Relevant bibliographies by topics / Fractured chalk

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Academic literature on the topic 'Fractured chalk'

Author: Grafiati
Published: 5 October 2024

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Journal articles on the topic "Fractured chalk"

1

Gale, Julia F. W. "Specifying Lengths of Horizontal Wells in Fractured Reservoirs." SPE Reservoir Evaluation & Engineering 5, no. 03 (June 1, 2002): 266–72. http://dx.doi.org/10.2118/78600-pa.

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Summary New methods have been developed to constrain optimal horizontal drilling distance in fractured reservoirs in which opening-mode fractures are dominant. Studies of opening-mode fractures in Austin Chalk outcrops and core reveal that open fractures are commonly clustered, with the distance between clusters ranging from approximately 1 m to more than 300 m, depending on the horizon in question. Aperture-size distributions follow power laws, and spacing-size distributions are negative logarithmic or log-normal. The aperture size at which fractures are open to fluids is variable and site-specific (0.14 to 11 mm). Scaling properties of fracture attributes were used to calculate fracture permeability and to constrain well-length fracture-permeability relationships. Fracture permeability depends on the scale of measurement; it has been determined at 9.2 darcies for 14 m of lower Austin Chalk core and 286 darcies for 300 m of upper Austin Chalk outcrop. Introduction The Upper Cretaceous Austin Chalk, which crops out in a swath across central Texas, is renowned as a horizontal play and is well documented as such.1,2 Most workers regard Austin Chalk reservoirs as being low-porosity, fractured reservoirs, although there is debate concerning the relative storage capacities of matrix vs. fractures. When drilling a horizontal well in a fractured reservoir, the usual aim is to intersect fractures that are capable of providing a conduit for fluid flow. Although many horizontal wells have been drilled in the Austin Chalk,3 there are still questions over where it is best to locate new operations and how to optimize three critical parameters: wellbore azimuth, vertical depth, and wellbore length.4 This paper focuses on the question of wellbore length, although information pertaining to azimuth and depth choices also has been obtained. The choice of wellbore length has, in the past, been guided by experience and by field rules established by the Texas Railroad Commission, whereby the length of wells is linked to the acreage allocation of proration units and the permissible producing rate.4 Although these guidelines are practical, they lack direct geological input. The aim of this contribution is to develop techniques in which well-length determination is based on direct observation of fracture systems in the Austin Chalk, in addition to the Texas Railroad Commission guidelines. The objective of the outcrop and core studies was to characterize the opening-mode fracture system. Aperture-size distribution, spacing-size distribution, and fracture fill were determined in each case, allowing characterization of the spatial architecture of large, open fractures. This approach enabled us to calculate fracture permeability for different well lengths and to constrain optimal drilling distance for horizontal wells. The relationship between opening-mode fractures and normal faults in the outcrop is documented, and the relative importance of fractures and faults to reservoir permeability is considered. The connectivity and vertical height of fractures, and their impact on permeability, are discussed. Study Areas Data are presented from two outcrop analogs: one is near Waxahachie, north central Texas (Grove Creek); the other is from McKinney Falls State Park, central Texas (McKinney Falls), and from two laterals of a horizontal core drilled by the Kinlaw Oil Corp. in Frio County, Pearsall field (Kinlaw core) (Fig. 1). This well is currently operated by BASA Resources Inc. Although this study relates to the Austin Chalk specifically, the techniques used are transferable and could be applied in other horizontal targets. Geology The Austin Chalk is variable in terms of mineralogy, texture, and stratigraphy in part because of the effect of a basement high, the San Marcos Arch,5 on the paleobathymetry of its depositional basin. The updip portions of the Chalk in the Austin and San Antonio regions are relatively shallow water deposits containing considerable quantities of benthic skeletal material. Deeper-water planktonic microfossils and nanofossils dominate the basin equivalents, although some benthic material was transported basinward in debris flows.5 Drake6 reports the updip portions of the chalk in Burleson County, Giddings field, to be less fractured than the downdip portions, with wells in the updip portions being poor producers. At McKinney Falls State Park, a pavement in the McKown formation is exposed where Onion Creek flows over the lower falls. The McKown formation is a lateral equivalent of the Austin Chalk and comprises chalk intercalated with pyroclastic deposits derived from Pilot Knob, a Cretaceous volcanic center 3 km to the southeast.7 The Grove Creek outcrop is stratigraphically at the top of the Upper Chalk, just below the overlying Ozan formation. The McKinney Falls outcrop is close to the overlying Taylor Marl. The horizontal Kinlaw core from Pearsall field is from the base of the lower Chalk in the Atco Member. Thus, stratigraphically and with respect to the basin architecture, the studied sites are disparate. It is not the intention of this paper to make definitive recommendations for drilling distance in the Austin Chalk based on so few sites, but rather to show with these examples how site-specific information may be used to this end. Data-Collection Methodology An important consideration in fracture studies is whether the fractures observed in a particular core or outcrop are representative of those fractures that occur in the subsurface and contribute to fluid flow. In the case of core studies, the main pitfalls surround the distinction of natural fractures from those induced by drilling or by the core-handling process. Kulander et al.8 provided a comprehensive guide to natural and induced fracture identification in cores, and their criteria were used here. In outcrop studies, the challenge is to distinguish those fractures that would have been formed in the subsurface, at an appropriate depth to be considered as a reservoir analog, from those fractures that developed during uplift and erosion. The fracture systems documented here are confined to those that exhibit partial or total mineral fill and that would have developed in the subsurface.
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Carpenter, Chris. "Extended Laterals and Hydraulic Fracturing Redevelop Tight Fractured Carbonates." Journal of Petroleum Technology 76, no. 07 (July 1, 2024): 93–95. http://dx.doi.org/10.2118/0724-0093-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216292, “Redevelopment of Tight Fractured Carbonates Through Extended Laterals and Hydraulic Fracturing,” by Antonio Buono, Cameron Taylor, and Alyssa Dordan, SPE, ExxonMobil, et al. The paper has not been peer reviewed. _ In the complete paper, the authors compare development scenarios in a fractured carbonate play between historic vertical and short horizontal development and modern hydraulically fractured extended lateral development. Because of its long production history and recent redevelopment efforts, the Austin Chalk was chosen as a natural laboratory to test how recent artificial stimulation techniques can lead to additional production from a wider range of pore systems. Development of the Austin Chalk In recent years, application of modern unconventional multistage hydraulic fracturing techniques, coupled with adding proppant to support induced fracture networks, mitigated the steep decline seen in historic production profiles. These improvements were exemplified in a recent Austin Chalk redevelopment where modern completions led to an increase in estimated ultimate recovery (EUR) by 250% on average. In the targeted area of development, historic, short Austin Chalk laterals without modern completions exhibited a wide range of well performance. Some outlier wells achieved high recoveries from accessing an existing natural fracture network with the original completion, whereas others, after only a few months of economic production, were unable to achieve continuous flow without a propped stimulation. The differences in performance partially can be explained by the fact that the reservoir quality of different intervals within the Austin Chalk is likely highly variable. This is exemplified in the B-2 Zone, which contains a well-developed vertical fracture network with variable lengths. Data suggest that the natural fractures are confined within the B-2 and it is geomechanically less-susceptible to wellbore collapse than zones with higher clay concentrations. The B-2 is likely a stiffer interval than the E Zone. This implies that differences exist in the properties of these units that are caused by changes in mineralogy and cementation. The authors aim to characterize reservoir quality and hydrocarbon distributions of the fractured relatively clean zones compared with the hydraulically stimulated reservoir in relatively “dirty” chalky zones, and evaluate geomechanical properties and production expectations from each zone. Depositionally, these units can be characterized broadly as carbonate-rich with subordinate siliciclastic detritus composed of clay minerals and silt-sized quartz and plagioclase grains. These units all contain distinctive stylolite seams. The most-favorable hydrocarbon shows typically are in the lower members of the Austin Chalk. Production data show that natural-fracture-only production (heritage) generally has lower total EUR with highly variable well-to-well production profiles vs. fracture and matrix production, which the authors write that they believe is achieved when unconventional technology is applied to these reservoirs. To project from heritage chalk production to expected EUR using modern completions, the authors used a risked EUR scaling factor of 1.5×. Consequently, the potential uplift in economic viability was recognized through a multiwell Austin Chalk appraisal to assess well-to-well communication with Eagle Ford codevelopment. The authors’ appraisal evaluated reservoir-quality differences between the main landing zones in the Austin Chalk with those from the E Zone of the Austin Chalk and Upper Eagle Ford, respectively, to demonstrate how significant economic uplift can be realized in mature, tight carbonate fields with unconventional technology.
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Bredal, Tine Vigdel, Reidar Inge Korsnes, Udo Zimmermann, Mona Wetrhus Minde, and Merete Vadla Madland. "Water Weakening of Artificially Fractured Chalk, Fracture Modification and Mineral Precipitation during Water Injection—An Experimental Study." Energies 15, no. 10 (May 22, 2022): 3817. http://dx.doi.org/10.3390/en15103817.

