A live oil sample was subjected to a solid detection system (SDS) to measure asphaltene onset point (AOP) at 3850 psi, and asphaltene content of 1.3%. A high-resolution digital camera was used to measure asphaltene particle size distribution. The result showed that asphaltene particles were not uniform in size, but has a normal distribution of 100-120 µm. Asphaltene reversibility to dissolved back into the oil with increasing pressure was only 35% of the original deposition. Two core samples were examined for formation damage due to asphaltene deposition. A Low permeability core showed significant permeability reduction exceeding 50% of its baseline permeability, and the higher permeability core showed less permeability decline, even with the same asphaltene precipitation.
Cinar, Yildiray (The University of New South Wales) | Arns, Christoph (The University of New South Wales) | Dehghan Khalili, Ahmad (The University of New South Wales) | Yanici, Sefer (The University of New South Wales)
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indi-cator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often sig-nificant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe for-mation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements.
Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement.
To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sam-ple, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison be-tween numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling proce-dure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Al-lowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
Thread compound "dope?? in the vernacular, has been used routinely in assembling joints of casing and tubing. The practice in almost universal application in the oil and gas industry involves the manual application of the lubricant in a fashion that is rudimentary, non-systematic and unquantifiable. There is evidence presented in this paper that damage to the near-well zone and other unpleasant events may be associated with the thread compound.
This paper presents the results of both laboratory and field investigations quantifying the effects of the dope on near-well damage. During the assembly of tubing and casing a portion of the thread compound is exuded inside and outside the connection and gets access to the well fluids through the tubing and annular space. Studies presented here show that the dope forms a suspension which penetrates and damages the formation. The studies used standard fluid circulation velocities during typical completion operations.
To characterize and quantify the problem, core samples from the El Tordillo field, with different permeabilities were used. The samples were subjected to the circulation of the suspension created by the thread compound and the completion fluid, measuring the change in the core permeability. The work simulated the well conditions during water injection for water injection wells and during acid treatments for producer wells. A significant reduction in permeability, manifested by a fast and a very large increase in pressure, was measured, at the front face of the core sample. The same measurements showed a far smaller impact in the core body suggesting very minor penetration of dope particles.
This paper describes the laboratory and field work, with description of the test protocols, well conditions and laboratory emulation of field conditions that were used.
Oil and gas producers have shown renewed interest in developing reservoirslocated both onshore and offshore within the Arctic regions of Alaska, Canadaand Russia. In many cases, the hydrocarbon reservoirs are known to be overlainby a massive permafrost interval that extends over depths of up to 700 m belowthe surface active layer. These conditions create unique design and operationalchallenges for production and injection wells from the perspective of ensuringthat well integrity will not be compromised by the inevitable thaw subsidenceof the permafrost soil layers.
The permafrost soil layers surrounding arctic wells will thaw gradually withtime due to wellbore heat loss. As the thaw zone advances radially outward fromeach well, the ice-to-water phase change within the pore space of thefrozen/partially frozen sediments will lead to changes in the permafrost soilproperties and to the loading conditions within the thaw column region. Thesechanges will result in soil deformations (including both vertical settlements(subsidence) and horizontal displacements) which can, in turn, inducesignificant well casing strains that need to be considered in selecting thewell design and layout. The magnitude of the soil deformations that occurthroughout the permafrost interval are highly dependent on the depositionhistory, insitu temperature and the physical and mechanical properties of theindividual soil layers. Therefore, in order to accurately predict the soildeformations and resultant localized casing strain levels, it is essential toobtain reliable data to properly characterize the lithology (soil types) withinthe permafrost interval, as well as the frozen state and the relevantmechanical and thermal properties (both frozen and thawed) of individual soillayers. This paper describes the various information and geotechnical test datathat has been used to establish the thaw and deformation response of differentpermafrost soils at a number of arctic locations for the purpose of evaluatingthe effects of thaw subsidence loading on wells. Overall, the paper serves tohighlight the importance of collecting the appropriate geotechnical data toallow thaw subsidence-induced ground deformations and associated casing loadingconditions to be properly considered at the well/project design stage.
