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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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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 ×10−9m2/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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Ireson, A. M., A. B. Butler, and H. S. Wheater. "Evidence for the onset and persistence with depth of preferential flow in unsaturated fractured porous media." Hydrology Research 43, no. 5 (April 12, 2012): 707–19. http://dx.doi.org/10.2166/nh.2012.030.
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Two distinct types of fracture flow can occur in unsaturated fractured porous media: non-preferential flow, whereby the fractures and matrix wet up in equilibrium, and preferential flow, whereby water in the fractures bypasses the matrix. This has important implications for how infiltration, recharge, groundwater flooding and contaminant transport are modelled. Taking the UK Chalk as a case study, we explore evidence for the occurrence of unsaturated preferential fracture flow, considering separately its initiation in the near surface, and persistence at 20–30 m depth. We postulate a link between the apparent hysteretic response of the Chalk soil moisture characteristic, which was observed and simulated, and the initiation of preferential recharge. Focusing on observed water table responses to an extreme rainfall event on 20th July 2007, we show by inverse modelling of recharge that preferential flow persisted to a depth of 20 m below ground level, but not to 30 m, resulting in markedly different water table responses at two boreholes. These findings both lend support to our conceptualisation. However, since the observations from which preferential flow can be inferred are few and are indirect, quantification of the controls on the onset and depth persistence of preferential flow remains a significant challenge.
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Rahman, Mostaquimur, and Rafael Rosolem. "Towards a simple representation of chalk hydrology in land surface modelling." Hydrology and Earth System Sciences 21, no. 1 (January 25, 2017): 459–71. http://dx.doi.org/10.5194/hess-21-459-2017.
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Abstract. Modelling and monitoring of hydrological processes in the unsaturated zone of chalk, a porous medium with fractures, is important to optimize water resource assessment and management practices in the United Kingdom (UK). However, incorporating the processes governing water movement through a chalk unsaturated zone in a numerical model is complicated mainly due to the fractured nature of chalk that creates high-velocity preferential flow paths in the subsurface. In general, flow through a chalk unsaturated zone is simulated using the dual-porosity concept, which often involves calibration of a relatively large number of model parameters, potentially undermining applications to large regions. In this study, a simplified parameterization, namely the Bulk Conductivity (BC) model, is proposed for simulating hydrology in a chalk unsaturated zone. This new parameterization introduces only two additional parameters (namely the macroporosity factor and the soil wetness threshold parameter for fracture flow activation) and uses the saturated hydraulic conductivity from the chalk matrix. The BC model is implemented in the Joint UK Land Environment Simulator (JULES) and applied to a study area encompassing the Kennet catchment in the southern UK. This parameterization is further calibrated at the point scale using soil moisture profile observations. The performance of the calibrated BC model in JULES is assessed and compared against the performance of both the default JULES parameterization and the uncalibrated version of the BC model implemented in JULES. Finally, the model performance at the catchment scale is evaluated against independent data sets (e.g. runoff and latent heat flux). The results demonstrate that the inclusion of the BC model in JULES improves simulated land surface mass and energy fluxes over the chalk-dominated Kennet catchment. Therefore, the simple approach described in this study may be used to incorporate the flow processes through a chalk unsaturated zone in large-scale land surface modelling applications.
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Keim, Dawn M., L. Jared West, and Noelle E. Odling. "Convergent Flow in Unsaturated Fractured Chalk." Vadose Zone Journal 11, no. 4 (November 2012): vzj2011.0146. http://dx.doi.org/10.2136/vzj2011.0146.
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Yeh, N. S., M. J. Davison, and R. Raghavan. "Fractured Well Responses in Heterogeneous Systems—Application to Devonian Shale and Austin Chalk Reservoirs." Journal of Energy Resources Technology 108, no. 2 (June 1, 1986): 120–30. http://dx.doi.org/10.1115/1.3231251.
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This paper presents new methods to analyze fractured well responses in heterogeneous reservoirs. We consider wells producing formations that are naturally fractured and use the idealizations proposed by Warren and Root (pseudosteady-state flow in the matrix-system) and by deSwaan-O (unsteady-state flow in the matrix-system) to model the naturally fractured reservoir. Pressure responses are correlated in a manner suitable for direct application of field data. Methods to determine fracture half-length are presented. Two field applications are discussed. The consequences of neglecting the heterogeneous character of the porous medium are also discussed.
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Shtober-Zisu, N., N. Tessler, A. Tsatskin, and N. Greenbaum. "Accelerated weathering of carbonate rocks following the 2010 wildfire on Mount Carmel, Israel." International Journal of Wildland Fire 24, no. 8 (2015): 1154. http://dx.doi.org/10.1071/wf14221.
