Reservoir Pore Throat Research Articles

English

There are many processes the oil industry used to recover more oil from the reservoir after the natural energy is depleted. In this research work, ultrasound energy has been tested as a method of improving oil recovery after waterflooding. The method used in this research work was a numerical simulation using MATLAB Reservoir Simulation Toolbox (MRST-2017a). Ultrasound energy source equation was incorporated into the residual energy equation in the MRST. Acoustic attenuation pressure equation was modelled as part of the residual pressure equation in the MRST. Effect of ultrasound waves on pore wall deformation was also modelled from waves stress equation. Two-phase (oil/water) black oil model was used to simulate fluid flow. Results obtained from the simulation runs show that the ultrasound energy has an impact on reservoir performance i.e. increase in fluid flowrates and pore pressure and temperature rise which led to oil viscosity reduction and consequently improve mobility ratio. However, attenuation of ultrasound energy increases with propagation distance, but this effect was compensated by increasing the intensity of the ultrasound power. Though, high power intensity induced stress on the reservoir pore throat. Results obtained also show that high porosity and permeability values affect the performance of the acoustic energy basically due to an increase in the rate of waves absorption. Key words: Ultrasound energy, improved oil recovery, reservoir simulation toolbox, MATLAB. &nbsp

A comparative study of dynamic adsorption of anionic synthetic and nanocellulose-based surfactant in Malaysian reservoir

This project is aimed at studying the applicability of nanocellulose-based surfactant as a sustainable surfactant for enhanced oil recovery process (EOR) in Malaysia. Abundant biomass waste from palm oil industry in Malaysia is hard to be disposed of. Therefore, potential application of biomass in chemical EOR is an attractive alternative to minimize these problems. For this study, nanocellulose is synthesized from oil palm empty fruit bunch (OPEFB) and undergoes chemical modification for it to act like a surfactant. All methods and techniques in synthesizing nanocellulose and preparing nanocellulose-based surfactant are made inhouse. While waiting for the material preparation, adsorption study is carried out by using anionic synthetic surfactant. Characterization result shows the nanocellulose undergoes chemical modification successfully. The IFT results for the nanocellulose-based surfactants are also in a good and acceptable range, but there are some limitations in using nanocellulose-synthesized surfactant. The average particle size of nanocellulose is 283.5 µm which is larger than size of the reservoir pore throat. Dynamic adsorption cannot be performed as the large particle size of nanocellulose might plug the porous domains. Therefore, it is recommended to further improve the method of synthesizing nanocellulose from OPEFB because the nanocellulose-based surfactant is expected to have potential of lower adsorption in porous media once it becomes nanosized and due to its advantages such as being of lower cost and environmental friendly compared to other commercial surfactants.

Combined technology of PCP and nano-CT quantitative characterization of dense oil reservoir pore throat characteristics

The size of pore throats in tight oil reservoirs varies from a few tens of nanometers to several hundred micrometers. This complex and diverse microscopic pore throat structure restricts the exploration and development process, affecting the recovery rate. Size, shape, and spatial distribution of pore throats in tight oil reservoirs are revealed in this paper via a scanning electron microscope (SEM), casting thin-sections, high-pressure mercury injection, and Nano-CT. Results show that the pore type of the Chang 7 tight oil reservoir in the Xin’anbian area is mainly divided into three categories: intergranular pores, dissolution pores, and microfractures. Numerous nanoscale pore throats have developed in this area, which greatly contributes to reservoir capacity and seepage. Pore throat distribution on capillary pressure curves of different samples shows that when the threshold pressure is less than 1 Mpa, there are many micron-sized pores with good connectivity and pore throats form a large tubular shape with a throat radius between 3.6 and 1064 nm. When the threshold pressure ranges from 1 to 3 MPa, there are many nanoscale pores with good local connectivity, intragranular dissolution pores develop, and pore throats are in tube bundles and spherical in shape with the throat radius between 3.6−657 nm. When the threshold pressure is greater than 3 MPa, nanoscale microfractures develop and are connected to neighboring small spherical pores, small spherical nanopore spaces become isolated, vertical connectivity is poor, and the throat radius is between 3.6−242 nm.