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This experiment was designed to study the water-weakening effect of artificially fractured chalk caused by the injection of different compositions of brines under reservoir conditions replicating giant hydrocarbon reservoirs at the Norwegian Continental Shelf (NCS). NaCl, synthetic seawater (SSW), and MgCl2, with same ionic strength, were used to flood triaxial cell tests for approximately two months. The chalk cores used in this experiment originate from the Mons basin, close to Obourg, Belgium (Saint Vast Formation, Upper Cretaceous). Three artificially fractured chalk cores had a drilled central hole parallel to the flooding direction to imitate fractured chalk with an aperture of 2.25 (±0.05) mm. Two additional unfractured cores from the same sample set were tested for comparison. The unfractured samples exposed a more rapid onset of the water-weakening effect than the artificially fractured samples, when surface active ions such as Ca2+, Mg2+ and SO42− were introduced. This instant increase was more prominent for SSW-flooded samples compared to MgCl2-flooded samples. The unfractured samples experienced axial strains of 1.12% and 1.49% caused by MgCl2 and SSW, respectively. The artificially fractured cores injected by MgCl2 and SSW exhibited a strain of 1.35% and 1.50%, while NaCl showed the least compaction, at 0.27%, as expected. Extrapolation of the creep curves suggested, however, that artificially fractured cores may show a weaker mechanical resilience than unfractured cores over time. The fracture aperture diameters were reduced by 84%, 76%, and 44% for the SSW, MgCl2, and NaCl tests, respectively. Permeable fractures are important for an effective oil production; however, constant modification through compaction, dissolution, and precipitation will complicate reservoir simulation models. An increased understanding of these processes can contribute to the smarter planning of fluid injection, which is a key factor for successful improved oil recovery. This is an approach to deciphering dynamic fracture behaviours.
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Brettmann, K. L., K. Høgh Jensen, and R. Jakobsen. "Tracer Test in Fractured Chalk." Hydrology Research 24, no. 4 (August 1, 1993): 275–96. http://dx.doi.org/10.2166/nh.1993.0008.

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A two-well tracer test carried out in fractured chalk was analyzed using a three-dimensional finite-difference model for flow and transport which, was constructed on the basis of the geological and hydraulic information collected at the field site. The model was developed as a dual-porosity continuum model, in which advection was assumed to occur only in the fractures, and the water in the porous matrix was assumed to be static. The exchange of solute between the fractures (mobile phase) and the porous matrix (immobile phase) was assumed to occur as a diffusion process in response to the local concentration difference of solute between the two phases. Simulations from the dual-porosity model reproduced the shape of the observed breakthrough curves, although some portions of the tail were not accurately represented. The model was also applied as a single-porosity model for advection and dispersion in the fractures with no solute exchange with the porous matrix. The simulations from the single-porosity model greatly overestimated the observed lithium concentrations, and showed very little tailing effect in the falling limb. The study shows that, based on the given tracer test, solute transport in a fractured chalk cannot be represented by a single-porosity approach and hence when dealing with contaminant transport in such systems, both a fractured and a porous domain need to be considered.
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Zuta, John, and Ingebret Fjelde. "Transport of CO2-Foaming Agents During CO2-Foam Processes in Fractured Chalk Rock." SPE Reservoir Evaluation & Engineering 13, no. 04 (August 5, 2010): 710–19. http://dx.doi.org/10.2118/121253-pa.

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Summary The coinjection of carbon dioxide (CO2) and a CO2-foaming agent to form stable CO2 foam has been found to improve the sweep efficiency during CO2-foam processes in carbonate reservoirs. However, only a few studies of CO2-foam transport in fractured rock have been reported. In fractured chalk reservoirs with low matrix permeability, the aqueous CO2-foaming-agent solution will flow mainly through the fractures. The total retention of the CO2-foaming agent in the reservoir will depend on how much of the matrix is contacted by the CO2-foaming-agent solution during the project period and, therefore, on its transport rate into the matrix. This paper presents results from a series of static and flowthrough experiments carried out to investigate the transport and retention phenomena of CO2-foaming agents in fractured chalk models at 55°C. Fractured chalk models with 100% water-saturation and residual-oil saturation after waterflooding were used. In the static experiments, the fractured model was created by transferring core plugs with different diameters into steel cells with an annulus space around the plugs. The fracture volume was filled with foaming-agent solutions with different initial concentrations. The experiments were carried out in parallel, with liquid samples regularly taken out from the fracture above the plugs and analyzed for the foaming-agent concentration. The experiments were monitored until the concentrations in the fractures reached a plateau. At specific and constant concentrations of the foaming agent in the fractures, the plugs were demounted and samples drilled out along the whole lengths of the plugs from the outer, middle, and center portions. These samples were analyzed for foaming-agent concentration to determine how much of it had penetrated the matrix. Results indicate that the transport of the foaming-agent decreases toward the center of the plugs with 100% water-saturation and residual-oil saturation after waterflooding. Modeling of the static experiments using the Computer Modelling Group (CMG)'s commercial reservoir simulator STARS was also carried out to determine the transport rate for the foaming agent. A good history match between experimental and modeling results was obtained. In the flow-through experiments, the fractured model was created by drilling a concentric hole through the center of the plug. The hole, simulating an artificial fracture, was filled with glass beads of different dimensions. Fractured models with different effective permeability were flooded with equal volumes of the foaming-agent solution. Results show that the transport of CO2-foaming agent into the matrix is slower in the fractured models than in the homogeneous models with viscous flooding of the rock.
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Jakobsen, R., K. Høgh Jensen, and K. L. Brettmann. "Tracer Test in Fractured Chalk." Hydrology Research 24, no. 4 (August 1, 1993): 263–74. http://dx.doi.org/10.2166/nh.1993.0007.