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Massive destruction of carbonate rocks occurred on the slopes of Mount Carmel during the severe wildfire in 2010. The bedrock surfaces exhibited extensive exfoliation into flakes and spalls covering up to 80–100% of the exposed rocks; detached boulders were totally fractured or disintegrated. The fire affected six carbonate units – various types of chalk, limestone and dolomite. The burned flakes show a consistent tendency towards flatness, in all lithologies. The extent of the physical disruption depends on rock composition: the most severe response was found in the chalk formations covered by calcrete (Nari crusts). These rocks reacted by extreme exfoliation, at an average depth of 7.7 to 9.6 cm and a maximum depth of 20 cm. Scorched and blackened faces under the upper layer of spalls provide strong evidence that chalk breakdown took place at an early stage of the fire. It is possible to explain the extreme response of the chalks by the laminar structure of the Nari, which served as planes of weakness for the rock destruction. Three years after the fire, the rocks continue to exfoliate and break down internally. As the harder surface of the Nari deteriorates, the more brittle underlying chalk is exposed to erosion.
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Pastore, Nicola, Claudia Cherubini, and Concetta I. Giasi. "Kinematic diffusion approach to describe recharge phenomena in unsaturated fractured chalk." Journal of Hydrology and Hydromechanics 65, no. 3 (September 1, 2017): 287–96. http://dx.doi.org/10.1515/johh-2017-0033.
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AbstractWhen dealing with groundwater resources, a better knowledge of the hydrological processes governing flow in the unsaturated zone would improve the assessment of the natural aquifer recharge and its vulnerability to contamination. In North West Europe groundwater from unconfined chalk aquifers constitutes a major water resource, therefore the need for a good hydrological understanding of the chalk unsaturated zone is essential, as it is the main control for aquifer recharge. In the North Paris Basin, much of the recharge must pass through a regional chalk bed that is composed of a porous matrix with embedded fractures. The case study regards the role of the thick unsaturated zone of the Cretaceous chalk aquifer in Picardy (North of France) that controls the hydraulic response to rainfall. In order to describe the flow rate that reaches the water table, the kinematic diffusion theory has been applied that treats the unsaturated water flow equation as a wave equation composed of diffusive and gravitational components. The kinematic diffusion model has proved to be a convenient method to study groundwater recharge processes in that it was able to provide a satisfactory fitting both for rising and falling periods of water table fluctuation. It has also proved to give an answer to the question whether unsaturated flow can be described using the theory of kinematic waves. The answer to the question depends principally on the status of soil moisture. For higher values of hydraulic Peclet number (increasing saturation), the pressure wave velocities dominate and the preferential flow paths is provided by the shallow fractures in the vadose zone. With decreasing values of hydraulic Peclet number (increasing water tension), rapid wave velocities are mostly due to the diffusion of the flow wave. Diffusive phenomena are provided by matrix and fracture-matrix interaction.The use of a kinematic wave in this context constitutes a good simplified approach especially in cases when there is a lack of information concerning the hydraulic properties of the fractures/macropores close to saturation.
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Wang, Dongmei, Jin Zhang, Raymond Butler, and Kayode Olatunji. "Scaling Laboratory-Data Surfactant-Imbibition Rates to the Field in Fractured-Shale Formations." SPE Reservoir Evaluation & Engineering 19, no. 03 (February 19, 2016): 440–49. http://dx.doi.org/10.2118/178489-pa.
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Summary By use of existing methods, typical oil-recovery factors from the Bakken and other shale formations are low, typically less than 5% of original oil in place (OOIP). We are investigating the use of surfactant imbibition to enhance oil recovery from oil shale or other tight rocks. Much of our previous work has measured surfactant-imbibition rates and oil-recovery values in laboratory cores from the Bakken shale, Niobrara chalk/shale, and Eagle Ford formations. With optimized surfactant formulations at reservoir conditions, we observed oil-recovery values up to 20% of OOIP incremental over brine imbibition. However, whether surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil-production rates in a field setting. This, in turn, depends on three factors: the area of formation contact (through fractures and microfractures) when/where the surfactant formulation is introduced; the rates of surfactant imbibition; and the distances of surfactant imbibition into the rock and ultimate oil-displacement effectiveness. In this paper, we use analytical models to scale laboratory surfactant-imbibition rates to a field scale in fractured-shale formations. In laboratory cores, we observed imbibition rates that varied inversely with time. Dimensionless scaling groups were applied that compensate for the effects of sample size and shape, boundary conditions, permeability, porosity, and viscosity. Calculations were made of available fracture area, assuming typical horizontal-well lengths and transverse-induced-fracture spacing in typical Bakken wells. These fracture areas were coupled with our imbibition-scaling groups to estimate oil-recovery rates in a field setting. Considering realistic timing, surfactant imbibition will generally not proceed more than a few meters into the low-permeability shale/chalk formations. These calculations indicate insufficient fracture area to provide a viable imbibition process if only the induced-fracture area is considered. However, recent results from geological, microseismic, and pressure-transient studies indicate considerably greater area associated with natural microfractures in our target formations. When the increased area suggested by the presence of microfractures is included in our analyses, the surfactant-imbibition process appears quite promising.
