Academic literature on the topic 'Poorly cemented sands'
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Journal articles on the topic "Poorly cemented sands"
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Hashemi, S. S., N. Melkoumian, A. Taheri, and M. Jaksa. "The failure behaviour of poorly cemented sands at a borehole wall using laboratory tests." International Journal of Rock Mechanics and Mining Sciences 77 (July 2015): 348–57. http://dx.doi.org/10.1016/j.ijrmms.2015.03.037.
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Hassane, Amadou, Chukwuemeka Ngozi Ehirim, and Tamunonengiyeofori Dagogo. "Rock physics diagnostic of Eocene Sokor-1 reservoir in Termit subbasin, Niger." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 20, 2021): 3361–71. http://dx.doi.org/10.1007/s13202-021-01259-2.
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AbstractEocene Sokor-1 reservoir is intrinsically heterogeneous and characterized by low-contrast low-resistivity log responses in parts of the Termit subbasin. Discriminating lithology and fluid properties using petrophysics alone is complicated and undermines reservoir characterization. Petrophysics and rock physics were integrated through rock physics diagnostics (RPDs) modeling for detailed description of the reservoir microstructure and quality in the subbasin. Petrophysical evaluation shows that Sokor-1 sand_5 interval has good petrophysical properties across wells and prolific in hydrocarbons. RPD analysis revealed that this sand interval could be best described by the constant cement sand model in wells_2, _3, _5 and _9 and friable sand model in well_4. The matrix structure varied mostly from clean and well-sorted unconsolidated sands as well as consolidated and cemented sandstones to deteriorating and poorly sorted shaly sands and shales/mudstones. The rock physics template built based on the constant cement sand model for representative well_2 diagnosed hydrocarbon bearing sands with low Vp/Vs and medium-to-high impedance signatures. Brine shaly sands and shales/mudstones were diagnosed with moderate Vp/Vs and medium-to-high impedance and high Vp/Vs and medium impedance, respectively. These results reveal that hydrocarbon sands and brine shaly sands cannot be distinctively discriminated by the impedance property, since they exhibit similar impedance characteristics. However, hydrocarbon sands, brine shaly sands and shales/mudstones were completely discriminated by characteristic Vp/Vs property. These results demonstrate the robust application of rock physics diagnostic modeling in quantitative reservoir characterization and may be quite useful in undrilled locations in the subbasin and fields with similar geologic settings.
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Hashemi, S. S., and N. Melkoumian. "A strain energy criterion based on grain dislodgment at borehole wall in poorly cemented sands." International Journal of Rock Mechanics and Mining Sciences 87 (September 2016): 90–103. http://dx.doi.org/10.1016/j.ijrmms.2016.05.013.
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Hashemi, S. S., A. Taheri, and N. Melkoumian. "An experimental study on the relationship between localised zones and borehole instability in poorly cemented sands." Journal of Petroleum Science and Engineering 135 (November 2015): 101–17. http://dx.doi.org/10.1016/j.petrol.2015.08.009.
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Dvorkin, Jack, and Amos Nur. "Elasticity of high‐porosity sandstones: Theory for two North Sea data sets." GEOPHYSICS 61, no. 5 (September 1996): 1363–70. http://dx.doi.org/10.1190/1.1444059.
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We have analyzed two laboratory data sets obtained on high‐porosity rock samples from the North Sea. The velocities observed are unusual in that they seem to disagree with some simple models based on porosity. On the other hand, the rocks are unusually poorly‐cemented (for laboratory studies, at least), and we investigate the likelihood that this is the cause of the disagreement. One set of rocks, from the Oseberg Field, is made of slightly cemented quartz sands. We find that we can model their dry‐rock velocities using a cementation theory where the grains mechanically interact through cement at the grain boundaries. This model does not allow for pressure dependence. The other set of rocks, from the Troll Field, is almost completely uncemented. The grains are held together by the applied confining pressure. In this case, a lower bound for the velocities can be found by using the Hertz‐Mindlin contact theory (interaction of uncemented spheres) to predict velocities at a critical porosity, combined with the modified Hashin‐Strikman lower bound for other porosities. This model, which allows for pressure‐dependence, also predicts fairly large Poisson’s ratios for saturated rocks, such as those observed in the measurements. The usefulness of these theories may be in estimating the nature of cement in rocks from measurements such as sonic logs. The theories could help indicate sand strength in poorly consolidated formations and predict the likelihood of sand production. Both theoretical methods have analytical expressions and are ready for practical use.