The Pressure Sensitivity Test and Plugging Mechanism Analysis in Salt-out Reservoir

With the decrease of formation pressure, high temperature and high salinity reservoirs are prone to salting out, which leads to the blockage of reservoir pore throat and the decrease of oil recovery. The gas-liquid two-phase seepage mechanism when the formation pressure is lower than the saturation pressure is simulated by changing gas-liquid injection volume ratio, and metallographic microscope and probabilistic statistical method were used to analyze the degree of plugging caused by salting out in displaced cores. The research shows that when the reservoir pressure is slightly lower than the saturation pressure, it is beneficial to improve the reservoir recovery, but when the reservoir pressure is too low, the salting out phenomenon is serious, the reservoir pore throat is blocked, and the reservoir permeability and recovery are significantly reduced. The reservoir blockage mainly occurs at the end of production, and the regularity of blockage degree is in line with the characteristics of exponential variation.

Matching between the diameter of the aggregates of hydrophobically associating polymers and reservoir pore-throat size during polymer flooding in an offshore oilfield

Abstract In order to quantitatively study the matching between hydrophobically associating polymers (HAPs) and reservoir pore-throat size in offshore oilfields, the geological characteristics and fluid properties of the S area reservoir in the Bohai Oilfield were used as a research platform. After determining the matching of HAP solutions with different association degrees and core permeabilities using a seepage experiment at a constant flow rate, the matching between the diameter of the HAP aggregates (Dh) and the median pore-throat radius was quantified by combining the relationship between core permeability and median pore-throat radius. Finally, the importance of matching on the oil displacement effect of the HAP solution was demonstrated using homogeneous cores and heterogeneous cores with separate injection and production interlayers. The results showed that the diameter of the HAP aggregates, as well as their morphology and ability to increase viscosity, were highly related to the association degree of HAP. As the association degree of HAP was varied, the matching between cores with different permeabilities and the beta-cyclodextrin (β-CD)/HAP compound systems also changed. Under the experimental conditions used in this study, the ratio between the median pore-throat radius and Dh ranged from 4 to 7. During the process of HAP flooding, suitably increasing the Dh, i.e., increasing the association degree between HAP molecules, could allow control of the mobility of the HAP solution. The oil displacement effect of HAP was closely related to the matching between the HAP and reservoir pore-throat, rather than the viscosity of the HAP solution. Good matching between the HAP and reservoir pore-throat not only achieves fluid diversion but can also expand the swept volume in the low-permeability layer to ensure good oil displacement ability.

Reservoir heterogeneity of Agbada Formation sandstone from PZ-2 well and PZ-4 well, Niger Delta: implications for reservoir management

Sandstones of the Agbada Formation deposited in Eocene serves as the main hydrocarbon reservoirs of the Niger Delta Basin. PZ-2 well and PZ-4 well that penetrated sections of the formation were investigated for their reservoir heterogeneity, to understand the hydraulic flow units and better assessment of the reservoirs. Reservoir quality and pore throat sizes encountered in the sandstones vary from poor to excellent quality and macroscopic. Greater heterogeneities permeability and homogeneous porosity distribution occur in the bioturbated sandstone facies in the PZ-4 well and sandstone facies in the PZ-2 well. Four hydraulic flow units (FZ-1, FZ-2, FZ-3, FZ-4) and three hydraulic flow units (FZ-1, FZ-2, FZ-3) were recognized in the PZ-2 and PZ-4 wells respectively. These flow zones are characterised by good reservoir qualities and adjudged as a better reservoir candidate for probable prospects.

Applying LSSVM algorithm as a novel and accurate method for estimation of interfacial tension of brine and hydrocarbons

ABSTRACTOne of the critical parameters in petroleum and chemical engineering is the interfacial tension between brine and hydrocarbon which has major effects on trapping and residual oil in reservoir pore throat so it becomes one of the interesting topics in enhancement of oil recovery in this work Least squares support vector machine (LSSVM) algorithm was applied as a novel predicting machine for prediction of interfacial tension of brine and hydrocarbons in terms of hydrocarbon carbon number, temperature, pressure and ionic strength of brine. A total number of 175 interfacial tensions were collected from literature in the purpose of training and testing of the model. The root mean squared error (RMSE), average absolute relative deviation (AARD) and the coefficient of determination (R2) were calculated overall datasets as 0.23964, 0.27444 and 0.98509 respectively. The results of study showed that predicting LSSVM machine can be applicable for estimation of interfacial tension and EOR processes.