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Tang, Guo-Qing, and Abbas Firoozabadi. "Effect of Pressure Gradient and Initial Water Saturation on Water Injection in Water-Wet and Mixed-Wet Fractured Porous Media." SPE Reservoir Evaluation & Engineering 4, no. 06 (December 1, 2001): 516–24. http://dx.doi.org/10.2118/74711-pa.
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Summary A systematic study of the effect of wettability and initial water saturation on water injection and imbibition is made in Kansas outcrop chalk samples. (Kansas outcrop chalk is very similar to the rock matrix of the North Sea fractured chalk reservoirs.) Water-injection tests were conducted at different pressure gradients to simulate the effect of gravity (that is, negative Pc) on recovery. Based on a large number of carefully conducted tests, the following conclusions are drawn:Initial water saturation has a pronounced effect on water injection in an intermediate-wet chalk. This effect is much less pronounced for a strongly water-wet chalk. The effects are also in opposite directions.Pressure gradients (which simulate the negative Pc effect) have a very strong effect on water-injection performance in an intermediate-wet chalk. Our interpretation of these experiments leads to the conclusion that recovery from the chalk reservoirs may be nearly independent of wettability state. The results from the experiments also reveal that there is no relation between laboratory measurements of spontaneous imbibition and field performance of mixed-wet reservoirs, even when the wettability state is perfectly restored in the laboratory. Introduction Wettability state and its effect on oil recovery has been the subject of numerous studies since 1928.1–8 However, major issues of oil recovery related to wettability remain unresolved. A major parameter of wettability is contact angle. Some authors have even questioned the usefulness of contact angle in defining wettability.5 The state of wettability in some reservoirs can vary significantly with depth and rock properties. Jerauld and Rathmell4 presented data showing that there is a clear dependence of residual oil saturation upon depth. In the Prudhoe Bay reservoirs, residual oil saturation to waterflood decreases with depth while the reservoir wettability changes from less-water-wet to more-water-wet conditions with an increase in depth. In the Ekofisk field, which is similar to the Prudhoe Bay reservoirs, there is a systematic change of wettability with depth; water-wetting increases with depth. Spontaneous water imbibition in the laboratory shows poor recovery in the cores from the upper part of the reservoir. However, field data from a long period of waterflooding reveal a low water cut. The openhole logging results on sidetracks also show oil recoveries in excess of the laboratory imbibition measurements.9 Despite wettability variation in the Ekofisk field, residual oil saturation is low and independent of the depth. In the Ekofisk field, from the commencement of water injection in 1987, the oil rate has increased from approximately 75,000 B/D to approximately 250,000 B/D in 1997.10 Research concerning the effect of gravity forces on water injection in fractured reservoirs is rather limited. In 1968, Hamon11 found that oil recovery by water drainage in oil-wet fractured porous media could be significant depending on matrix permeability. Similar results were reported recently by Putra et al.12 Zhou et al.13 observed that a decrease in water-wetness of Berea sandstone by adsorption of polar oil components could increase oil recovery by waterflooding. Graue et al.14 obtained similar results for low permeability chalk. The effect of initial water saturation on oil recovery remains controversial. Brown15 studied the effect of initial water saturation on waterflood efficiency. He emphasized that connate water (retained as water film and in small pores) could become re-mobilized when water is invading. His experimental results showed that flow of connate water improves waterflood recovery. Skauge et al.16 studied the influence of connate water on oil recovery by gas gravity drainage using chalk samples. The maximum oil recovery was obtained at approximately 30% initial water saturation. Viksund et al.17 carried out spontaneous imbibition tests with strongly water-wet chalk. A maximum oil recovery was obtained at approximately 34% of initial water saturation. However, results from Narahara et al.18 are much different. They measured gas and oil relative permeability in water-wet and mixed-wet Berea at various initial water saturations and found that gas and oil relative permeabilities are independent of initial water saturation. Zhou et al.19 observed that for a crude-oil/brine/rock system, imbibition recovery increased with initial water saturation, but waterflood recovery decreased with initial water saturation. A long induction time (ranging from 10 to 1,000 minutes) was observed in imbibition tests after the cores were aged with crude oil at T=88°C for 10 days. The main objective of this work is to understand the mechanisms that lead to a vast difference between laboratory spontaneous imbibition measurements and field performance. For this purpose, we have conducted an extensive set of laboratory measurements on Kansas outcrop chalk with a