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A two-well tracer test was conducted in eastern Denmark, in which a short duration pulse of lithium chloride was injected into a recharge well and made to flow through a fractured chalk aquifer to a discharge well. The wells were 25 m apart, and the concentration of lithium arriving at the discharge well was monitored at five vertical intervals in the well for a 21-day period. The observed breakthrough curves show a sharp breakthrough front, with an arrival time that is consistent with advective transport through the fractures in the chalk. The breakthrough curves also exhibit a long tail in the falling limb, suggesting the influence of a secondary transport mechanism of diffusion into the porous matrix.
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7

Eide, Øyvind, Martin A. Fernø, Zachary Alcorn, and Arne Graue. "Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk." SPE Journal 21, no. 01 (February 18, 2016): 112–20. http://dx.doi.org/10.2118/170920-pa.

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Summary This work demonstrates that diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO2) for enhanced oil recovery, depending on the CO2 distribution within the fracture network and distance between fractures. High oil recovery was observed during miscible, supercritical CO2 injection (RF = 86% original oil in place) in the laboratory with a fractured chalk core plug with a large permeability contrast. Dynamic 3D fluid saturations from computed-tomography (CT) imaging made it possible to study the local oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient with analytical methods. The obtained diffusion coefficient varies between 0.83 and 1.2 ×10−9m2/s, depending on the method used for calculation. A numerical sensitivity analysis, with a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and oil-filled matrix. In a numerical upscaling effort, with the experimentally achieved diffusion coefficient, oil-recovery rates and local flow were studied in an inverted five-spot pattern in a heavily fractured carbonate reservoir.
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Al-Shuhail, Abdullatif A. "Fracture-porosity inversion from P-wave AVOA data along 2D seismic lines: An example from the Austin Chalk of southeast Texas." GEOPHYSICS 72, no. 1 (January 2007): B1—B7. http://dx.doi.org/10.1190/1.2399444.

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Vertical aligned fractures can significantly enhance the horizontal permeability of a tight reservoir. Therefore, it is important to know the fracture porosity and direction in order to develop the reservoir efficiently. P-wave AVOA (amplitude variation with offset and azimuth) can be used to determine these fracture parameters. In this study, I present a method for inverting the fracture porosity from 2D P-wave seismic data. The method is based on a modeling result that shows that the anisotropic AVO (amplitude variation with offset) gradient is negative and linearly dependent on the fracture porosity in a gas-saturated reservoir, whereas the gradient is positive and linearly dependent on the fracture porosity in a liquid-saturated reservoir. This assumption is accurate as long as the crack aspect ratio is less than 0.1 and the ratio of the P-wave velocity to the S-wave velocity is greater than 1.8 — two conditions that are satisfied in most naturally fractured reservoirs. The inversion then uses the fracture strike, the crack aspect ratio, and the ratio of the P-wave velocity to the S-wave velocity to invert the fracture porosity from the anisotropic AVO gradient after inferring the fluid type from the sign of the anisotropic AVO gradient. When I applied this method to a seismic line from the oil-saturated zone of the fractured Austin Chalk of southeast Texas, I found that the inversion gave a median fracture porosity of 0.21%, which is within the fracture-porosity range commonly measured in cores from the Austin Chalk.
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Sayer, Zoë, Jonathan Edet, Rob Gooder, and Alexandra Love. "The Machar Field, Block 23/26a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 523–36. http://dx.doi.org/10.1144/m52-2018-45.

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AbstractMachar is one of several diapir fields located in the Eastern Trough of the UK Central North Sea. It contains light oil in fractured Cretaceous–Danian chalk and Paleocene sandstones draped over and around a tall, steeply-dipping salt diapir that had expressed seafloor relief during chalk deposition. The reservoir geology represents a complex interplay of sedimentology and evolving structure, with slope-related redeposition of both the chalk and sandstone reservoirs affecting distribution and reservoir quality. The best reservoir quality occurs in resedimented chalk (debris flows) and high-density turbidite sandstones. Mapping and characterizing the different facies present has been key to reservoir understanding.The field has been developed by water injection, with conventional sweep in the sandstones and imbibition drive in the chalk. Although the chalk has high matrix microporosity, permeability is typically less than 2 mD, and fractures are essential for achieving high flow rates; test permeabilities can be up to 1500 mD. The next phase of development is blowdown, where water injection is stopped and the field allowed to depressurize. This commenced in February 2018.
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Graue, A., T. Bognø, B. A. Baldwin, and E. A. Spinler. "Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs." SPE Reservoir Evaluation & Engineering 4, no. 06 (December 1, 2001): 455–66. http://dx.doi.org/10.2118/74335-pa.