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Aubrecht, Roman, Tomáš Lánczos, Branislav Šmida, Charles Brewer-Carias, Federico Mayoral, Jan Schlögl, Marek Audy, Lukáš Vlček, Lubomirq Kováčik, and Miloš Gregor. "Venezuelan sandstone caves: a new view on their genesis, hydrogeology and speleothems." Geologia Croatica 61, no. 2-3 (December 25, 2008): 345–62. http://dx.doi.org/10.4154/gc.2008.27.
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Caves in arenites of the Roraima Group in Venezuela have been explored on the Chimantá and Roraima plateaus (tepuis). Geological and geomorphological research showed that the most feasible method of caves genesis was the winnowing and erosion of unlithified or poorly lithified arenites. The unlithified arenitic beds were isolated by well-cemented overlying and underlying rocks. There is a sharp contrast between these well-lithified rocks and the loose sands which form the poorly lithified to unlithified beds. They are only penetrated by strongly lithified pillars which were cemented by vertical finger flow of the diagenetic fluids from the overlying beds. Such finger flow is only typical for loose sands and soils where there is a sharp difference in hydraulic conductivity. The pillars exhibit no signs of further dissolution. The caves form when the flowing water accesses the poorly lithified beds through clefts/crevices. Collapse of several superimposed winnowed-horizons can create huge subterranean spaces. Futher upward propagation of the collapses can lead to large collapse zones which are commonly observed on the tepuis. Dissolution is also present but it probably plays neither a trigger role, nor a volumetrically important role in the cave-forming processes. The strongest dissolution/reprecipitation agent is condensed atmospheric moisture which is most likely the main agent contributing to growth of siliceous speleothems. As such, it can be active only after, but not before the cave is created. Siliceous speleothems are mostly microbialites except for some normal stalactites, cobweb stalactites and flowstones which are formed inorganically. They consist of two main types: 1. fine-laminated columnar stromatolite formed by silicified filamentous microbes (either heterotrophic filamentous bacteria or cyanobacteria) and 2. a porous peloidal stromatolite formed by Nostoc-type cyanobacteria. The initial stages of encrusted shrubs and mats of microbes were observed, too, but the surrounding arenitic substrate was intact. This is strong evidence for the microbial mediation of silica precipitation.
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Pedchenko, Larysa, Nazar Pedchenko, Jerzy Kicki, and Mykhailo Pedchenko. "Improvement of the bitumen extraction technology from bituminous sand deposits." E3S Web of Conferences 201 (2020): 01004. http://dx.doi.org/10.1051/e3sconf/202020101004.
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Today considerable experience in the development of tar sands is accumulated. However, well-known mining technologies do not cover the entire depth range of natural bitumen deposits. In addition, there are significant energy-intensive technologies and negative environmental impacts. In view of this, the purpose of this work is to improve the method of extracting natural bitumen in site for a deposit interval of 75 – 200 m and to substantiate the basic technological scheme of this method. The proposed method of extracting bitumen from poorly cemented reservoirs in the depth range of 50 – 400 m provides: creation of artificial mine working; the transfer of the rock into the water mixture composition under the action of high pressure jets of a heated mixture of water, a hydrocarbon solvent and a flotation agent; separation from the rock and concentration of bitumen in the production as a result of its heating, dissolution and flotation; selection of depleted bitum slurry from the mine working by gas lift method. The proposed method of extracting bitumen is the transfer of the rock at the site of its occurrence to the suspension condition on the excavation created by the hydraulic production method, separation and concentration of bitumen by dissolving it with a heated hydrocarbon solvent and a flotation agent (hydrocarbon reagents), and extraction in the composition of depleted rock slurry to the surface by the gas lift method. As the preliminary calculations show, the proposed method will allow the efficient extraction of bitumen and highly viscous oil from weakly cemented reservoirs in the depth range of 50 – 400 m. Also, the proposed technology creates the preconditions for the development of oil sands at a depth of 75 – 200 m since there is currently no effective technology for the interval. In addition, it can significantly reduce energy costs, environmental pollution and greenhouse gas emissions.
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Ross, Cynthia M., Edgar Rangel-German, Louis M. Castanier, Philip S. Hara, and Anthony R. Kovscek. "A Laboratory Investigation of Temperature-Induced Sand Consolidation." SPE Journal 11, no. 02 (June 1, 2006): 206–15. http://dx.doi.org/10.2118/92398-pa.