Investigation on matching relationship between dispersed particle gel (DPG) and reservoir pore-throats for in-depth profile control

The current study aims at in-depth profile control to further improve oil recovery by studying the matching relationship between the size of dispersed particle gel (DPG) and geometry of reservoir pore-throat. The DPG products with different sizes were prepared, and their microscopic characteristics and particle size distributions were analyzed. The matching factor, which was defined as the ratio of average size of DPG particles to mean size of pore-throats, was introduced to represent the matching relationship. The injection properties and plugging capacities were systematically studied by a series of core flooding experiments to optimize the matching factor. The matching factor was optimized from 0.21 to 0.29 depending on both the injection pressure and the plugging rate. In addition, the results of multi-point pressure measurement experiment verified that the DPG particles exhibited good in-depth migration and plugging ability within the optimized matching factor values. Meanwhile, scanning electron microscope (SEM) was used to study the distribution of DPG particles in porous media. The results intuitively showed that the DPG particles can migrate to the deep of porous media and induce effective plugging to the pore-throats. Moreover, the enhanced oil recovery experiments for different matching factors were conducted, and the mechanisms for enhanced oil recovery by DPG with different matching factors were proposed. The enhanced oil recovery with an optimized matching factor was much higher than that with a smaller or larger matching factor. Owing to good in-depth migration and plugging ability of DPG particles with optimal matching factors, the subsequent injected water was diverted into low permeability zones with high oil saturation and, consequently, widely swept the remaining oil in low permeability zones.

Experimental measurement and mathematical model of permeability with methane hydrate in quartz sands

Natural gas hydrates widely distributed in marine sediments and permafrost areas have attracted global attentions as potential energy resources. The permeability of sediments with or without hydrate is an essential and critical parameter that could determine the technical and economical feasibility of gas recovery from hydrate reservoirs. The saturation of hydrate in the solid phase significantly affects the pore size, the pore volume, the distribution of reservoir pore throat size, etc., which are key factors determining the permeability of the hydrate-bearing deposit. In this study, the absolute permeability and the water effective permeability were experimentally measured with fluid water under a serials of hydrate saturations (0–31% in volume). Hydrate saturations were controlled and calculated precisely based on the amount of injected and produced gas/water, and the system pressure and temperature. Unconsolidated quartz sands with different particle size (200–300, 300–450, 450–600µm) were used as the porous media. The absolute permeabilities of the above quartz sands were 21.11, 35.53 and 52.32 Darcies, respectively. The experimental results indicated that the characteristics of the permeability were different with the hydrate saturation lower and higher than 10%. When the hydrate saturation increased from 0 to 10%, there was a sudden drop for the permeability, which indicated that the appearance and the existence of the solid hydrate phase in the porous media affected the permeability significantly. On the other hand, this effect lightened when the hydrate saturation higher than 10%. With different hydrate crystal growth habit, a new relationship between the ratio of the permeability in the presence and the absence of hydrate and the hydrate saturation was developed. Two patterns of the pore filling models with the hydrate saturation lower and higher than 10% were used to fit the measured experimental data. The overall relationship and the values of the saturation exponent were continuous and consistent with hydrate saturation lower than 31%.

Characteristics and resource prospects of tight oil in Ordos Basin, China

AbstractEfficient large-scale development of ultra-low-permeability reservoirs (0.3–1mD) has been achieved in the Changqing Oilfield, Ordos Basin of China. According to unique features of petroleum exploration and development in this basin, tight oil herein refers to petroleum that occurs in oil-bearing shales and interbedded tight sandstone reservoirs adjacent to source rocks with ambient air permeability <0.3mD. Tight oil in tight sandstone and shale have generally not yet experienced large-scale long-distance migration. In the Yanchang Formation, tight oil has mainly accumulated in the semi-deep to deep lacustrine facies, typically in oil-bearing shales and tight sandstones of the 7th member oil-bearing formation and tight sandstones of the 6th member oil-bearing formation in the center of the basin. Tight oil resource in the Ordos Basin is characterized by wide spatial distribution, excellent source rocks, extremely tight sandstone reservoirs, complex pore throat structures, poor physical properties, high oil saturation, good crude-oil properties, and low reservoir pressure. A fundamental feature of the continuous oil and gas accumulation in tight oil reservoirs is the widespread development of nano-scale pore-throat systems. In the Yanchang Formation, most of connected pore throats in tight sandstone reservoirs have diameters greater than critical pore throat diameter, allowing oil and gas migration in the tight reservoirs. According to contact relationship between tight reservoirs and source rocks, three types of tight oil reservoirs are identified in the Yanchang Formation, i.e., tight massive sandstone reservoir, sand - shale interbed reservoir, and oil-bearing shale reservoir. In the Ordos Basin, tight oil is widely distributed in the 6th and 7th members of the Yanchang Formation, with total resources estimated to be 3×109 t. These include > 1×109 t of oil resources in shale in the 7th member of the Yanchang Formation and approximately 0.9×109 t and 1.1×109 t of tight sandstone oil resource in the 6th and 7th members of the Yanchang Formation, respectively. These tight oil resources are the realistic resources addition for the oilfield, which can ensure an annual production of 50×106 t of oil and gas equivalent and maintain long-term stable oil production in the Changqing Oilfield, Ordos Basin, China.

