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Abstract Oil and gas fields encounter issues associated with clay minerals through drilling and production. Depending on the types of clay minerals, they pose the danger of swelling and migration upon exposure to incompatible water. Drilling introduces water through drilling mud, and production introduces water through different treatments such as acid stimulation and hydraulic fracturing. The recovery of oil and gas from subterranean formations has been troublesome in formations that contain water-sensitive minerals, e.g., water-swellable clays, such as clays in the smectite group, and fines capable of migrating when disturbed, such as silica, iron minerals, and alkaline earth metal carbonates. It has been common practice to add salts to the treatment fluids. The salts adsorb to the clay surfaces in an ion exchange process that can temporarily reduce the swelling and/or migration of the clays. Another method used is to coat the area with a polymer in order to physically block the surface of the clays. This paper will mention the types of clays related to the oil industry, describe the structure of clays, mention the mechanisms behind swelling and migrating, and compare the different developments in the field of clay inhibition.
- North America (0.68)
- Asia > Middle East > Saudi Arabia (0.47)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
Abstract Polymer flooding is one of the most attractive chemical EOR techniques for sandstone reservoirs however due to complex geological heterogeneity and harsh reservoir conditions its full potential has not been explored in carbonate reservoirs. The main reason behind this limitation is the inability of conventional EOR polymers like HPAM and Xanthan to withstand these conditions. Candidate polymers must provide the required rheology at minimal polymer concentration, be thermally and mechanically stable, and result in a manageable adsorption on the reservoir formation. A polymer screening study has been conducted on a series of polymers, to identify the most suitable candidate that can tolerate the harsh reservoir conditions. Initially, rheological measurements are conducted on a series of polymers followed by filterability, injectivity, static and dynamic adsorption, mechanical and thermal stability testing as a screening criterion for polymers in EOR operations. Amongst the tested polymers polyacrylamide based co- and ter-polymers showed reasonable temperature stability with low salinity tolerance. Whereas, biopolymer Schizophyllan a polysaccharide showed shear thinning behavior with positive thermal stability and salt tolerance. Long-term thermal stability of biopolymer is also conducted at a temperature of 120 ยฐC and salinity up to 220 g/L under anaerobic conditions for over eight months and no viscosity loss is observed. Biopolymer showed acceptable injectivity on cores of permeability more than 30 mD. Core flood effluents viscosity reached 40% compared to injected sample. In addition the mechanical stability and filterability of biopolymer are also discussed. Static as well as dynamic adsorptions of biopolymer have also been studied. The static adsorption on four natural minerals (Calcite, Dolomite, Kaolin, and Silica) as well as formation rocks is reported. Out of these four minerals, maximum and minimum adsorption is observed on Dolomite and Kaolin respectively. The adsorption of biopolymer decreases with salinity and temperature. Adsorption on carbonate reservoir rocks is found to be low when compared to pure calcite and dolomite minerals. Dynamic adsorption on cores with different permeabilites (3 to 165 mD) is measured to be low in magnitude (47.5 to 0.53 ยตg/g).
- North America > United States (1.00)
- Asia > Middle East > UAE (0.93)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Mitigating Shale Drilling Problems through Comprehensive Understanding of Shale Formations
Al-Arfaj, Mohammed K. (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Sultan, Abdullah (King Fahd University of Petroleum & Minerals) | Amanullah, Md. (Saudi Aramco) | Hussein, Ibnelwaleed (Qatar University)
Abstract In order to develop an inhibitive water-based mud capable of mitigating the adverse effects of shale-mud interactions, it is important to characterize the shale sample in terms of its geological structure, mineralogical composition, reactivity potential, etc. Further, the shale-mud interactions should be studied through a series of experimental tests such as swelling, dispersion and inhibition durability. This paper presents the results of characterization and testing of one of the studied shale samples with X-ray diffraction, micro-CT, ultrasonic rock mechanics testing, capillary suction time and cation exchange capacity. The paper also shows how petrophysics data of shale formations can be utilized to improve and optimize drilling practices in order to achieve the ultimate goal of enhanced wellbore stability. Depending on clay content, different shale formations have different responses when exposed to drilling fluids. It is therefore very important to characterize the shale formation to develop the appropriate drilling fluid. The tested shale sample was found to be a silica-rich shale with a small percentage of clay minerals, mainly kaolinite. Characterization scheme included also Micro-CT where the images revealed the heterogeniety and fractures in the internal matrix. Dynamic elastic moduli were determined using ultrasonic rock mechanics testing. A cation exchange capacity (CEC) value of 2.5 meq and capillary suction time (CST) value of 42.6 seconds indicated low tendency of the shale rock to both swelling and dispersion.