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Summary Current gravel-packed, slotted-liner completion techniques for wells in unconsolidated and weakly consolidated sandstone are relatively expensive and result in greatly reduced operational flexibility. On the other hand, empirical field evidence (Wilmington, California) demonstrates that sand grains surrounding the wellbore are cemented and consolidated following injection of high-pressure (1,600-psi) steam. Effective sand control results without adverse changes to formation permeability and producibility. Here, sand consolidation mechanisms are exposed by duplicating, in the laboratory, the governing geochemical processes. Sandpacks contain typical per-volume concentrations of concrete resulting from perforating a cased and cemented well. The evolution of sandpack pore and grain struture is determined using scanning electron microscope imaging and compositional analyses. Results show that hot alkaline water injected at rates comparable to field rates indeed results in grain-cementing precipitates. Casing cement plays a crucial role in that it is the source of calcium silicates appearing in various pore-lining precipitates. Conditions for effective sand consolidation are not necessarily formation-specific, and the process can be altered to improve cost-effectiveness, flexibility, and longevity of the completion technique. Introduction In poorly consolidated and unconsolidated sandstone reservoirs, solids are sometimes carried from the formation to the wellbore as oil and water flow toward producers. It is referred to as "sand production." This term is usually detrimental and should be avoided. Operational problems result, including extra wear of the pumping units, shorter pipe lifetime, frequent workovers, loss of well productivity, and waste-disposal issues. Several remedies are available to the engineer. They include production-rate reduction (Penberthy and Shaughnessy 1992), physical barriers (Penberthy and Shaughnessy 1992), in-situ consolidation (Prats and Hamby 1965; Davies et al. 1983; Davies et al. 1997; Davies et al. 2003), and hybrid methods (Penberthy and Shaughnessy 1992; Kruger 1986). No sand-control method is, as of yet, generally applicable. We use laboratory experiments to develop a mechanistic understanding of a novel hot alkaline/steam sand-consolidation technique. This technique has proved effective empirically (Davies et al. 1997). The mechanisms of mineral and grain dissolution, precipitation, and consolidation using Wilmington (Los Angeles basin, California) field cores and quartz sandpacks are described. Field sands are drawn from the productive, heavy-oil intervals (T and D sands) of the Tar II-A zone (Hara 2003). The tools employed are core-scale and beaker-scale experiments, scanning electron microscopy (SEM), and elemental analyses. Additionally, tubing-tail samples recovered from the field are reexamined in light of the new laboratory results. Before proceeding to the experimental details and results, a brief review of the hot alkaline/steam sand-consolidation process is given. This background is foundational, because it underpins the experimental program and interpretation of results. The experimental objectives, apparatus, and procedures follow. Results, discussion, and implications finish the paper.
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Williams, B. P. J., E. K. Wild, and R. J. Suttill. "PARAGLACIAL AEOLIANITES: POTENTIAL NEW HYDROCARBON RESERVOIRS, GIDGEALPA GROUP, SOUTHERN COOPER BASIN." APPEA Journal 25, no. 1 (1985): 291. http://dx.doi.org/10.1071/aj84026.
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Facies analysis of core from the Gidgealpa Group has led to the first recognition of sandstones of aeolian origin in the Cooper Basin. The aeolian suite was recognised in core from the Merrimelia Formation penetrated by wells within the Merrimelia field.The Merrimelia 5 aeolianites occur in core between 8603 and 8659 ft drill depth. These were correlated to similar facies in core from Merrimelia 1 between 9649 and 9674 ft drill depth, where other lithotypes of the suite were identified.Gamma ray-sonic log response over cored aeolianite intervals can be correlated to Merrimelia 13, where similar aeolian sediments are interpreted for an uncored interval of Merrimelia Formation.The overall glacigenic nature of the Merrimelia Formation is well documented but this discovery records the first aeolian suite in the Gidgealpa Group and may also document the first subsurface example of cold-climate aeolianites.The aeolianites are porous, poorly cemented, coarse and fine grained sandstones dominated by parallel lamination. Sharp, planar truncation surfaces divide the suite into units composed mainly of translatent wind ripple lamination with minor amounts of sandflow bedding. Primary depositional dip (post-compaction) varies between 0° and 25° suggesting preservation of dune lee-slope strata. Local deformation of avalanche foresets is also visible in the core.The gamma ray-sonic logs of the thick (1190 ft (363 m)) Merrimelia Formation in Merrimelia 5 indicate thick (760 ft (232 m)) porous sandstones. These originate from distal aeolian and distal sandy braidplain environments. In core from Merrimelia 1, aeolianites are interbedded with proximal outwash fan conglomerates. Also gamma ray-sonic logs of the interval indicate thinning of the aeolianite sands. These two observations indicate a nearby depositional edge to the aeolianites.A low interval transit time on sonic logs is characteristic of the porous aeolianite sand. This response produces an identifiable change in seismic reflections where the sands are developed, which allows mapping of the sand distribution from seismic data.A 6 to 8-km wide band of aeolianite sand facies trending southeast — northwest has been mapped. This porous aeolianite sand facies is interpreted to pass laterally into outwash fan, braidplain and interdune deposits.Potential hydrocarbon traps may occur at the top of the aeolianites, or within them beneath intraformational seals formed by muddy interdune facies. The recognition of an aeolian suite at Merrimelia indicates the potential for similar facies development elsewhere in the southern Cooper Basin. Locally these could form important reservoirs beneath the level of existing production.