porosity of approximately 30% and a permeability of some 0.5 md. Waterflood and spontaneous imbibition performances of the Kansas outcrop chalk are studied before and after wettability alteration. We have used Kansas chalk because of its similarity to the chalk matrix rock from the Ekofisk chalk field. In this paper, we present the experimental results that include wettability alteration by chemical adsorption, water injection, and spontaneous imbibition in strongly water-wet and weakly water-wet chalks. In some of the experiments, an initial water saturation was present. In the injection experiments, the pressure gradient is varied to simulate the effect of gravity on recovery. Materials and Experimental Setup Fluids and Chemicals. Normal decane (n-C10) with a density of 0.73 g/cm3 and a viscosity of 0.92 cp at 24°C is used as the oil phase. Stearic acid (octadecanoic acid), purchased from Sigma with a purity of 99% and a molecular weight of 284.5, is used as a surfactant to alter the chalk wettability. This chemical is dissolved in oil (n-C10) to prepare the stearic acid solution. Solubility tests at room temperature show that stearic acid dissolves in oil when the concentration is less than 2,000 ppm, but it hardly dissolves in water. NaCl and CaCl2 are used to prepare the 0.1% NaCl+0.1% CaCl2 brine solution, which is used both for injection water and for the establishment of initial water saturation. The viscosity and density of the brine are 1.0 cp and 1.02 g/cm3 at 24°, respectively. Fluids and Chemicals. Normal decane (n-C10) with a density of 0.73 g/cm3 and a viscosity of 0.92 cp at 24°C is used as the oil phase. Stearic acid (octadecanoic acid), purchased from Sigma with a purity of 99% and a molecular weight of 284.5, is used as a surfactant to alter the chalk wettability. This chemical is dissolved in oil (n-C10) to prepare the stearic acid solution. Solubility tests at room temperature show that stearic acid dissolves in oil when the concentration is less than 2,000 ppm, but it hardly dissolves in water. NaCl and CaCl2 are used to prepare the 0.1% NaCl+0.1% CaCl2 brine solution, which is used both for injection water and for the establishment of initial water saturation. The viscosity and density of the brine are 1.0 cp and 1.02 g/cm3 at 24°, respectively.
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Kallesten, Emanuela, Pål Østebø Andersen, Dhruvit Satishchandra Berawala, Reidar Inge Korsnes, Merete Vadla Madland, Edvard Omdal, and Udo Zimmermann. "Modeling of Permeability and Strain Evolution in Chemical Creep Compaction Experiments with Fractured and Unfractured Chalk Cores Conducted at Reservoir Conditions." SPE Journal 25, no. 05 (April 16, 2020): 2710–28. http://dx.doi.org/10.2118/197371-pa.
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Summary Understanding the effect of typical water-related improved oil recovery techniques is fundamental to the development of chalk reservoirs on the Norwegian Continental Shelf (NCS). We investigate the contribution and interplay of key parameters influencing the reservoir's flow and storativity properties, such as effective stresses, injecting fluid chemistry, and geomechanical deformation. This is done by developing a mathematical model that is applied to systematically interpret experimental data. The gained understanding is useful for improved prediction of permeability development during field life. The model we present is for a fractured chalk core whereby fluids can flow through the matrix and fracture domains in parallel. The core is subject to a constant effective stress above the yield, resulting in time-dependent compaction (creep) of the matrix, while the fracture does not compact. Reactive brine injection causes enhanced compaction but also permeability alteration. This again causes a redistribution of injected flow between the two domains. A previous version of the model parameterizing the relation between chemistry and compaction is here extended to quantify the effect on permeability and see the effect of flow in a fracture-matrix geometry. A vast set of experimental data were used to quantify the relations in the model and demonstrate its usefulness to interpret experimental data. Two outcrop chalk types (Aalborg and Liège) being tested at 130°C and various concentrations of Ca-Mg-Na-Cl brines are considered. However, assumptions were required, especially regarding the fracture behavior because directly representative data were not available. The tests with inert injecting brine were used to quantify the effect of matrix and fracture mechanical compaction on permeability trends. To be able to explain the tests with reactive brine, an important finding is that permeability not only decreased because of enhanced porosity reduction but also because of a quantifiable chemistry-related process (dissolution/precipitation). Sensitivity analyses were performed regarding varying fracture width, injection rate, and chemistry concentration to evaluate the effect on chemical creep compaction and permeability evolution in fractured cores. The model can be used to highlight parameters with great influence on the experimental results. An accurate quantification of such parameters will contribute to refining laboratory experiments and will provide valuable data for upscaling and field application.