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Summary Iterative comparison between experimental work and numerical simulations has been used to predict oil-recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability by aging in crude oil at an elevated temperature produced chalk blocks that were strongly water-wet and moderately water-wet, but with identical mineralogy and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored the waterflooding of these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressure- and relative permeability-input data used in the simulations. Capillary pressure and relative permeabilities at each wettability condition were measured experimentally and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of the validity of these input data. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations than matching production profiles only. Introduction Laboratory waterflood experiments, with larger blocks of fractured chalk where the advancing waterfront has been imaged by a nuclear tracer technique, showed that changing the wettability conditions from strongly water-wet to moderately water-wet had minor impact on the the oil-production profiles.1–3 The in-situ saturation development, however, was significantly different, indicating differences in oil-recovery mechanisms.4 The main objective for the current experiments was to determine the oil-recovery mechanisms at different wettability conditions. We have reported earlier on a technique that reproducibly alters wettability in outcrop chalk by aging the rock material in stock-tank crude oil at an elevated temperature for a selected period of time.5 After applying this aging technique to several blocks of chalk, we imaged waterfloods on blocks of outcrop chalk at different wettability conditions, first as a whole block, then when the blocks were fractured and reassembled. Earlier work reported experiments using an embedded fracture network,4,6,7 while this work also studied an interconnected fracture network. A secondary objective of these experiments was to validate a full-field numerical simulator for prediction of the oil production and the in-situ saturation dynamics for the waterfloods. In this process, the validity of the experimentally measured capillary pressure and relative permeability data, used as input for the simulator, has been tested at strongly water-wet and moderately water-wet conditions. Optimization of either Pc data or kr curves for the chalk matrix in the numerical simulations of the whole blocks at different wettabilities gave indications of the data's validity. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations of the fractured blocks, in which only the fracture representation was a variable. Experimental Rock Material and Preparation. Two chalk blocks, CHP8 and CHP9, approximately 20×12×5 cm thick, were obtained from large pieces of Rørdal outcrop chalk from the Portland quarry near Ålborg, Denmark. The blocks were cut to size with a band saw and used without cleaning. Local air permeability was measured at each intersection of a 1×1-cm grid on both sides of the blocks with a minipermeameter. The measurements indicated homogeneous blocks on a centimeter scale. This chalk material had never been contacted by oil and was strongly water-wet. The blocks were dried in a 90°C oven for 3 days. End pieces were mounted on each block, and the whole assembly was epoxy coated. Each end piece contained three fittings so that entering and exiting fluids were evenly distributed with respect to height. The blocks were vacuum evacuated and saturated with brine containing 5 wt% NaCl+3.8 wt% CaCl2. Fluid data are found in Table 1. Porosity was determined from weight measurements, and the permeability was measured across the epoxy-coated blocks, at 2×10–3 µm2 and 4×10–3 µm2, for CHP8 and CHP9, respectively (see block data in Table 2). Immobile water saturations of 27 to 35% pore volume (PV) were established for both blocks by oilflooding. To obtain uniform initial water saturation, Swi, oil was injected alternately at both ends. Oilfloods of the epoxy-coated block, CHP8, were carried out with stock-tank crude oil in a heated pressure vessel at 90°C with a maximum differential pressure of 135 kPa/cm. CHP9 was oilflooded with decane at room temperature. Wettability Alteration. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperatures, produced a moderately water-wet chalk block, CHP8, with similar mineralogy and pore geometry to the untreated strongly water-wet chalk block CHP9. Block CHP8 was aged in crude oil at 90°C for 83 days at an immobile water saturation of 28% PV. A North Sea crude oil, filtered at 90°C through a chalk core, was used to oilflood the block and to determine the aging process. Two twin samples drilled from the same chunk of chalk as the cut block were treated similar to the block. An Amott-Harvey test was performed on these samples to indicate the wettability conditions after aging.8 After the waterfloods were terminated, four core plugs were drilled out of each block, and wettability measurements were conducted with the Amott-Harvey test. Because of possible wax problems with the North Sea crude oil used for aging, decane was used as the oil phase during the waterfloods, which were performed at room temperature. After the aging was completed for CHP8, the crude oil was flushed out with decahydronaphthalene (decalin), which again was flushed out with n-decane, all at 90°C. Decalin was used as a buffer between the decane and the crude oil to avoid asphalthene precipitation, which may occur when decane contacts the crude oil.
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Dissertations / Theses on the topic "Fractured chalk"

1

Matthews, Marcus Charles. "The mass compressibility of fractured chalk." Thesis, University of Surrey, 1993. http://epubs.surrey.ac.uk/773029/.

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This thesis is concerned with the mass compressibility of fractured chalk and its influence on the settlement of shallow foundations. A review of the literature reveals nineteen case records of load-settlement behaviour from relatively small diameter « 1m) plate loading tests but only six welldocumented case records of the behaviour of shallow foundations on chalk. The plate loading tests indicate that highly fractured near-surface chalk undergoes yield at relatively low stresses (200 - 400kPa) resulting in a significant reduction in stiffness. This behaviour contrasts with that observed in other rock types with similar discontinuity patterns. For chalk it has only been observed in one case record for a full-scale foundation. Little is understood about the mechanisms causing yield. At the time of starting this research, based largely upon the experience ..gained from in-situ loading tests carried out at Mundford, Norfolk (Ward et aI., 1968), it was known that factors such as fracture spacing and aperture played an important role in controlling the load-settlement behaviour of shallow foundations. Little attention was paid to the large variation in intact properties displayed by the chalk. In this research nine 1.8m diameter plate loading tests have been carried out by the author on chalks with different intact mechanical properties and similar discontinuity patterns. These data are used to evaluate other in-situ tests (such as SPT, surface-wave geophysics and visual assessment) as means of providing parameters for the prediction of foundation settlement. The results of this research indicate that fractured near-surface chalk undergoes yield within the range of stresses likely to be imposed by shallow foundations and that the pre-yield stiffness of the rock mass is controlled to a large extent by the looseness of the fracture-block system, which in tum appears to be associated with the intact mechanical properties of the rock. The post yield-stiffness of the rock mass is generally about one tenth of the pre-yield stiffness and is relatively insensitive to the rock material properties.
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Payne, Simon S. "Analysis of multi-component seismic data in fractured chalk." Thesis, University of Oxford, 2006. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.437033.

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Christoffersen, Kjell R. "High-pressure experiments with application to naturally fractured chalk reservoirs." Doctoral thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 1992. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-5290.

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Darvish, Gholam Reza. "Physical Effects Controlling Mass Transfer in Matrix Fracture System during CO2 Injection Into Chalk Fractured Reservoirs." Doctoral thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2007. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-1736.