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Loro, Richard, Robin Hill, Mark Jackson, and Tony Slate. "Technologies that have transformed the Exmouth into Australia." APPEA Journal 55, no. 1 (2015): 233. http://dx.doi.org/10.1071/aj14018.
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The oil and gas fields of the Exmouth Sub-basin, offshore WA, have presented a number of significant challenges to their exploitation since the first discoveries of heavy oil and lean gas were made in the late 1980s and early 1990s. Presently, some 20 oil and gas fields have been discovered in a variety of Late Jurassic to Cretaceous clastic reservoirs from slope turbidites to deltaic sands. Discovered oils are typically heavily biodegraded with densities ranging from 14–23° API and moderate viscosity. Seismic imaging is challenging across some areas due to pervasive multiples and gas escape features, while in other areas resolution is excellent. Most reservoirs are poorly cemented to unconsolidated and thus require sand control. Modest oil columns, most with gas caps, and variable permeability, present challenges for both maximising oil recovery and minimising the influx of water and gas. Oil-water emulsions also present difficulties for both maximising oil rate and metering production. To date, more than 300 MMbbls have been produced from five developments (Enfield, Stybarrow, Vincent, Van Gogh and Pyrenees), and in 2013 the Macedon gasfield began production. This peer-reviewed paper focuses on the variety of technologies—geoscience, reservoir, drilling and production—that have underpinned the development of these challenging fields and in doing so, transformed the Exmouth into Australia’s premier oil producing basin.
Dissertations / Theses on the topic "Poorly cemented sands"
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Hashemi, SeyedSaeid. "Drilling and maintaining stable unsupported boreholes in poorly cemented sandy formations." Thesis, 2015. http://hdl.handle.net/2440/105980.
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This thesis presents a series of journal and conference articles in which the failure behaviour of an unsupported vertical borehole drilled through poorly cemented sands is studied by analytical, numerical and experimental methods. Also, drilling field investigations were carried out to collect real samples. Three different cement contents and two borehole sizes were considered to study the effects of the bonding strength and scale-size on the particle dislocation. This study resulted in a more realistic prediction of the actual behaviour of this formation in the vicinity of a drilled borehole. Having in-depth understanding on the parameters influencing the borehole status is of significant importance in identifying borehole instability problems, designing adequate borehole supports and choosing an efficient drilling method. Due to poor cementation and therefore granular behaviour of this material, the Discrete Element Method (DEM) was identified as a well-suited tool for developing realistic numerical models. To conduct the numerical simulation, a cube of 8 m3 made up of spherical particles with diameters ranging from 5 mm to 70 mm was modelled and analysed in a three-dimensional Particle Flow Code (PFC 3D). The effects of in-situ stresses around the borehole, strength of particle bonding and fluid flow pressure on the stability of the formation around the borehole have been investigated. The studies showed that when there is lack of sufficient bonding between the sand grains, the interaction between them results in their movement towards the borehole opening and thus eventuates the collapse of the borehole wall. Furthermore, the presence of high pressure water flow expedites the process of the borehole collapse. To study the behaviour of poorly cemented sands thick-walled hollow cylinder (TWHC) and solid cylindrical synthetic specimens were designed and prepared in the laboratory. The effects of different parameters such as stress path, water and cement content, grain size distribution and mixture curing time on the characteristics of the samples were studied to identify the mixture closely resembling the formation at the drilling site. The Hoek cell was modified to allow the real-time visual monitoring of the grain debonding and borehole breakout processes during the laboratory tests. The results showed the significance of real-time visual monitoring in determining and better understanding the onset of the borehole breakout. The study on the size-scale effect revealed that with the increase in the borehole size the ductility of the specimen decreased, however the axial and lateral stiffness of the TWHC specimen remained unchanged. Under different confining pressures the lateral strain at the borehole breakout initiation point was considerably lower in a larger size borehole (20 mm) versus a smaller size one (10 mm). Three