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Alavian, S. A., and C. H. Whitson. "Numerical modeling CO2 injection in a fractured chalk experiment." Journal of Petroleum Science and Engineering 77, no. 2 (May 2011): 172–82. http://dx.doi.org/10.1016/j.petrol.2011.02.014.
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Arnon, Shai, Eilon Adar, Zeev Ronen, Ali Nejidat, Alexander Yakirevich, and Ronit Nativ. "Biodegradation of 2,4,6-Tribromophenol during Transport in Fractured Chalk." Environmental Science & Technology 39, no. 3 (February 2005): 748–55. http://dx.doi.org/10.1021/es0491578.
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Weisbrod, Noam, Ofer Dahan, and Eilon M. Adar. "Particle transport in unsaturated fractured chalk under arid conditions." Journal of Contaminant Hydrology 56, no. 1-2 (May 2002): 117–36. http://dx.doi.org/10.1016/s0169-7722(01)00199-1.
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Adar, Eilon, and Ronit Nativ. "Isotopes as tracers in a contaminated fractured chalk aquitard." Journal of Contaminant Hydrology 65, no. 1-2 (August 2003): 19–39. http://dx.doi.org/10.1016/s0169-7722(02)00237-1.
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Ghasemi, M., W. Astutik, S. Alavian, C. H. Whitson, L. Sigalas, D. Olsen, and V. S. Suicmez. "Tertiary-CO2 flooding in a composite fractured-chalk reservoir." Journal of Petroleum Science and Engineering 160 (January 2018): 327–40. http://dx.doi.org/10.1016/j.petrol.2017.10.054.
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Wefer-Roehl, A., E. R. Graber, M. D. Borisover, E. Adar, R. Nativ, and Z. Ronen. "Sorption of organic contaminants in a fractured chalk formation." Chemosphere 44, no. 5 (August 2001): 1121–30. http://dx.doi.org/10.1016/s0045-6535(00)00309-x.
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Ezra, Shai, Shimon Feinstein, Alex Yakirevich, Eilon Adar, and Itzhak Bilkis. "Retardation of organo-bromides in a fractured chalk aquitard." Journal of Contaminant Hydrology 86, no. 3-4 (August 2006): 195–214. http://dx.doi.org/10.1016/j.jconhyd.2006.02.016.
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Witthuser, K., B. Reichert, and H. Hotzl. "Contaminant Transport in Fractured Chalk: Laboratory and Field Experiments." Ground Water 41, no. 6 (November 2003): 806–15. http://dx.doi.org/10.1111/j.1745-6584.2003.tb02421.x.
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Casabianca, D., R. J. H. Jolly, and R. Pollard. "The Machar Oil Field: waterflooding a fractured chalk reservoir." Geological Society, London, Special Publications 270, no. 1 (2007): 171–91. http://dx.doi.org/10.1144/gsl.sp.2007.270.01.12.
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Champ, D. R., and J. Schroeter. "Bacterial Transport in Fractured Rock – A Field-Scale Tracer Test at the Chalk River Nuclear Laboratories." Water Science and Technology 20, no. 11-12 (November 1, 1988): 81–87. http://dx.doi.org/10.2166/wst.1988.0269.
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The potential for transport of bacteria by groundwater in fractured crystalline rock was assessed in a series of field-scale tracer tests. The breakthrough curves for injected Escherichla coll and “non-reactive” particle tracers were compared with those for conservative inorganic and radioactive tracers. Rapid transport, relative to the conservative tracers, of both bacteria and non-reactive particles was observed. The first appearance of both was with, or slightly before, the conservative tracers for water movement. Removal of the bacteria and particles by filtration processes occurred and was quantified through the calculation of filter factors. The filtration process in this fracture system is similar to that found in a gravel aquifer. From the results we can conclude that particulate contaminants can be very rapidly transported in fracture systems and that continuing sources of contamination could lead to relatively high local concentrations of particulate contaminants compared with the average at any given distance from the source. It was also concluded that the use of traditional conservative tracers, for water movement, to assess the potential for movement of particulate contaminants could lead to significant underestimates of exposure to particulate contaminants due to consumption of water from water recovery wells located in fractured media.