This paper presents a method for determining the Archie saturation exponent, n, from a single, nonequilibrium centrifuge step. The input measurements include detailed 3D saturation distributions from magnetic resonance imaging and the DC conductivity of the sample under examination. The latter is obtained by making use of a patented 4-contact cell. The sample is modeled as a 3D conductivity network and a specially developed algorithm based on random walk (RW) is used to compute its overall conductivity in a very short time. The value of the n exponent is determined by matching the measured conductivity to the calculated one. The entire analysis takes one day. Examples demonstrate the method and details of the impedance cell and the RW algorithm are provided.
Alaskar, Mohammed N. (Stanford University) | Ames, Morgan F. (Stanford University) | Connor, Steve T. (Stanford University) | Liu, Chong (Stanford University) | Cui, Yi (Stanford University) | Li, Kewen (Stanford University) | Horne, Roland N. (Stanford University)
The goal of this research was to develop methods for acquiring reservoir pressure and temperature data near the wellbore and farther out into the formation and to correlate such information to fracture connectivity and geometry. Existing reservoir-characterization tools allow pressure and temperature to be measured only at the wellbore. The development of temperature- and pressure-sensitive nanosensors will enable in-situ measurements within the reservoir. This paper provides the details of the experimental work performed in the process of developing temperature nanosensors. The study investigated the parameters involved in the mobility of nanoparticles through porous and fractured media. These parameters include particle size or size distribution, shape, and surface charge or affinity to rock materials.
The principal findings of this study were that spherically shaped nanoparticles of a certain size and surface charge compatible with that expected in formation rock are most likely to be transported successfully, without being trapped because of physical straining, chemical, or electrostatic effects. We found that tin-bismuth (Sn-Bi) nanoparticles of 200 nm and smaller were transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle size range. We also found that the entrapment of silver (Ag) nanowires was primarily because of their shape. This conclusion was supported by the recovery of the spherical Ag nanoparticles with the same surface characteristics through the same porous media used during the Ag nanowires injection. The entrapment of hematite nanorice was attributed to its affinity to the porous matrix caused by surface charge. The hematite coated with surfactant (which modified its surface charge to one compatible with flow media) flowed through the glass beads, emphasizing the importance of particle surface charge.
Preliminary investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. We found that silica microspheres of different sizes (smaller than the fracture opening) could be transported through the fracture. We demonstrated the possibility of using microspheres to estimate fracture aperture by injecting a polydisperse microsphere sample. It was observed that only spheres of 20 µm and smaller were transported. This result agreed reasonably well with the measurement of hydraulic fracture aperture (27 µm), as determined by the cubic law.
Relative permeability to formation fluids is an essential input into reservoir characterization, dynamic modeling, and production prediction. In this work, a method combining evaporation and unsteady-state pressure-falloff technique is developed to measure gas-phase relative permeability on tight-gas cores for both drainage and imbibition cycles. Toluene is used to mimic formation water and its saturation is varied by evaporation and determined by mass balance. Nitrogen gas is used to imitate the hydrocarbon fluid, and the gas effective permeability at certain toluene saturations is measured by the pressure-falloff technique.
The method greatly reduces the measurement duration, and provides a relatively simple and effective way to characterize the gas-phase relative permeability for tight-gas cores. It has been applied on ~30 tight-gas cores from various fields. Results show that the gas relative permeabilities follow the Corey model with a Corey exponent of ~2 for the drainage cycle and ~3 for the imbibition cycle. The assumptions are studied by both numerical modeling and separate experiments.