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Tertiary recovery or Improved Oil Recovery (IOR) methods are key processes to replace or upgrade reserves, which can be economically recovered, beyond conventional methods. Therefore, the application of IOR methods offers opportunities to increase the hydrocarbon reserves that have been produced in addition to those coming from exploration and reservoir appraisal. The purpose of this thesis is to combine experiments, computations, and theory to make fundamental advances in our ability to predict transport phenomena as well as the IOR potential involved in tertiary CO2 injection at the lab scale in a matrix fracture system. This is done by using rock and fluid samples similar to one of the chalk fractured reservoirs in the North Sea. The work involves a review of key physical mechanisms and calculation methods for the modelling of fluid flow in fractured reservoirs. The main matrix fracture fluid exchange mechanisms described are gravity drainage, capillary imbibition and molecular diffusion. Also described are the estimation of the recovery performance for a single block and a stack of blocks surrounded by gas. The effect of interfacial tension on the ultimate recovery has been discussed and the definition of the minimum miscibility pressure for single porosity and dual porosity system is described. Numerical modelling of gravity drainage for a matrix blocks surrounded by gas has been described. Numerical estimation of gas-oil gravity drainage by reducing the number of grid blocks in vertical direction in a draining matrix column is common practice in order to reduce the simulation time. However this can lead to systematic numerical errors and consequently underestimation of the recovery. In order to minimize the underestimation of the reservoir performance, a set of pseudo functions needs to be developed that not only satisfy the actual responses in the fine grid simulation but also reduce the simulation time. The effectiveness and the accuracy of such pseudo functions are extensively discussed and the different simulation models have been run to quantify the underestimation of recovery by coarse griding in the numerical modelling of gravity drainage. The importance of the molecular diffusion to recover oil from a high fracture intensity system is described as well as the basic concept for calculating the molecular diffusion based on the Fick’s second law. Corresponding laboratory methods for the estimation and measurement of the oil and gas diffusion coefficients are reviewed. The effect of molecular diffusion on the interfacial tension and eventually on the gas-oil capillary pressure is presented. A compositional study of a non-equilibrium gas injection process such as CO2 requires an equation of state (EOS) model which can predict the CO2/oil phase behaviour. In order to make such EOS model, a set of pVT experiments using fluids involved in the core flooding has been performed and finally the EOS models were tuned against experimental pVT data. The necessary steps to perform pVT experiments including making live reservoir oil, constant composition expansion, single flash, viscosity measurements and CO2-oil swelling are described. Gas injection is known to have a significant potential for high ultimate recovery in many oil fractured reservoirs with tall matrix blocks. The high ultimate recovery in these reservoirs could be due to the effectiveness of the gravity drainage mechanism. Fractured chalk reservoirs in the North Sea have a very high porosity (up to 45%), and low matrix permeability (3-4 mD) with small matrix block size. In order to quantify the dominant transport mechanisms and potential of Improved Oil Recovery (IOR) in the case of CO2 injection in the North Sea chalk fractured reservoirs, CO2 injection experiments at reservoir conditions have to be performed in the laboratory. The feasibility of such laboratory experiments initially has been verified by performing compositional simulation. In these simulations by varying the experimental parameters, such as core height and fracture size, the optimum matrix and fracture geometry were designed and the summary of the task is presented in Paper 1- Appendix A. CO2 injection experiments under reservoir conditions in the presence of different water saturation at reservoir conditions have been carried out. A unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized with the CO2. A complete description of, rock and fluids, experimental procedure and experimental results is given in Chapters 3, 4 and Papers 2 and 3 in Appendices B, C. In order to investigate the effect of temperature on the oil recovery mechanism, CO2 injection experiments were carried out at initial reservoir temperature (130 ºC) and a low temperature 60 ºC which representing the water flooded parts in the reservoir. The effect of initial water saturation also was investigated at reservoir temperature 130 ºC by performing two experiments with different initial water saturation. Results from these experiments show a high potential for oil recovery in all experiments. In the high temperature experiments, the produced oil had a variable composition during CO2 injection, while at the low temperature condition, the produced oil initially had a constant composition and then it started to change. Different behaviour of produced oil composition in the high and low temperature might be due to dominant of diffusion mechanism in the high temperature experiments. In the low temperature (60 ºC) experiment, at the early stage of CO2 injection the produced oil had constant composition for a short period of time and then it changed to variable composition similar to the high temperature case. This behaviour maybe is due to high solubility of CO2 into oil and consequently more oil swelling than the high temperature condition. In order to quantify the above mechanisms, several attempts have been done to history match the experiments by using compositional simulator. But in all cases, it was not possible to history match the experiments. The weakness of the simulator was due to the improper formulation which was used for calculating the cross phase diffusion between the oil and gas phase in the matrix and fracture system. The details of simulation work as well as the cross phase diffusion issue are discussed in Chapter 5 and Paper 2 in Appendix B.
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5

Doran, Helen. "Diagenesis of a fractured chalk reservoir : Machar oilfield, Central North Sea." Thesis, University of Edinburgh, 2004. http://hdl.handle.net/1842/13691.

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The Machar Cretaceous chalk oilfield, Central North Sea, is a structural trap of chalk folded above a diaper of Zechstein salt, and formed a regional leakoff point for overpressure from Jurassic sandstones deeper in the basin. Chalk was deposited as pelagic sediment, but re-deposition by gravity flows improves reservoir quality. Diagenesis of the Machar chalk matrix occurs during burial to 1Km. Stylolites form in the chalk at depths below 600m and cause cementation of the reservoir through pressure dissolution and precipitation in a closed system. During diagenesis of the chalk matrix the underlying salt diaper evolves and as a result four fracture sets begin to form in the chalk reservoir. Hydrocarbon charge at mid-Miocene halted matrix cementation resulting in an exceptionally porous (30%mD) reservoir. The growth and evolution of the diaper is marked by the formation of healed fractures within the chalk reservoir. Fracture filling calcite records the evolution of the Tor Formation reservoir from a closed system, rock-dominated environment to an open diagenetic system. Four different fracture types have been discovered within the Tor formation on the Machar field. Of these, the first to form was Fracture Type 1, relating to bedding stylolites formed through minor extension at the crest of the reservoir as the salt attempts to remain buoyant. This fracture is filled with Calcite 1. δ13C values within this calcite (+ 2.0 to + 2.3‰ PDB) are similar to the values measured in the matrix chalk (+ 1.5 to + 3‰ PDB), suggesting that like the matrix cement this formed in a rock-dominated system. 87Sr/86Sr (0.7078 to 70787) values within Calcite 1,also similar to the matrix values (0.70770-0.70791) supports this theory. Negative δ18O (-5 to -7‰ PDB) values measured in Calcite 1 are explained by increased burial temperature during precipitation. Fracture type 2, the second fracture to form, is filled with Calcite 2; δ13C values (+ 3.6 to + 5.9‰ PDB), are more positive than the matrix values (+ 1.5 to + 3.0‰ PDB), and mark the opening of the reservoir to an external fluid. Fracture type 3 is filled with Calcite 3, and forms as Palaeogene sediments begin to down build around the evolving salt diaper. Calcite 3 precipitated from an external fluid that is restricted in its migration between tectonic stylolites. Calcite 3 is replaced by saddle dolomite, celestite, barite and fluorite.
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6

Mace, Robert Earl. "Ground-water flow and solute transport in a fractured chalk outcrop, North-Central Texas /." Digital version accessible at:, 1998. http://wwwlib.umi.com/cr/utexas/main.

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7

Darvish, Gholam Reza. "Physical Effects Controlling Mass Transfer in Matrix Fracture System during CO2 Injection Into Chalk Fractured Reservoirs." Doctoral thesis, Norwegian University of Science and Technology, Department of Petroleum Engineering and Applied Geophysics, 2007. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-1736.

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Tertiary recovery or Improved Oil Recovery (IOR) methods are key processes to replace or upgrade reserves, which can be economically recovered, beyond conventional methods. Therefore, the application of IOR methods offers opportunities to increase the hydrocarbon reserves that have been produced in addition to those coming from exploration and reservoir appraisal.

The purpose of this thesis is to combine experiments, computations, and theory to make fundamental advances in our ability to predict transport phenomena as well as the IOR potential involved in tertiary CO2 injection at the lab scale in a matrix fracture system. This is done by using rock and fluid samples similar to one of the chalk fractured reservoirs in the North Sea.

The work involves a review of key physical mechanisms and calculation methods for the modelling of fluid flow in fractured reservoirs. The main matrix fracture fluid exchange mechanisms described are gravity drainage, capillary imbibition and molecular diffusion. Also described are the estimation of the recovery performance for a single block and a stack of blocks surrounded by gas. The effect of interfacial tension on the ultimate recovery has been discussed and the definition of the minimum miscibility pressure for single porosity and dual porosity system is described.