Investigation of Nanoparticle Adsorption During Transport in Porous Media

Summary Nanoparticles (diameter of approximately 5 to 50 nm) easily pass through typical pore throats in reservoirs, but physicochemical attraction between nanoparticles and pore walls may still lead to significant retention. We conducted an extensive series of nanoparticle-transport experiments in core plugs and in columns packed with crushed sedimentary rock, systematically varying flow rate, type of nanoparticle, injection-dispersion concentration, and porous-medium properties. Effluent-nanoparticle-concentration histories were measured with fine resolution in time, enabling the evaluation of nanoparticle adsorption in the columns during slug injection and post-flushes. We also applied this analysis to nanoparticle-transport experiments reported in the literature. Our analysis suggests that nanoparticles undergo both reversible and irreversible adsorption. Effluent-nanoparticle concentration reaches the injection concentration during slug injection, indicating the existence of an adsorption capacity. Experiments with a variety of nanoparticles and porous media yield a wide range of adsorption capacities (from 10–5 to 101 mg/g for nanoparticles and rock, respectively) and also a wide range of proportions of reversible and irreversible adsorption. Reversible- and irreversible-adsorption sites are distinct and interact with nanoparticles independently. The adsorption capacities are typically much smaller than monolayer coverage. Their values depend not only on the type of nanoparticle and porous media, but also on the operating conditions, such as injection concentration and flow rate.

Experimental analysis on reservoir blockage mechanism for CO 2 flooding

Abstract The slim-tube experiment, component analysis experiment and microscopic simulation experiment are used to analyze the phenomena of reservoir blockage and drop of oil production rate, and to find out the reservoir blockage mechanisms in the process of carbon dioxide flooding. The slim-tube experiment shows that the effect of carbon dioxide flooding was poor under low displacement pressure, and the higher the displacement pressure, the better the effect of flooding. When the displacement pressure exceeded the minimum miscibility pressure, reservoir blockage could occur, affecting the reservoir productivity significantly. Component analysis and microscopic modeling experiments show that oil component differentiation could occur after oil contacted with carbon dioxide. Under low displacement pressure, component differentiation was not significant, so reservoir blockage did not occur; but when the displacement pressure was higher, aromatics in oil were extracted rapidly by carbon dioxide, resulting in quick deposition of non-hydrocarbons and asphalt and the blockage of pore-throats in reservoirs. Therefore, controlling the displacement pressure is the main measure to prevent reservoir blockage. The best pressure of carbon dioxide flooding should be near the minimum miscible pressure, pressure, too high or too low, is not good for carbon dioxide flooding.

The Law of Reservoir Property Change both before and after Water Flooding in Liaohe Oilfield

In order to explore the change laws of physical properties and pore throat radius of reservoir both before and after water flooding to guide the oilfield in-depth fluid diversion, the reservoir properties are analyzed on the basis of core data of early exploratory well and inspection well in the middle and later stages of oilfield development. The theory of reservoir geology and development geology is used to study the change laws of reservoir properties both before and after water flooding in May 20th Development Area of Liaohe oilfield. The research result indicates that reservoir physical properties and pore throat radius have changed in the different period and different microfacies types of sand body [1-3].The permeability is changed far outweigh porosity in the physical properties of reservoir. And with the increase of time, the biggest change is the porosity and permeability of distributary channel, the next are margin of channels, mouth bar. The thin layer of channels and distal bar of physical properties have changed lesser or not. The pore throat radius has declined following distributary channel, mouth bar, thin layer of channels and distal bar in the sedimentary microfacies [4-5].The study results are helpful for the establishment of production measures at the later stage of oilfield development.