- Asia > Middle East > Saudi Arabia (0.29)
- North America > United States > Texas (0.28)
Preliminary Assessment of CO2 Storage Potential in the H-59 Block in Jilin Oilfield CCS Project
Zhang, Liang (China University of Petroleum (Huadong)) | Li, X. (China University of Petroleum (Huadong)) | Ren, B. (University of Texas at Austin) | Cui, G. D. (China University of Petroleum (Huadong)) | Ren, S. R. (China University of Petroleum (Huadong)) | Chen, G. L. (PetroChina)
The block H-59 in the Daqingzijing region was selected as a pilot site for the first stage of the CCS project in Jilin oilfield after an extensive assessment. This block is a light oil reservoir with a low permeability. The performance of water flooding after the primary oil recovery was very poor. Therefore, CO2 injection has been started since April 2008 for EOR associated with CO2 storage for environmental benefits. This paper is aimed at assessing the current CO2 storage capacity and distribution at different states in the oil reservoir after 6-year injection until April 2014. Based on various CO2 trapping mechanisms, an evaluation method of CO2 storage potential is established to calculate the theoretical and effective CO2 storage capacities in target oil reservoir the current amount of CO2 buried in the H-59 block was calculated according to the field data. The reservoir numerical simulation was used to analyze the distribution and existing state of CO2 underground. The assessment results show that the theoretical capacity of CO2 storage in the H-59 block is 72.32ร104 t, and the effective capacity of CO2 storage is 26.37ร104 t. The calculation of effective CO2 storage capacity in oil reservoir considers the engineering practice of field operation during project life. The coverage factor of well pattern (k1) and the sweep coefficient of CO2 within the well pattern (k2) have been introduced in the method. Meanwhile, the mineral trapping was neglected for short-term storage of CO2 based on a preliminary geochemical simulation analysis. There are 17.45ร104 t CO2 which has been buried in the block until April 2014. The distribution of buried CO2 between the injection and production wells is mainly determined by the reservoir physical properties and the total amount of CO2 injected in each well. Reservoir simulations indicate that 61.0% of CO2 buried in the oil reservoir has been trapped at supercritical state, and the amounts of CO2 dissolved in oil and water account for 24.4% and 14.6% respectively. These proportions of CO2 at different states are very close to the calculation results of effective CO2 storage capacity. In comparison to the effective CO2 storage capacity, it is thought that the block H-59 still has a certain storage potential of 8.92ร104 t at present. For the assessment methods, the parameters k1 and k2 for calculation of effective CO2 storage capacity deserve for further discussion. It should be also noted that the accuracy of CO2 distribution predicted by reservoir simulation greatly depends on the accuracy of geological model. It needs more efforts to improve the understanding of the target reservoir properties.
- North America > United States (1.00)
- Asia > China > Jilin Province (0.85)
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snรธhvit Field > Stรธ Formation (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snรธhvit Field > Nordmela Formation (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/5 > Snรธhvit Field > Stรธ Formation (0.99)
- (33 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)
Abstract The objective of this paper is to determine the water saturation applying the Waxman-Smits equation and using mineralogy analysis obtained from XRD/CT scanning and resistivity data for a tight sandstone formation. Contrarious to using Archie's equation, the suggested approach takes conductivity into account and provides more accurate water saturation calculations, in order to correctly predict oil and gas in place. Accurate computing of the correlations between rock resistivity and fluid saturations is vital to constructing 2D and 3D models of water saturation to understand the effect of microstructure on petrophysical properties of tight formations. The negative charges on the surface of monoclinic and triclinic clay minerals, with layered silica tetrahedra in shale rocks, hold electric interactions with bipolar molecules of water and free cations. The presence of clays in tight gas sandstone reservoirs may lead to the overestimation of water saturation, if the mineralogy is not properly included into the computations. This implies that proper water saturation characterization of tight gas reservoirs could lead to an increase of evaluated hydrocarbon resources. Such an increase may be significant in large newly discovered tight rock gas bearing basins with multiple shaley-sand sweet spots. The case study in this paper shows a computational analysis made by comparing Archie versus Waxman-Smits equations. Results from tight rock samples illustrate a proportional relationship between the clay content and the quantity of exchangeable clay. A new term, named the clay factor, Cf, has been obtained from this linear relationship, and was found that it could possibly replace the BQv term in the Waxman-Smits equation. These results show a promising workflow method to calculate water saturation considering the conductivity and fraction volume of clay minerals. As the mineralogy of a rock can be accurately identified by high resolution imaging techniques, an approach based on mineralogy, as the proposed method can be utilized as a better way to compute saturation using modification of the Waxman-Smits model. Good assessment of saturation can have a large impact in the computation of transition zones and gas resources in tight rocks, revisiting volumes that were counted as water in past models.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.57)
