurrent problems when large scale permeability has to be extrapolated outside the volume explored by the well test. A new formulation of the power averaging coefficient has been proposed, which relates the power averaging coefficient to the geostatistical description of the permeability structures, the direction of the flow, and the volume for which the equivalent permeability is computed. The new methodology has been applied to the Buissonniere field laboratory, a site from the ALBION R&D Project. Thanks to a characterization at an unusual scale, the integration of geological, petrophysical, geophysical and pressure transient data has successfully validated the use of this new formulation.
In carbonates, the geological facies is a key driver for populating reservoir models with petrophysical properties. Conventionnal core analysis mainly contributes to establish relationships between facies, petrophysics and geophysics. However, populating gridblocks reservoir models with petrophysics requires parsimonious facies classifications and effective relationships at larger scales that field studies rarely investigate. Studying outcrop analogues helps filling the gap between lab measurements and effective upscaled properties of models, and considerably improves the modelling workflows.
The ALBION R&D project developed an innovative framework for multi-physics and multi-scales characterization of Barremian-Aptian carbonates from south-eastern France. These outcropping rudist-rich limestones constitute an analogue of Middle-East reservoirs. Petrophysical and geophysical properties were measured on plugs from cores and outcrops but also at larger scales thanks to original experiments on cores, in and between boreholes. Indeed the analogue includes several experimental areas, where hydraulic tests in sealed wells sections and tomographies between very close boreholes allowed investigating petrophysical and geophysical rock properties at intermediate decimetric to decametric scales. Thanks to the resulting database, this paper aims quantifying the variability of multi-physics data (e.g. porosity, permeability, and P-wave velocity) at different scales in regards of an updated and unified facies classification. The latter is only based on sedimentary origin and fabrics. Other available properties affecting petrophysics are used to cluster facies associations in sub-classes.
Consequently the facies classification does not allow discriminating the distributions of porosity, permeability, nor p-wave velocity. For the rudist facies, that is the most sampled, texture subclasses do not help this work. Reversely, the place of sampling, that is likely a proxy of diagenesis and age, cluster the petrophysical distributions. The results remind us that a proper facies definition should consider both sedimentary origin, fabrics, texture, diagenesis and tectonics. They also point out the relative importance of each characteristics in regards of the scale of interest and the difficulty to infer upscaled relationships between rock properties from CCAL because the representative elementary volume of carbonates is usually higher than the plug and even the core volumes.
OMV's exploration efforts in Austria include the prospecting for new fields in units of the Alpine thrust belt below the Neogene Vienna Basin. Current exploration efforts are targeting the deep and underexplored parts of the Paleogene thrust belt with potentially large structural closures within the so-called Rhenodanubian Flysch units.
Interpretation of fold-thrust structures is primarily based on new 3D seismic reflection data, which images the Paleogene nappes buried below the Neogene Vienna Basin fill and is supplemented by well data. In order to improve the understanding of the structural architecture, the results are compared to the regional structural framework of the Eastern Alps and West Carpathians to the W and NE of the Vienna Basin, respectively.
Spatial seismic interpretation depicts the Rhenodanubian Flysch units being subject to three major phases of deformation during the Paleogene and Neogene:
Our interpretation depicts several large ∼NE-trending structural closures within the deeper parts of the N-vergent Paleogene nappe stack with structural closures of up to 1000 m and areas of up to 5km2. They include Paleogene turbidites, which are known dual porosity fractured reservoirs in producing fields within overlying nappes. The NE-trending structural closures result from both Paleogene N-directed thrusting and subsequent refolding of the N-vergent flysch nappes by Early Miocene NW-directed out-of-sequence thrusts. Comparison of data with the regional tectonic framework suggests that the NW-directed out-of sequence thrusts result from a local reorientation of thrusting and from basement buttressing during the Early Miocene, both being triggered by the shape and geometry of the underlying basement units.
Our results highlight the exploration potential in the deeper parts of the Alpine thrust belt with target depths exceeding 3 km. Due to the complex deformation, challenging reservoir types, high formation pressures and limited amount of data, the exploration of these deep targets translates to higher geological/technical risks and uncertainties, compared to shallower, more traditional plays. However, though very challenging, the deep opportunities have the potential for finding significant resources in an already hypermature hydrocarbon basin.
TechnipFMC was appointed by one its major client to conduct a feasibility study for the development a highly sour gas-condensate field. Sour gas levels are in the range of 22-28%vol of H 2 S and 13-17%vol of CO 2 and contains also organic sulphur components such as carbonyl sulphide, mercaptans and disulphides. The study addresses the evaluation of onshore technologies for gas and condensate processing (gas sweetening, gas dehydration, NGL recovery, condensate stabilization and sweetening) for five different set of export product: sales gas, LPGs, hydrocarbon condensates, Sulphur or re-injection of the acid gases, with the objective of selecting the most attractive scheme based on economic and HSE criteria. Using this case study, this paper aims to present the methodology, the different process configuration screened, the pros and cons of each technology, and the influence of basic technico-economic parameters on the plant architecture and technology selection.