well-known failure criterion domains; the Coulomb, Drucker-Prager and Mogi, were considered versus the laboratory test data from the TWHC tests to evaluate their ability to predict the shear failure of a borehole. The obtained results showed the significance of selecting an appropriate failure domain for predicting the shear failure behaviour of poorly cemented sands near the borehole wall. The results also showed that the Coulomb criterion is not well suited for predicting the borehole failure when there is no pressure acting inside the borehole. A failure envelope based on the Mogi domain was developed which can be used for the case of the far-field stress states. The introduced failure envelope allows predicting the stability of a borehole drilled in poorly cemented sands. The results from the video recording of the tests showed that a narrow localized zone develops in the direction of the horizontal stress, where the stress concentration causes a full breakout in the specimens. In the TWHC specimens the dilation occurred at lower confining pressures and contracting behaviour was observed during the onset of shear bands at higher pressures. Scanning electron microscopy (SEM) studies showed that sand particles stayed intact under the applied stresses and micro- and macrocracks developed along their boundaries. The SEM imaging was used to investigate and characterize pre-existing microcracks on the borehole wall developed due to the specimen preparation. It showed that boring the solid specimen in order to produce a TWHC specimen can generate microcracks on the borehole wall prior to testing which affects the process of borehole failure development during the test. Detecting the bonding breakage point and introducing an appropriate failure criterion plays a key role in the borehole stability analysis. The total potential and dissipative absorbed strain energy per volume of material up to the point of the observed particle debonding was calculated. The results showed that the particle bonding breakage point at the borehole wall was reached both before and after the peak strength of the TWHC specimens depending on the stress path and cement content. Test results showed that the stress path has a significant effect on the onset of the particle bonding breakage. Also, it was shown that for different stress paths there is a near linear relationship between the absorbed energy and the normal effective mean stress.Thesis (Ph.D.) (Research by Publication) -- University of Adelaide, School of Civil, Environmental and Mining Engineering, 2015.
Book chapters on the topic "Poorly cemented sands"
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Melkoumian, Nouné Sophie, Stanley Donald Woithe, Yien Lik Kuo, and Adam Karl Schwartzkopff. "A New Cost-Effective Active Structural Health Monitoring Technology for Detecting Shear Bands in Poorly Cemented Sands Leading to Exploration Borehole Collapse." In Mine Planning and Equipment Selection, 1231–41. Cham: Springer International Publishing, 2014. http://dx.doi.org/10.1007/978-3-319-02678-7_119.
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Amgaa, Tsolmon, Dieter Mader, Wolf Uwe Reimold, and Christian Koeberl. "Tabun Khara Obo impact crater, Mongolia: Geophysics, geology, petrography, and geochemistry." In Large Meteorite Impacts and Planetary Evolution VI. Geological Society of America, 2021. http://dx.doi.org/10.1130/2021.2550(04).
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ABSTRACT Tabun Khara Obo is the only currently known impact crater in Mongolia. The crater is centered at 44°07′50″N and 109°39′20″E in southeastern Mongolia. Tabun Khara Obo is a 1.3-km-diameter, simple bowl-shaped structure that is well visible in topography and clearly visible on remote-sensing images. The crater is located on a flat, elevated plateau composed of Carboniferous arc-related volcanic and volcanosedimentary rocks metamorphosed to upper amphibolite to greenschist facies (volcaniclastic sandstones, metagraywacke, quartz-feldspar–mica schist, and other schistose sedimentary rocks). Some geophysical data exist for the Tabun Khara Obo structure. The gravity data correlate well with topography. The −2.5–3 mGal anomaly is similar to that of other, similarly sized impact craters. A weak magnetic low over the crater area may be attributed to impact disruption of the regional trend. The Tabun Khara Obo crater is slightly oval in shape and is elongated perpendicular to the regional lithological and foliation trend in a northeasterly direction. This may be a result of crater modification, when rocks of the crater rim preferentially slumped along fracture planes parallel to the regional structural trend. Radial and tangential faults and fractures occur abundantly along the periphery of the crater. Breccias occur along the crater periphery as well, mostly in the E-NE parts of the structure. Monomict breccias form narrow (<1 