Numerical modelling of gravity drainage for a matrix blocks surrounded by gas has been described. Numerical estimation of gas-oil gravity drainage by reducing the number of grid blocks in vertical direction in a draining matrix column is common practice in order to reduce the simulation time. However this can lead to systematic numerical errors and consequently underestimation of the recovery.

In order to minimize the underestimation of the reservoir performance, a set of pseudo functions needs to be developed that not only satisfy the actual responses in the fine grid simulation but also reduce the simulation time. The effectiveness and the accuracy of such pseudo functions are extensively discussed and the different simulation models have been run to quantify the underestimation of recovery by coarse griding in the numerical modelling of gravity drainage.

The importance of the molecular diffusion to recover oil from a high fracture intensity system is described as well as the basic concept for calculating the molecular diffusion based on the Fick’s second law. Corresponding laboratory methods for the estimation and measurement of the oil and gas diffusion coefficients are reviewed. The effect of molecular diffusion on the interfacial tension and eventually on the gas-oil capillary pressure is presented.

A compositional study of a non-equilibrium gas injection process such as CO2 requires an equation of state (EOS) model which can predict the CO2/oil phase behaviour. In order to make such EOS model, a set of pVT experiments using fluids involved in the core flooding has been performed and finally the EOS models were tuned against experimental pVT data. The necessary steps to perform pVT experiments including making live reservoir oil, constant composition expansion, single flash, viscosity measurements and CO2-oil swelling are described.

Gas injection is known to have a significant potential for high ultimate recovery in many oil fractured reservoirs with tall matrix blocks. The high ultimate recovery in these reservoirs could be due to the effectiveness of the gravity drainage mechanism.

Fractured chalk reservoirs in the North Sea have a very high porosity (up to 45%), and low matrix permeability (3-4 mD) with small matrix block size. In order to quantify the dominant transport mechanisms and potential of Improved Oil Recovery (IOR) in the case of CO2 injection in the North Sea chalk fractured reservoirs, CO2 injection experiments at reservoir conditions have to be performed in the laboratory.

The feasibility of such laboratory experiments initially has been verified by performing compositional simulation. In these simulations by varying the experimental parameters, such as core height and fracture size, the optimum matrix and fracture geometry were designed and the summary of the task is presented in Paper 1- Appendix A.

CO2 injection experiments under reservoir conditions in the presence of different water saturation at reservoir conditions have been carried out. A unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized with the CO2.

A complete description of, rock and fluids, experimental procedure and experimental results is given in Chapters 3, 4 and Papers 2 and 3 in Appendices B, C. In order to investigate the effect of temperature on the oil recovery mechanism, CO2 injection experiments were carried out at initial reservoir temperature (130 ºC) and a low temperature 60 ºC which representing the water flooded parts in the reservoir. The effect of initial water saturation also was investigated at reservoir temperature 130 ºC by performing two experiments with different initial water saturation.

Results from these experiments show a high potential for oil recovery in all experiments. In the high temperature experiments, the produced oil had a variable composition during CO2 injection, while at the low temperature condition, the produced oil initially had a constant composition and then it started to change. Different behaviour of produced oil composition in the high and low temperature might be due to dominant of diffusion mechanism in the high temperature experiments.

In the low temperature (60 ºC) experiment, at the early stage of CO2 injection the produced oil had constant composition for a short period of time and then it changed to variable composition similar to the high temperature case. This behaviour maybe is due to high solubility of CO2 into oil and consequently more oil swelling than the high temperature condition.

In order to quantify the above mechanisms, several attempts have been done to history match the experiments by using compositional simulator. But in all cases, it was not possible to history match the experiments.

The weakness of the simulator was due to the improper formulation which was used for calculating the cross phase diffusion between the oil and gas phase in the matrix and fracture system. The details of simulation work as well as the cross phase diffusion issue are discussed in Chapter 5 and Paper 2 in Appendix B.

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8

MacAllister, Donald John. "Monitoring seawater intrusion into the fractured UK Chalk aquifer using measurements of self-potential (SP)." Thesis, Imperial College London, 2016. http://hdl.handle.net/10044/1/33350.

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Using laboratory, numerical and field experiments this study investigated whether borehole measurements of self-potential (SP) can be used to monitor seawater intrusion into the fractured UK Chalk aquifer. The SP, a natural voltage, arises in water saturated fractured porous media due to gradients in pressure (electrokinetic (EK) potential) and concentration (exclusion-diffusion (EED) potential), both features of seawater intrusion. An electrode array was installed in a monitoring borehole c.1.7 km from the coast, in Saltdean, East Sussex, and c.1.3 km from an active abstraction borehole. Head fluctuations in the monitoring borehole were controlled by tidal processes and seasonal changes in inland head. SP monitoring over 1.5 years revealed tidal SP signals. The fluctuations (c.600 μV) were two orders of magnitude larger than those observed at an inland site in the same aquifer, near Reading in Berkshire. Numerical simulation, supported by laboratory measurements, of the coupled hydrodynamic and electrical processes in the coastal aquifer suggested that the EK potential generated by tidal processes was one order of magnitude too small to be responsible for the tidal SP fluctuations. Instead, SP was caused by the EED potential that arose due to the concentration gradient between groundwater and seawater across the saline front (i.e. the 1000 mg/l isoline) some distance from the borehole. The saline front moved through a fracture at the base of the borehole in response to tides. A vertical SP gradient (c.0.22 mV/m), only present in the coastal borehole, was also observed. Modelling suggested that the gradient was due to the close proximity of the saline front (c.4 m) below the borehole and was caused by the EED potential. In August 2013 and 2014, tides and a decline in inland head caused saline water to enter the borehole. Fluid electrical conductivity logging showed that entry was via the fracture. Prior to each occurrence of saline breakthrough, an increase in the SP of c.300 μV was observed, commencing c.7 days before saline water was detected in the borehole. Although this study focused on a monitoring borehole, SP arrays could be installed in abstraction boreholes. The results suggest that SP monitoring may be used to provide early warning of saline water breakthrough, allowing for improved management of groundwater resources in coastal aquifers.
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9

Law, Ryan. "Geothermal systems in the Chalk of the south east of England : methods of predicting thermal transport in a fractured aquifer." Thesis, University of Birmingham, 2010. http://etheses.bham.ac.uk//id/eprint/981/.

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There has recently been a steady increase in the number of licenses granted for the abstraction of water from the Chalk aquifer beneath London to supply "open loop" geothermal systems (Environment Agency, 2007). However, there has been little research conducted on how the water re-injected by these systems, which often differs in temperature by as much as 10°C, will interact with the fractured Chalk aquifer in both the short and long term. An analytical solution developed by Bodvarsson (1989) was used to show that, for most configurations of a geothermal system, thermal transport would be governed by fractures. It was then proved that the United States Geological Survey SUTRA code could be used to construct a more detailed model of the aquifer. A thermal test was devised to collect hydrogeological and thermal data. This test, along with conventional site investigation techniques, was used at a site in central London. A detailed numerical model of the geothermal system and the aquifer was then constructed in SUTRA. The results showed that the fracture zones found during testing would affect the system performance. Building on these results a procedure was developed for designers, to ensure such systems function in an appropriate way.
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10

Hawi, Hanan. "Μοdélisatiοn de transfert de matières dissοutes et particulaires dans un milieu fracturé." Electronic Thesis or Diss., Normandie, 2024. http://www.theses.fr/2024NORMLH09.