Study of Pore Structure of Gas Shale with Low-Field NMR: Examples from the Longmaxi Formation, Southern Sichuan Basin, China
Chen, Yulin (St. Key Lab. O&G Geo & Exp. Eng., Southwest Petroleum University) | Zhang, Liehui (St. Key Lab. O&G Geo & Exp. Eng., Southwest Petroleum University) | Li, Jianchao (St. Key Lab. O&G Geo & Exp. Eng., Southwest Petroleum University)
Abstract Pore structure of gas shale which possesses lots of nanopores is complex. NMR measurement can not only obtain accurate sample parameters but also provide an approach to quantitatively study pore structure. This paper Integrates NMR, mercury injection, nitrogen adsorption and X-ray diffraction to analyze the relationships of pore structure, surface to volume ratio and mineral components. Both nitrogen adsorption and mercury-injection have some limitations in characterizating of pore structure of gas shale. In this paper we integrate pore size distribution curve of nitrogen adsorption and mercury-injection. Comparison and analyses of NMR T2 spectra and the integrated pore size distribution curve calculate NMR pore size distribution. Capillary pressure curve is constructed based on NMR T2 spectra for quantitatively studying pore structure of gas shale. The diagrams of relationship between characteristic parameters of pore structure, surface to volume ratio and mineral components such as clay minerals, pyrite and TOC are established. NMR study has been implemented on 15 samples from Longmaxi formation. The results show the porosity range from 2.24% to 5.76%. The NMR pore size distribution curves is more precise than the curves that calculated only according to nitrogen adsorption or mercury-injection. Calculating separation coefficient, skewness, structure coefficient, median pressure and other parameters from constructed capillary pressure curves indicate high threshold pressure, poor connectivity, and complex pore size distribution. Porosity has a positive correlation with clay mineral content, TOC, pyrite. Most of surface to volume ratio and pore volume are provided by micropores and mesopores. Using integration pore size distribution curve of nitrogen adsorption and mercury-injection to calculate parameter of NMR pore size distribution is a more exact approach than only using nitrogen adsorption or mercury-injection. Capillary pressure curve constructed by NMR T2 spectra can provide information of micropores and mesopores which mercury-injection cannot correctly characterize.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Europe > France > Autun Basin (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- (3 more...)
X-Ray Micro-Computed Tomography Imaging for Coal Characterization
Ramandi, Hamed Lamei (School of Petroleum Engineering, The University of New South Wales) | Armstrong, Ryan T. (School of Petroleum Engineering, The University of New South Wales) | Mostaghimi, Peyman (School of Petroleum Engineering, The University of New South Wales) | Saadatfar, Mohammad (Department of Applied Mathematics, Australian National University) | Pinczewsk, W. Val (School of Petroleum Engineering, The University of New South Wales)
Abstract An Australian bituminous coal is imaged at high resolution of 16.1 ฮผm with (wet) and without (dry) X-ray attenuating fluids present in the pore space using a large-field three-dimensional microfocus helical X-ray computed tomography (micro-CT) instrument. Scanning Electron Microscope (SEM) is conducted on slices of the specimen to visualize coal micro-features up to resolution of about 15 nm. Two- and three-dimensional image registration techniques are used to precisely overlay micro-CT tomograms of the core plug in dry and wet conditions and SEM images to yield detailed three-dimensional visualizations of the geometry and topology of the fracture systems in coal. SEM images are also used to produce a calibration curve based on the relationship between the micro-CT intensity values and the true apertures of fractures within coal. This eliminates the need for two sets of imaging. Advanced filtering algorithms are applied to segment the micro-CT image into four distinct phases: resolved fractures, sub-resolution pores and fractures, macerals, and minerals. The application of micro-CT in determination of relative age relationships between adjacent geological features is presented. The distribution of resolved aperture size within the coal sample is investigated and the variation of permeability and porosity in several sub-samples of the coal is plotted. The analysis suggests that coal permeability is independent of porosity and is likely affected by other petrophysical properties such as lithotype. To include the effects of mineral phase on coal properties, we remove the segmented mineral phase and merge it to the resolved fracture phase. This analysis affirms that minerals are deposited in highly connected regions.