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Carpenter, Chris. "Visualization of CO2 EOR by Molecular Diffusion in Fractured Chalk." Journal of Petroleum Technology 67, no. 07 (July 1, 2015): 122–24. http://dx.doi.org/10.2118/0715-0122-jpt.
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Mathias, S. A., A. P. Butler, T. C. Atkinson, S. Kachi, and R. S. Ward. "A parameter identifiability study of two chalk tracer tests." Hydrology and Earth System Sciences Discussions 3, no. 4 (August 29, 2006): 2437–71. http://dx.doi.org/10.5194/hessd-3-2437-2006.
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Abstract. As with most fractured rock formations, Chalk is highly heterogeneous. Therefore, meaningful estimates of model parameters must be obtained at a scale comparable with the process of concern. These are frequently obtained by calibrating an appropriate model to observed concentration-time data from radially convergent tracer tests (RCTT). Arguably, an appropriate model should consider radially convergent dispersion (RCD) and Fickian matrix diffusion. Such a model requires the estimation of at least four parameters. A question arises as to whether or not this level of model complexity is supported by the information contained within the calibration data. Generally modellers have not answered this question due to the calibration techniques employed. A dual-porosity model with RCD was calibrated to two tracer test datasets from different UK Chalk aquifers. A multivariate sensitivity analysis, which assumed only a priori upper and lower bounds for each model parameter, was undertaken. Rather than looking at measures of uncertainty, the shape of the multivariate objective function surface was used to determine whether a parameter was identifiable. Non-identifiable parameters were then removed and the procedure was repeated until all remaining parameters were identifiable. It was found that the single fracture model (SFM) (which ignores mechanical dispersion) obtained the best mass recovery, excellent model performance and best parameter identifiability in both the tests studied. However, there was no objective evidence suggesting that mechanical dispersion was negligible. Moreover, the SFM (with just two parameters) was found to be good at approximating the Single Fracture Dispersion Model SFDM (with three parameters) when different, and potentially erroneous parameters, were used. Overall, this study emphasises the importance of adequate temporal sampling of breakthrough curve data prior to peak concentrations, to ensure adequate characterisation of mechanical dispersion processes, and continued monitoring afterwards, to ensure adequate characterisation of fracture spacing (where possible), when parameterising dual-porosity solute transport models.
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Payne, S. S., M. H. Worthington, N. E. Odling, and L. J. West. "Estimating permeability from field measurements of seismic attenuation in fractured chalk." Geophysical Prospecting 55, no. 5 (September 2007): 643–53. http://dx.doi.org/10.1111/j.1365-2478.2007.00643.x.
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Arnon, Shai, Eilon Adar, Zeev Ronen, Alexander Yakirevich, and Ronit Nativ. "Impact of microbial activity on the hydraulic properties of fractured chalk." Journal of Contaminant Hydrology 76, no. 3-4 (February 2005): 315–36. http://dx.doi.org/10.1016/j.jconhyd.2004.11.004.
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Odling, N. E., L. J. West, S. Hartmann, and A. Kilpatrick. "Fractional flow in fractured chalk; a flow and tracer test revisited." Journal of Contaminant Hydrology 147 (April 2013): 96–111. http://dx.doi.org/10.1016/j.jconhyd.2013.02.003.
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Nativ, R., E. M. Adar, and A. Becker. "Designing a Monitoring Network for Contaminated Ground Water in Fractured Chalk." Ground Water 37, no. 1 (January 1999): 38–47. http://dx.doi.org/10.1111/j.1745-6584.1999.tb00956.x.
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Sagi, D. A., M. Arnhild, and J. F. Karlo. "Quantifying fracture density and connectivity of fractured chalk reservoirs from core samples: implications for fluid flow." Geological Society, London, Special Publications 374, no. 1 (June 26, 2013): 97–111. http://dx.doi.org/10.1144/sp374.16.
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Kurtzman, Daniel, Ronit Nativ, and Eilon M. Adar. "Flow and transport predictions during multi-borehole tests in fractured chalk using discrete fracture network models." Hydrogeology Journal 15, no. 8 (July 24, 2007): 1629–42. http://dx.doi.org/10.1007/s10040-007-0205-x.
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Baniak, G. M., Z. Sayer, H. Patterson, R. Gooder, N. Laing, and A. Love. "The Mungo Field, Blocks 22/20a and 23/16a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 537–49. http://dx.doi.org/10.1144/m52-2018-82.