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Pour faire face aux problèmes émergents de pollution et de dégradation de la qualité des eaux, il est nécessaire de maîtriser le fonctionnement hydrogéologique des roches réceptrices de polluants. Cela implique de définir la vulnérabilité des aquifères et d'optimiser la modélisation des phénomènes de rétention et des mécanismes de transport des particules dans les roches. Dans les aquifères karstiques, les fractures servent de voies préférentielles pour les particules, permettant ainsi leur transport rapide. Le transport des particules et de la matière dissoute dans les fractures est régi par l'advection et la dispersion qui sont influencées par plusieurs facteurs. L'objectif de cette étude est de contribuer à une meilleure compréhension des mécanismes de transport des particules solides et des matières dissoutes dans les fractures et des différents facteurs qui influencent ces mécanismes. A cette fin, un programme expérimental a été développé pour comprendre l'influence de la vitesse d'écoulement, de l'ouverture de la fracture, de l'orientation de la fracture et de la force ionique sur le transport des particules de kaolinite et du traceur dissous (fluorescéine) dans des échantillons de craie fracturée. Un modèle numérique a été développé sur la base de l'équation d'advection-dispersion, afin de déterminer les paramètres de transport et de comprendre en profondeur les interactions entre les particules et la surface de la fracture dans différentes conditions.Les résultats de cette étude ont révélé que l'effet hydrodynamique est significatif quelle que soit l'orientation de la fracture, la récupération des particules augmentant avec la vitesse d'écoulement. Les particules de kaolinite sont transportées plus rapidement que la fluorescéine en raison de l'effet d'exclusion de taille et du coefficient de dispersion plus élevé de la fluorescéine. Le coefficient d’attachement augmente avec la vitesse d'écoulement pour toutes les orientations de fracture et est indépendant de l'ouverture de la fracture. Inversement, le coefficient de détachement, qui est négligeable pour les petites vitesses d'écoulement, est plus important dans les petites ouvertures en raison d'une contrainte de cisaillement plus élevée. Les résultats ont montré, aussi, que l'orientation des fractures affecte de manière significative le transport des particules de kaolinite mais a un impact négligeable sur la fluorescéine. L'augmentation de l'orientation verticale des fractures améliore la récupération et la dispersion des particules, tandis que le coefficient d'attachement diminue. Enfin, les résultats de l'effet de la force ionique indiquent qu'une force ionique plus élevée augmente la rétention des particules et diminue le taux de récupération. Le coefficient d'attachement présente une augmentation linéaire et le coefficient de détachement suit une évolution exponentielle avec l'augmentation de la force ionique.Les résultats de l'étude soulignent l'importance de prendre en compte des vitesses d'écoulement élevées dans l'étude des effets hydrodynamiques, de l'ouverture de la fracture et de l'effet de la force ionique pour comprendre les mécanismes de transport des particules de taille micrométrique dans les fractures de la craie. Elle contribue également à faire progresser la compréhension de l'effet de l'orientation des fractures sur le transport des particules. Cette compréhension est essentielle pour évaluer les risques pour les ressources en eaux souterraines et pour faire progresser les mesures de protection de l'environnement
In order to face the emerging problems of pollution and deterioration in water quality, it is necessary to master the hydrogeological functioning of pollutant-receiving rocks. This involves, defining the vulnerability of aquifers and optimising the modelling of the retention phenomena and transport mechanism of particles in rocks. In karstic aquifers, fractures serve as preferential pathways for particles, thus allowing their rapid transport. The transport of particles and dissolved matter in fractures is governed by advection and dispersion which are influenced by several factors. The objective of this study is to contribute to a better understanding of the mechanisms of transport of solid particles and dissolved matter in fractures and the different factors influencing these mechanisms. For this purpose, an experimental program was developed to understand the influence of flow velocity, fracture aperture, fracture orientation and ionic strength on the transport of kaolinite particles and fluorescein dissolved tracer in fractured chalk samples. In addition, a numerical model was developed based on the Advection-Dispersion equation, to determine the transport parameters and deeply understand the particle-fracture surface interactions under different conditions. The results of this study revealed that the hydrodynamic effect is significant regardless of fracture orientation, with particle recovery increasing as flow velocity increases. Kaolinite particles travel faster than fluorescein due to the size exclusion effect and the higher dispersion coefficient of fluorescein. The attachment coefficient increases with flow velocity for all fracture orientations and is independent of fracture aperture. Conversely, the detachment coefficient, which is negligible for small flow velocities, is greater in smaller apertures due to higher shear stress. The findings showed that fracture orientation significantly affects the transport of kaolinite particles but has a negligible impact on fluorescein as a dissolved tracer. Increasing the fracture orientation vertically enhances particle recovery and dispersion, while the attachment coefficient decreases. The effect of ionic strength indicate that higher ionic strength increases particle retention and decreases the recovery rate. With the attachment coefficient exhibiting a linear increase and the detachment coefficient follows an exponential trend with increasing ionic strength.The study findings highlight the importance of considering high flow velocities in studying the hydrodynamic effect, fracture aperture, and IS effect in understanding micron-sized particle transport mechanisms in chalk fractures. It also contributes to the advancement of understanding the effect of fracture orientation on the transport of particles by using experimental methods. These understandings are essential for assessing risks to groundwater resources and advancing environmental protection measures
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Books on the topic "Fractured chalk"

1

Welch, Michael John, and Mikael Lüthje, eds. Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-35327-7.

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Revitalizing Gilbertown oil field: Characterization of fractured chalk and glauconitic sandstone reservoirs in an extensional fault system. Tuscaloosa, Ala: Geological Survey of Alabama, 2000.

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Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea: Understanding and Predicting Fracture Systems. Springer International Publishing AG, 2023.

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Book chapters on the topic "Fractured chalk"

1

Tran, Emily, and Noam Weisbrod. "Colloid and Colloid-Facilitated Transport in Fractured Chalk." In Springer Hydrogeology, 469–72. Cham: Springer International Publishing, 2020. http://dx.doi.org/10.1007/978-3-030-51148-7_22.

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Dahan, Ofer, Ronit Nativ, Eilon M. Adar, and Brian Berkowitz. "Water Flow and Solute Transport in Unsaturated Fractured Chalk." In Flow and Transport through Unsaturated Fractured Rock, 183–96. Washington, D. C.: American Geophysical Union, 2013. http://dx.doi.org/10.1029/gm042p0183.

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Arnon, Shai, Eilon Adar, Zeev Ronen, Alexander Yakirevich, and Ronit Nativ. "The Effect of Microbial Activity on Biodegradation of 2,4,6-Tribromophenol and Flow in Naturally Fractured Chalk Cores." In Dynamics of Fluids and Transport in Fractured Rock, 195–207. Washington, D. C.: American Geophysical Union, 2013. http://dx.doi.org/10.1029/162gm18.