- Oceania > Australia (0.47)
- Asia (0.47)
- North America > United States (0.28)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Mineral (1.00)
New Models of Brittleness Index for Shale Gas Reservoirs: Weights of Brittle Minerals and Rock Mechanics Parameters
Hu, Yuan (University of Calgary) | Gonzalez Perdomo, M. E. (University of Adelaide) | Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary) | Zhang, Kai (University of Calgary) | Yi, Jie (University of Queensland) | Ren, Guoxian (University of Calgary) | Yu, Yanguo (University of Calgary)
Abstract Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they ignore the weights of these two factors. Also, it is imprecise to calculate BI by considering quartz (or dolomite) as the only brittle mineral in mineralogy-based BI prediction. Shale gas reservoirs like Eagle Ford are rich in carbonate minerals. If the carbonate minerals are ignored in those reservoirs, the value of BI will be greatly underestimated. On the other hand, brittle minerals like quartz, dolomite and calcite play different roles in BI calculation. If we equally treat them without weighting in BI prediction, the BI being calculated will be inaccurate as well. This paper analyzes the influence of calcite on rock mechanics parameters and BI comparing with quartz and clay. Then new models of BI prediction are built to characterize the weight of each brittle mineral and rock mechanics parameter. Based on the least squares method, optimal values of weight coefficients will be obtained by iteration. The results show that calcite improves rock brittleness and should be considered as a brittle mineral in BI prediction. However, the weight of calcite is less than quartz. From the statistics results, quartz > dolomite > calcite > clay occurs in improving BI. The results also show that Young's modulus plays a more important role in BI prediction than Poisson's ratio.
- Overview > Innovation (0.63)
- Research Report > New Finding (0.49)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.91)
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.48)
Abstract Comparison of different adsorption models in the application of shale reservoir is performed, adsorption capability of shale is reconstructed by the combination of pure mineral adsorption capability with adsorption potential theory. Results are tested by experimental study of specific shale samples in China. The research is based on the high pressure adsorption experiment of methane, in the same time X-ray diffraction experiment is performed to get the mineral information of the shale samples, which are taken from Lungmaxi formation in China. With the experiment, different adsorption models including monolayer Langmuir model, multilayer BET model and D-A model are used to match the data. Also, adsorption capability of pure minerals is combined by adsorption potential theory, which is used to study the contribution of different minerals on the total adsorption capability of shale. Results show that Langmuir curve fits can be used to describe the adsorption behavior of shale, but BET curve fits give more accurate results, D-A curve fits make the best match. The use of characteristic curve can provide further information of the adsorption behavior, by which the unknown isothermal data can be forecasted. The adsorption capability with combination of pure mineral through adsorption potential theory (according to the mineral composition of each sample) gives reasonable results to indicate the total adsorption capability of shale, which means the new approach to get the adsorption information is applicable if the mineral composition and adsorption capability of each mineral are known.
- Research Report > New Finding (0.69)
- Research Report > Experimental Study (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
Experimental Study of Controlling Factors of the Continental Shale Matrix Permeability in Ordos Basin
Qu, Hongyan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Zhou, Fujian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Xue, Yanpeng (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Pan, Zhejun (CSIRO)
Abstract Matrix permeability could be a key factor controlling shale gas production from matrix to micro fractures and further to hydraulic fractures in Chinese shales due to the low porosity and permeability, affected by its unique geochemistry and geology settings including the Total Organic Carbon (TOC) content, mineral compositions, pore structure, and deposition environment. This paper aims to study the controlling factors of the matrix permeability in the continental shale formation, Ordos, China, through modified laboratory measurement mothod. In this work, nine shale samples were collected from three wells in Chang 7 member, Yanchang continental formation, Ordos Basin, China, crushed at in-situ water saturation and sieved to certain size (20/40 mesh). Matrix permeability of these samples was measured with modified Pressure-decay method and compard with the results with Pulse-decay method. The reasons for the discrepancy of these results with different methods were analysed. Moreover, the effects of geochemistry and geology factors on matrix permeability were investigated by grouping these crushed samples according to the variation of TOC, mineral compositions and deposition depth. The relationships between shale matrix permeability and TOC as well as depth were established respectively. Furthermore, the effects of other factors such as mineralogical compositions and pore structure parameters were studied through the Scanning Electron Microscope (SEM) and X-ray diffraction (XRD) analysis. The results show that the shale matrix permeability measured by the Pulse-decay method is generally up to two orders of magnitude higher than that by the Pressure-decay method due to the presence of the natural or artificial micro fractures. In addition, the geochemistry and geology parameters including the TOC, mineral compositions, pore structure and deposition environment have significant effects on the shale matrix permeability. Matrix permeability in Yanchang shale formation is strongly related to TOC and the mineral compositionand even at the similar depth, porosity and matrix permeability are different due to the variation of TOC as a result of geological heterogeanity. TOC in Yanchang formation varies considerably in the range of 1.8 wt % to over 11 wt %, resulting in significant changes in matrix permeability ranging from 0.02 nD to 10 nD, resulting from the influence of the organic matter and clay minerals on total pore volume based on the result of SEM and XRD analysis. The accurate measurement of matrix permeability is important for computer simulation modeling of long term shale gas production.
- Asia > China > Shaanxi Province (0.74)
- Asia > China > Shanxi Province (0.64)
- Asia > China > Gansu Province (0.64)
- Research Report > New Finding (0.84)
- Research Report > Experimental Study (0.70)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Paleozoic (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)