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AbstractThe Mungo Field is a mature producing asset located in the UK Central North Sea. Discovered in 1989 and brought on production in 1998, it is the largest field within the Eastern Trough Area Project (ETAP). Production occurs via a normally unattended installation and is tied back to the ETAP Central Processing Facility. It is a pierced, four-way dip closure against a salt diapir. Light oil is present within steeply dipping Late Paleocene sandstone and Early Paleocene–Late Cretaceous chalk intervals. The vertical relief of the salt stock is around 1500 m TVDSS and top of the salt canopy lies at about 1350 m TVDSS.The Paleocene sandstones (Forties Sandstone Member of the Sele Formation, Lista Formation and Maureen Formation) make up the primary reservoir and have been extensively developed in three phases since 1998 under water injection and natural depletion. The sandstones were deposited as deep-water turbidite complexes (submarine fans with local channels) on and around the flanks of the rising salt diapir. More recently, successful stimulation of the Chalk Group, coupled with re-evaluation of core and well-log data, has indicated that economic production rates could also be achieved from the underlying fractured chalk reservoir.
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Agarwal, B., H. Hermansen, J. E. Sylte, and L. K. Thomas. "Reservoir Characterization of Ekofisk Field: A Giant, Fractured Chalk Reservoir in the Norwegian North Sea—History Match." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 534–43. http://dx.doi.org/10.2118/68096-pa.
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Summary The Ekofisk reservoir is a high porosity, low matrix permeability naturally fractured chalk. Fluid flow is largely governed by the distribution, orientation, and interconnectivity of the natural fracture system associated with complex structure and reservoir distribution. Because of the impact heterogeneity has on preferential fluid-flow direction, significant attention was given to capturing as much of the intrinsic heterogeneity as possible, both laterally and vertically, in the new three-dimensionally geological model. Anon-uniform simulation mesh was defined for the fluid-flow model with a grid size of 450 ft×450 ft in the crestal area of the field and increasing towards the flanks. A flow-based upscaling technique was then applied to preserve the heterogeneity from the geological to the fluid-flow model. Because of the complexity of the Ekofisk field, with its numerous faults and fracture networks, anisotropy was one of the primary attributes calibrated to achieve an individual well and field history match. However, faults and fault sealing factors, vertical permeability, pseudorelative permeability curves, bubblepoint pressure correlations, local permeability, and rock compressibility were also key parameters in the history match, and are presented in this paper. A brief discussion on the preliminary implementation of water-induced compaction is included. Introduction The Ekofisk field is a prolific field discovered in 1969 that is located in the Norwegian sector of the North Sea. The reservoir consists of two fine-grained limestone producing formations, the Ekofisk formation (Danian Age)and the Tor formation (Maastrichtian Age), separated by a thin, impermeable Tight Zone. The reservoir was initially overpressured and contained an under saturated oil at 7,120 psi and 268°F at a datum elevation of 10,400 ftsubsea. The bubblepoint pressure was approximately 5,545 psig. Production started from the chalks in 1971. Current estimates from the reservoir characterization project indicate about 7 billion barrels of oil originally in place. Production as of the end of 1998 from 76 deviated and horizontal wells was 310,000 BOPD and 510 MMcf/D of gas. Reinjection of natural gas in excess of sales has been ongoing in Ekofisk since 1975 with 1.3 Tcf of gas injected to date. Eight wells were initially completed for gas injection service, with five of the original gas injection wells being recompleted as production wells through time. A pilot water injection project was initiated in 1981 in the highly fractured Tor formation1 and in the Lower Ekofisk in1986.2 Fieldwide water injection began in 1987.3 Current water injection rates are 800,000 BWPD into 37 active water injection wells. A number of additional improved oil recovery techniques are being evaluated, and a water-alternating-gas (WAG) pilot in the southern area of the field was attempted. Fig. 1 shows a structure map of the Ekofisk field drawn on the top Ekofisk formation. Reservoir characterization of Ekofisk was directed at gaining a detailed understanding of reservoir hydrocarbon volumes, the architecture of the reservoir, and at fully describing the heterogeneity and anisotropy of reservoir parameters.4,5 Because water breakthrough not consistent with expectations has been observed in areas of the field, it is important that the highest degree of heterogeneity be represented in the flow model. This is especially significant given that the Ekofisk field is currently undergoing a major field redevelopment in which 45 new wells will be drilled before the end of 2003. To date a total of 25 new wells have already been drilled and are currently on production. The history match of the Ekofisk reservoir characterization fluid-flow model was completed in September 1997 after a period of approximately 12 months of intense work. The complexity of the Ekofisk field, with its numerous faults and fracture networks, provided quite a challenge in matching the 