m) lenses, and polymict breccias cover the outer flank of the eastern crater rim. While geophysical and morphological data are consistent with expectations for an impact crater, no diagnostic evidence for shock metamorphism, such as planar deformation features or shatter cones, was demonstrated by earlier authors. As it is commonly difficult to find convincing impact evidence at small craters, we carried out further geological and geophysical work in 2005–2007 and drilling in 2007–2008. Surface mapping and sampling did not reveal structural, mineralogical, or geochemical evidence for an impact origin. In 2008, we drilled into the center of the crater to a maximum depth of 206 m, with 135 m of core recovery. From the top, the core consists of 3 m of eolian sand, 137 m of lake deposits (mud, evaporites), 34 m of lake deposits (gypsum with carbonate and mud), 11 m of polymict breccia (with greenschist and gneiss clasts), and 19 m of monomict breccia (brecciated quartz-feldspar–mica schist). The breccias start at 174 m depth as polymict breccias with angular clasts of different lithologies and gradually change downward to breccias constituting the dominant lithology, until finally grading into monomict breccia. At the bottom of the borehole, we noted strongly brecciated quartz-feldspar schist. The breccia cement also changes over this interval from gypsum and carbonate cement to fine-grained clastic matrix. Some quartz grains from breccia samples from 192, 194.2, 196.4, 199.3, 201.6, and 204 m depth showed planar deformation features with impact-characteristic orientations. This discovery of unambiguous shock features in drill core samples confirms the impact origin of the Tabun Khara Obo crater. The age of the structure is not yet known. Currently, it is only poorly constrained to post-Cretaceous on stratigraphic grounds.
Conference papers on the topic "Poorly cemented sands"
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Liersch, L., G. Abdo, W. Choucair, and S. Sadek. "Chemical Grouting for Water Control in Nearshore Poorly Cemented Sands." In Proceedings of the Fourth International Conference on Grouting and Deep Mixing. Reston, VA: American Society of Civil Engineers, 2012. http://dx.doi.org/10.1061/9780784412350.0117.
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Ang, Ajita Ang C. K., Avinash A. Kumar Kumar, Syazwan B. A. Ghani Ghani, Nann N. N. Maung Nann, M. Hanif Yusof Yusoff, Myat Thuzar Thuzar, and Lau C. Hen Lau. "Infill Depleted Gas Well Cementing Challenges for Offshore Myanmar Drilling Operations." In IADC/SPE Asia Pacific Drilling Technology Conference. SPE, 2021. http://dx.doi.org/10.2118/201010-ms.
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Abstract Infill well drilling was planned and executed to increase production in a significantly depleted field. A total of 3 infill wells were drilled in 2 different layers of reservoir for an offshore operator in Myanmar. In the offset wells, water production had become significantly higher throughout. Previously all offset wells in this field were completed with open hole sand screens was chosen to isolate the water bearing sand in the sand reservoir below. Pore pressure prognosis were calculated from offset well depletion rate. Reservoir formation properties is assumed to be same throughout the field. The first well was drilled and was found that there were two gas water contacts through the 3 targeted sand layers. The gas water contact and WUT (Water Up To) in this well were unexpected and it was prognosed that these gas water contact are there due to compartmentalization. The 7" liner were set and cemented throughout these reservoirs. The cement job went as per the plan and there were no losses recorded during cementing. However, initial cement log did not show isolation. 2 more runs of cement log were performed 6 days and 10 days later while conducting intervention activities on other wells. All three cement log came to the same conclusion, showing no isolation throughout the annulus of the 7" production liner. Significant amount of gas had percolated into the annulus over time. Despite no evidence of poor cement slurry design observed during running various sensitivity studies and post-job lab tests final cement log, which was conducted under pressure and confirmed no hydraulic isolation. A cement remedial job was planned and an investigation was conducted to identify the plausible root causes. This paper explains on the root causes of poor cement presence in the annulus, and the remedial work that took place to rectify the issue.
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Abdulhadi, Muhammad, Evelyn Ling, Ahmad Uzair Zubbir, Hani Mohd Said, Rohani Elias, Paul Sanchez, Nazri Nor, et al. "Successful Appraisal Cum Development of Shallow and Poorer Quality Gas Reservoir in Mature Field at Minimal Cost." In SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205666-ms.