Profice, Sandra (I2M–TREFLE - Universite de Bordeaux) | Lasseux, Didier (I2M–TREFLE - Universite de Bordeaux) | Jannot, Yves (LEMTA - Nancy-Universite) | Jebara, Naime (TOTAL – CSTJF) | Hamon, Gerald (TOTAL – CSTJ)
Permeability estimation of poor permeable formations like tight or gas-shale reservoirs using a pulse-decay experiment performed on crushed samples has been shown in earlier works to be an interesting alternative for it is faster and less expensive than traditional transient tests performed on carefully prepared core plugs, although it is restricted to measurement in the absence of overburden pressure. Due to reservoir depletion during production, sample characterization over a wide range of pore-fluid pressure is essential. If the Darcy-Klinkenberg model is thought to be a satisfactory gas-flowmodel for these tight formations, the full characterization can be achieved by determining both the intrinsic permeability, kl, and Klinkenberg coefficient b.
In this work, the conditions under which reliable estimates of kl, b and porosity, ø can be expected from this type of measurement are carefully analyzed. Considering a bed of monodisperse-packed spheres and a complete physical model to carry out direct simulations and inversion of the pressure decay, important conclusions are drawn opening wide perspectives for significant operational improvement of the method. In particular, it is shown that:
i) The particle size of the crushed sample must be well selected for a reliable pressure-decay signal record.
ii) The simultaneous determination of both kl and b by inversion of the pressure-decay signal is very difficult because the sensitivities of the pressure decay to both coefficients are correlated
iii) The porosity of the particles can be accurately estimated when the experimental setup has been properly calibrated (volumes of the chambers and of the porous sample). The precision on the estimation of this parameter is however strongly dependent on a bias on the crushed sample volume.
iv) When identification of kl and b is possible, a very significant error may occur in the determination of the intrinsic permeability due to a bias on the porous sample volume. Errors on the estimated values of ø and kl due to a bias on the chamber volume are not very significant Moreover, b remains insensitive to bias on both the chamber and porous sample volumes.
Clarkson, Christopher R. (University of Calgary) | Wood, James (Encana Corporation) | Burgis, Sinclair (Encana Corporation) | Aquino, Samuel (University of Calgary) | Freeman, Melissa (University of Calgary)
The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize because of a wide poresize distribution (PSD), with a significant pore volume (PV) in the nanopore range. A variety of methods is typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range. In this work, we investigate the use of nondestructive, low-pressure adsorption methods, in particular low-pressure N2 adsorption analysis, to infer pore shape and to determine PSDs of a tight gas siltstone reservoir in western Canada. Unlike previous studies, core-plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure (i.e., uncrushed) to be analyzed. Furthermore, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which mercury-injection capillary pressure (MICP) and permeability measurements were previously performed, allowing a more direct comparison with these techniques. PSDs, determined from two isotherm interpretation methods [Barrett-Joyner-Halenda (BJH) theory and density functional theory (DFT)], are in reasonable agreement with MICP data for the portion of the PSD sampled by both. The pore geometry is interpreted as slot-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, scanning-electron-microscope (SEM) imaging, and the character of measured permeability stress dependence. Although correlations between inorganic composition and total organic carbon (TOC) and between dominant pore-throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore-throat size and highest permeability, as estimated from MICP. The presence of stress relief-induced microfractures, however, appears to affect laboratory-derived (pressure-decay and pulse-decay) estimates of permeability for some samples, even after application of confining pressure. On the basis of the premise of slot-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, by use of dominant pore-throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly overpredicted for samples that are unaffected by stressrelease fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries or between organic matter and framework grains.
Hruška, Marina (Chevron Energy Technology Company) | Bachtel, Steven (Chevron Energy Technology Company) | Archuleta, Bonny (Chevron Energy Technology Company) | Skalinski, Mark (Chevron Energy Technology Company)
In this integrated study using resistivity images, conventional openhole logs, and core data from a Middle Eastern reservoir, abundance and geometric configuration of bedded and nodular evaporite have been studied to help distinguish which nodular forms of evaporite may be related to a permeability suppression. Several logs have been calculated from the resistivity image log to quantify nodular evaporite and help predict the presence of corresponding core facies well. Compared with thin-section description, most samples of nodular evaporite were exhibiting fine-scale cementation as well, and their permeability was suppressed compared with samples with rare or no fine-scale cementation in thin sections.