25 years worth of production and performance data. The heterogeneity that was captured in the three-dimensional (3-D) geological model, and preserved in the upscaling process to the fluid-flow model, proved to be the key to being able to match individual well performance. In general, a very good history match was achieved on both a field and platform basis, and on an individual well basis. Fluid-Flow Model Model Selection. In a fractured reservoir like Ekofisk, the large scale fluid-flow characteristics are primarily controlled by the distribution, orientation, and interconnectivity of the natural fracture system. One of the challenges in modeling this type of reservoir is to account for the fluid transfer between the high permeability fractures and the low permeability matrix blocks that contain the bulk of the pore volume.6 Full field modeling of the Ekofisk field is performed with a single porosity model that uses effective permeabilities for interblock flow and pseudorelative permeability functions to account for matrix-fracture and matrix-matrix interactions. Model Comparison. The main variation between the Ekofisk reservoir characterization (ERC) and previous fluid-flow models relates to improvement in the description of heterogeneity and anisotropy. These differences include permeability, simulation grid orientation, cell sizes and layering, and non-neighbor connections. Permeability in the ERC model is linked directly to fracture intensity through an algorithm developed based on the log linear relationship between fracture spacing (intensity) data from core and well test effective permeability.4 The orientation of the flow model was revised to better reflect current fault/stress regimes and, in turn, permeability and permeability anisotropy. Fault trend/system analysis indicates three primary fault systems, and orientation of the grid along the major axis of the structure and the NNW-SSE strike-slip faults was determined to be the optimum alignment. Typical well spacing in Ekofisk is 1600 ft and the average grid cell size in the crest of the field was established based on two criteria: the desire to have at least two grid cells between production and injection wells and the need to optimize the number of cells to allow the model to be used as an active tool in future field development decisions. The cells were 450 ft×450 ft as compared to the previous model definition of 600 ft×600 ft.
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Brown, David A. "The flow of water and displacement of hydrocarbons in fractured chalk reservoirs." Geological Society, London, Special Publications 34, no. 1 (1987): 201–18. http://dx.doi.org/10.1144/gsl.sp.1987.034.01.14.
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Ghasemi, M., W. Astutik, S. A. Alavian, C. H. Whitson, L. Sigalas, D. Olsen, and V. S. Suicmez. "Impact of pressure on tertiary-CO2 flooding in a fractured chalk reservoir." Journal of Petroleum Science and Engineering 167 (August 2018): 406–17. http://dx.doi.org/10.1016/j.petrol.2018.04.022.
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Polak, Amir, Ronit Nativ, and Rony Wallach. "Matrix diffusion in northern Negev fractured chalk and its correlation to porosity." Journal of Hydrology 268, no. 1-4 (November 2002): 203–13. http://dx.doi.org/10.1016/s0022-1694(02)00176-2.
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FOSTER, P. T., and P. R. RATTEY. "The evolution of a fractured chalk reservoir: Machar Oilfield, UK North Sea." Geological Society, London, Petroleum Geology Conference series 4, no. 1 (1993): 1445–52. http://dx.doi.org/10.1144/0041445.
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De Smedt, Florimond. "Analytical Solution for Fractional Well Flow in a Double-Porosity Aquifer with Fractional Transient Exchange between Matrix and Fractures." Water 14, no. 3 (February 2, 2022): 456. http://dx.doi.org/10.3390/w14030456.
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An analytical solution is presented for groundwater flow to a well in an aquifer with double-porosity behavior and transient transfer between fractures and matrix. The solution is valid for fractional flow dimensions including linear, cylindrical or spherical flow to the well and for fractional inter-porosity diffusive transfer including release from storage in infinite slabs, infinite cylinders or spherical matrix blocks. Approximations are also presented for small and large times that are easy to evaluate in practice. The solution can be used to analyze pumping tests via coupling with a parameter estimation code. The utility of the method is demonstrated by a practical example using data from a pumping test performed in a fractured chalk aquifer. The analytical solution allows the accurate modeling of pumping tests and the estimation of aquifer parameters that are statistically significant and physically relevant.
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Ghasemi, M., W. Astutik, S. Alavian, C. H. Whitson, L. Sigalas, D. Olsen, and V. S. Suicmez. "Experimental and numerical investigation of tertiary-CO2 flooding in a fractured chalk reservoir." Journal of Petroleum Science and Engineering 164 (May 2018): 485–500. http://dx.doi.org/10.1016/j.petrol.2018.01.058.
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Abdalla, Fathy A., Barbara Reichert, and Kai Witthueser. "Anthropogenic contaminants as tracers in fractured chalk aquifer: transport mechanisms and analytical modeling." Arabian Journal of Geosciences 4, no. 5-6 (September 1, 2009): 755–62. http://dx.doi.org/10.1007/s12517-009-0086-5.
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