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Abstract The Cement Packer approach has been successfully implemented in ExxonMobil Exploration & Production Malaysia Inc. (EMEPMI) to further develop minor gas reservoirs. The reservoir of interest is of relatively poor quality and has not been tested, thus making conventional development potentially not cost effective. Several viable approaches were identified and assessed to appraise and develop the reservoir. The cement packer method, which requires relatively minimal investment was then selected as being the most suitable in pursuing these behind casing opportunities. Group 1 sands in Field A are the shallowest hydrocarbon reservoirs which are relatively thin and have low porosity and permeability. The existing completions are currently producing from deeper reservoirs, with the top packer located below the Group 1 sands. Developing the opportunities behind casing in these sands using the conventional pull tubing workover approach may be cost prohibitive. The cement packer approach, where the tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing, was identified as one of the potential cost effective solution. The hardened cement then acts as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized. Prior to well entry, tubing and casing integrity tests were performed to confirm the integrity. This step is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement is hardened, pressure test from the tubing and from the casing indicated the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool also displayed nearly 120m of fair to good cement above the target perforation depth. These data served as basis and proof that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the relatively poor reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to increase the probability of maximum reservoir contact while minimizing skin. Post perforation, a sharp increase in the tubing pressure was observed, indicating pressure influx from the reservoir. The casing pressure however, remained low, confirming no tubing-casing communication and thus the success of the cement packer. The well was later able to unload naturally from the high reservoir pressure. The work program also managed to confirm the producibility of the reservoirs. This successful approach has opened up potential application to similar stranded reservoirs behind casing.
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Abdulhadi, Muhammad, Hani Mohd Said, Ahmad Uzair Zubbir, Evelyn Ling, Mohamed Azlin Mohd Nasir, Imran Anoar, Abdul Rahman Abdul Rahim, et al. "Cost-Effective Development of Shallow and Poorer Quality Gas Reservoir in Mature Field." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206315-ms.
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Abstract The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.
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Thomson, Shaun, Baglan Kiyabayev, Barry Ritchie, Jakob Monberg, Maurits De Heer, and Soren Skov List. "Worlds First Offshore Horizontal Well Using Jointed Pipe Cemented Frac Sleeve Technology." In SPE International Hydraulic Fracturing Technology Conference & Exhibition. SPE, 2022. http://dx.doi.org/10.2118/205331-ms.
Full textAbstract:
Abstract The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, "dirty chalk" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next. Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost. A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits. The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.
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Al-Kadem, Mohammad, Mohammad Gomaa, Karam Al Yateem, and Abdulmonam Al Maghlouth. "Multiphase Flow Meter Health Monitoring Strategy: Maximizing the Value of Real-Time Sensors and Automation for Industrial Revolution 4.0." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206281-ms.
Full textAbstract:
Abstract The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.
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Kou, Zuhao. "Impacts of Carbonated Brine-Rock Reactions on Multiphase Flow Properties in Upper Minnelusa Sandstone: Implication for CO2 Storage." In SPE Annual Technical Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/212389-stu.
Full textAbstract:
Abstract The impact of carbonated brine-rock geochemical reactions on porosity, permeability, and multiphase flow responses is relevant to the determination of CO2 storage capacity of deep saline aquifers. In this research, carbonated brine flooding experiments were performed on core samples consisting of poorly sorted, quartz-rich sand with laminated bedding from a target CO2 storage formation in Wyoming. Complementary pre- and post-injection lab measurements were performed. Results showed that both core porosity and permeability increased after a seven-day carbonated brine injection, from 6.2% to 8.4% and 1.6mD to 3.7mD, respectively. These changes were attributed to carbonate mineral dissolution, which was evidenced by the effluent brine geochemistry, pore-throat size distribution and surface area. To be more specific, within the more permeable section of core samples, containing larger pore size, the permeability increment is apparent due to dolomite mineral grains and cements dissolution. However, for the lower permeability section, corresponding to the smaller pore size, mineral precipitation possibly lessened dissolution effects, leading to insignificant petrophysical properties changes. Consequently, the observed heterogeneous carbonated brine-rock interactions resulted in changes of CO2/brine relative permeability. This research provides a fundamental understanding regarding impacts of fluid-rock reactions on changes in multiphase flow properties of eolian sandstones, which lays the foundation for more accurate prediction/simulation of CO2 injection into deep saline aquifers.
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Daohmareeyor, Tuanangkoon, Deric Leong Wei Lock, and Reawat Wattanasuwan. "The Use of an Organic Crosslinked Polymer Sealant as a Barrier to Retrieve Stuck Coiled Tubing from a Live High Pressure Well After Over a Year: Case Study from Offshore Vietnam." In IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/209856-ms.