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Glad, Aslaug C., Michael John Welch, Simon John Oldfield, Hamid M. Nick, Thomas M. Jørgensen, and Ole Rønø Clausen. "Geomechanical Modelling the Evolution of a Connected Natural Fracture Network to Explain Fluid Flow Variations Across a Fractured Chalk-Marl Reservoir." In Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea, 215–43. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-35327-7_8.

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Pennequin, Didier, Pierre-Yann David, Marie Servière, Nadia Amraoui, and Chrytèle Loiselet. "Hydro-System Flow Modelling for Water Resources Management in the Fractured and Karstified Chalk Aquifer Environment of Eastern Normandy." In EuroKarst 2016, Neuchâtel, 217–29. Cham: Springer International Publishing, 2017. http://dx.doi.org/10.1007/978-3-319-45465-8_22.

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Agarwal, Bijan, and Scott C. Key. "Reservoir Characterization of the Ekofisk Field: A Giant, Fractured Chalk Reservoir in the Norwegian North Sea-Phase 1, Reservoir Description." In Geology of Fossil Fuels - Oil and Gas, 191–204. London: CRC Press, 2021. http://dx.doi.org/10.1201/9780429087837-19.

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Lynggaard, Julie, and Christian F. Niordson. "Numerical Study on the Influence of Induced Hydraulic Fractures on Oil Production in a Line Drive." In Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea, 245–67. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-35327-7_9.

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Aabø, Tala Maria, Simon John Oldfield, Hemin Yuan, Janina Kammann, Erik Vest Sørensen, Lars Stemmerik, and Lars Nielsen. "Establishing a High Resolution 3D Fracture Dataset in Chalk: Possibilities and Obstacles Working with Outcrop Data." In Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea, 9–46. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-35327-7_2.

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Clausen, Ole Rønø, Kenni Dinesen Petersen, Torsten Hundebøl Hansen, and Katrine Juul Andresen. "Variations in the Porosity of the Chalk Group in the North Sea Basin Due to Subsidence Related Deformation." In Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea, 121–39. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-35327-7_5.

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Welch, Michael John. "Using Geomechanical Models to Simulate the Growth of the Fracture Network in the Ekofisk Formation of the Kraka Structure, Danish Central Graben." In Geomechanical Controls on Fracture Development in Chalk and Marl in the Danish North Sea, 167–213. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-35327-7_7.

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Conference papers on the topic "Fractured chalk"

1

Verbiest, M., O. Faÿ-Gomord, C. Allanic, E. Lasseur, B. Gauthier, and R. Swennen. "Mechanical stratigraphy of fractured chalks: evaluation of bias associated with fracture density through artificial fracture networks (AFN)." In Chalk 2018 Engineering in Chalk. ICE Publishing, 2018. http://dx.doi.org/10.1680/eiccf.64072.451.

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Fjelde, I., and A. V. Omekeh. "Surfactant Flooding in Fractured Chalk Reservoir." In IOR+ 2023. European Association of Geoscientists & Engineers, 2023. http://dx.doi.org/10.3997/2214-4609.202331011.

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L. Davis, T. "3D Seismic fractured reservoir characterization, Silo Field, Wyoming." In EAPG/AAPG Special Conference on Chalk. European Association of Geoscientists & Engineers, 1994. http://dx.doi.org/10.3997/2214-4609.201407539.

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Austad, T., S. Strand, E. J. Høgnesen, and P. Zhang. "Seawater as IOR Fluid in Fractured Chalk." In SPE International Symposium on Oilfield Chemistry. Society of Petroleum Engineers, 2005. http://dx.doi.org/10.2118/93000-ms.

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Gutierrez, Marte, Lloyd Tunbridge, Harald Hansteen, Axel Makurat, Nick Barton, and Geir Helge Landa. "Modelling of the compaction behaviour of fractured chalk." In Rock Mechanics in Petroleum Engineering. Society of Petroleum Engineers, 1994. http://dx.doi.org/10.2118/28130-ms.

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Zuta, J., I. Fjelde, and A. Maqsad. "CO2-Foam Processes in a Fractured Chalk Model." In IOR 2009 - 15th European Symposium on Improved Oil Recovery. European Association of Geoscientists & Engineers, 2009. http://dx.doi.org/10.3997/2214-4609.201404848.

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Alavian, Sayyed Ahmad, and Curtis Hays Whitson. "Modeling CO2 Injection in a Fractured Chalk Experiment." In SPE/EAGE Reservoir Characterization and Simulation Conference. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/125362-ms.

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Alavian, S. A., and C. H. Whitson. "Modeling CO2 Injection in a Fractured Chalk Experiment." In SPE/EAGE Reservoir Characterization & Simulation Conference. European Association of Geoscientists & Engineers, 2009. http://dx.doi.org/10.3997/2214-4609-pdb.170.spe125362.

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W. Teufel, L. "Influence of in situ stress on permeability of naturally fractured chalk reservoirs." In EAPG/AAPG Special Conference on Chalk. European Association of Geoscientists & Engineers, 1994. http://dx.doi.org/10.3997/2214-4609.201407537.

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B. Brahim, A., and R. T. J. Moody. "Chalks and chalk reservoirs of Tunisia with specific reference to the fractured reservoir of Sidi el Kilani." In EAPG/AAPG Special Conference on Chalk. European Association of Geoscientists & Engineers, 1994. http://dx.doi.org/10.3997/2214-4609.201407563.

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Reports on the topic "Fractured chalk"

1

Pashin, J. C., D. E. Raymond, A. K. Rindsberg, G. G. Alabi, R. E. Carroll, R. H. Groshong, and G. Jin. Area balance and strain in an extensional fault system: Strategies for improved oil recovery in fractured chalk, Gilbertown Field, southwestern Alabama. Final report, March 1996--September 1998. Office of Scientific and Technical Information (OSTI), December 1998. http://dx.doi.org/10.2172/307863.

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2

Pashin, J. C., D. E. Raymond, A. K. Rindsberg, G. G. Alabi, and R. H. Groshong. Area balance and strain in an extensional fault system: Strategies for improved oil recovery in fractured chalk, Gilbertown Field, southwestern Alabama. Annual report, March 1996--March 1997. Office of Scientific and Technical Information (OSTI), August 1997. http://dx.doi.org/10.2172/520833.

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3

Pashin, J. C., D. E. Raymond, A. K. Rindsberg, G. G. Alabi, and R. E. Carroll. Area balance and strain in an extensional fault system: Strategies for improved oil recovery in fractured chalk, Gilbertown Field, southwestern Alabama -- Year 2. Annual report, March 1997--March 1998. Office of Scientific and Technical Information (OSTI), September 1998. http://dx.doi.org/10.2172/296687.

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4

Warpinski, N. R., and L. W. Teufel. Effective-stress-law behavior of Austin chalk rocks for deformation and fracture conductivity. Office of Scientific and Technical Information (OSTI), August 1994. http://dx.doi.org/10.2172/10181952.

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