Full textAbstract:
Abstract Coiled Tubing (CT) is a commonly used well intervention technique for sand/debris cleanout, milling, fishing, cementing, and gas lifting applications. Performing cement plug operations with CT in high-pressure live wells can present a relatively high level of risk of getting stuck, improper placement of cement plugs, and poor quality cement plugs. In this scenario, an offshore well in Vietnam was left with CT held only on the surface by the Blow Out Preventers (BOP) after getting stuck downhole more than a year previously. Retrieval of the CT was required without any downhole barrier in place and circumstances that made the conventional killing of the well difficult. This paper will discuss the equipment necessary, factors to consider in the job design, sealant design with lab testing, and describe the technique used to safely retrieve the fish from the well. During the design phase of the solution, risk assessments were carried out to cover various scenarios such as: Poor condition of one or more of the CT string, BOP, dual ball kelly cock valve, double flapper check valve. Inability of the Organic Crosslinked Polymer sealant to hold well pressure. Difficulty in latching the surface CT stump, and the potential requirement for freezing to establish a surface barrier. Along with the specially designed sealant treatment, multiple yard tests for dressing the sheared CT and latching were performed to represent actual conditions during the operation and allow risk mitigation plans to be put in place. Firstly, the barrier verification process was performed to monitor any well pressure build-up from the downhole/surface pressure reading to confirm a barrier was in place, allowing surface equipment to be rigged up. After this was confirmed, the equipment was rigged up, and a fluid circulation test followed by the inflow test of the double flapper check valve in the bottom hole assembly was performed to verify CT integrity. The first of the organic crosslinked polymer was then pumped to plug inside the CT before electric line (E-line) was run into the CT to cut at the free-point above the stuck location. The second organic crosslinked polymer was then placed to plug between the CT and annulus, forming a barrier allowing the makeup of the spoolable connector. Finally, retrieval of the 1,700 meters of CT string took place without any loss of well control. Retrieving the CT from this high pressure well presented a lot of challenges. Achieving a safe and successful operation showed that with proper planning, design, and risk mitigation plans, a potential well control situation can be prevented with the well being secured and successfully returned to production. This paper can now serve as a guideline for future operations with similar circumstances requiring retrieval of stuck CT from high-pressure wells where it has been held on surface for an extended period of time.
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Carragher, Paul, Jeff Fulks, and David Mason. "Status of Meltable Plug Technology Applications in the Drilling Process." In IADC/SPE International Drilling Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/208719-ms.
Full textAbstract:
Abstract Meltable plug technology has a range of potential applications in the drilling process and is being more widely used. With over 250 jobs done to date, a variety of applications are being identified and being applied. This paper seeks to update the main areas of application to date. Bismuth alloy technology is now becoming standard technology as over 250 installations demonstrate that this is very much field proven. From onshore to deepwater environments, from drilling to completions and interventions applications through to abandonment operations, from 2″ to 28″ diameter and from 4 degC to 150 degC plug setting depth conditions, in wellbores with deviations up to 83 degrees, the technology has a wide operating envelope. Different alloy compositions are used according to the downhole conditions. In drilling a well, problems can be encountered in achieving good cement isolation from production intervals or from gas pressure in annuli. Furthermore, casing leaks can emerge and pose well integrity problems. In completing and producing a well, particularly over time, packers can leak, water cuts can increase and zonal isolations be required. This can be particularly challenging in sand control completions. Abandonment operations can be simplified and reduced in time and cost using this system. Meltable plug technology, while not a panacea for all ills, nonetheless can remediate many of these challenges. Four operators in the US have run 63 thermally deformable annulus packers in wells, then – when gas pressure developed in an annulus, activated the bismuth alloy based thermally deformable annulus packer and immediately isolated the leak. Operators have remediated poor annular cement jobs with bismuth alloy plugs. Recently, one leaking packer has been remediated using this technology, more are planned in coming months. Zonal isolations in openhole gravel pack wells using bismuth alloy plug technology have been done in several deepwater wells with good production results and more are planned. A meltable plug successfully isolated a water producing interval in a slotted liner completion with a void annulus. Abandonments have been done in many wells, with a significant program of work in the Valhall field offshore Norway playing a key part in successfully abandoning 30 wells, reducing HSE risks, time and costs. A similar program in Australia abandoning 30 wells with 55 plugs has been similarly successful and more abandonments using these techniques are planned. In addition, some wells offshore California have been abandoned using these techniques. This paper will effectively provide an updated status on the technology across the lifecycle of a well and potential future usage areas.