Study of Characterization Methods on the Particle Size of SMG

Soft moveable gel (SMG) is a new kind of deep profile control microgels used in many oilfields. SMG has many advantages of high temperature, salt tolerance, shear resistance, controllable grain size, good control and oil displacement effect. The SMG deep profile control technique can remarkably improve oil recovery of the high temperature and high salinity oilfields. While the successful applications of SMG deep profile control technique are greatly decided by the size matching ability between SMG microgels micelle particles and reservoir pore throat. Therefore, three different experimental methods such as microscope, SEM analysis, and laser scattering method are used for particle characterization at first. Based on that, the new method utilizing near-infrared spectroscopy is innovated and developed. The method has the advantages of non-destructive measurement of original state, convenient, accurate and reliable results etc.. Finally, three levels of SMG particle size entitled by nanometer, micron, and sub-millimeter are systematically evaluated. The results show the sizes are 0.06, 21.37, about 39.24 μm respectively in the new method. Different particle size of SMG can be applied in deep profile control of high, medium or low permeability reservoirs correspondingly with high temperature and high salinity.

Flow Characteristic of Aqueous Dispersion System of Nano/micron-sized Polymer Particles Through Microporous Membrane

To evaluate percolation ability of aqueous dispersion system of nano/micron-sized polymer particles in porous media, the flow characteristic and its influence factors were studied by laser particle size analyzer and filtration device of microporous membranes which were simulated to reservoir pore throat. The results show that at the same hydration time, plugging capacities of nano/micron-sized polymer particles gradually increase as their average particle sizes increasing; at the different hydration time, plugging capacities of nano/micron-sized polymer particles show a trend of increasing first and then decreasing with increasing average particle sizes. With increasing pressure differentials, the plugging capacities of nano/micron-sized polymer particles gradually decrease and their deep profile control capacities gradually increase. When pore sizes of microporous membrane decrease, the plugging capacities of nano/micron-sized polymer particles rapidly increase and their deep profile control capacities quickly decrease. When the particle concentrations increasing, the plugging capacities of nano/micron-sized polymer particles increase and their deep profile control capacities decrease.

Multi-scale method of Nano(Micro)-CT study on microscopic pore structure of tight sandstone of Yanchang Formation, Ordos Basin

Abstract Multi-scale (nano-to-micro) three-dimensional CT imaging was used to characterize the distribution and texture of micro-scale pore throats in tight sandstone reservoirs of the Triassic Yanchang Formation, Ordos Basin. First, the low-resolution Micro-CT was used to reflect the micro-pore texture of the core column with a diameter of 2.54 cm. Then, some samples with a diameter of 65 μm was derived from different areas according the different characteristics of micro-pore texture of the core scanned by low-resolution Micro-CT and scanned by high-resolution Nano-CT. Thus, a three-dimensional texture model of nano-scale micro-pores was reestablished and the permebility and porosity data of the sample could be obtained. On a micrometer scale, the size of the micro-pores varies, and their diameters range from 5.4 to 26.0 μm. The micro-pores are isolated, locally in the shape of a band. On a nanometer scale, the quantity of nanoscale micropores increases, the diameter of which ranges from 0.4 to 1.5 μm. The pore throats are arranged in the shape of tube and ball inside or on the surface of mineral particles(crystals). The ball-shaped micropores in nanoscale, often isolated in the three-dimensional space, show the poor connectivity and consequently act as the reservoir space. By contrast, the tube-shaped micropores in nanoscale show certain connectivity with micro-scale tube-shaped micropores and adjacent isolated ball-shaped micropores in nanoscale. Therefore, these tube-shaped micropores in nanoscale serve as throats and pores. Based on the calcution, the permeability of the samples is 0.843×10 −3 μm 2 and porosity is 10%.

姬塬油田储层注水伤害分析与化学增注技术研究

姬塬油田属特低渗油田，在注水开发过程中，因注入水与地层水严重不配伍，导致储层孔喉结垢，影响油田注水开发。本文通过对注入水与地层水分析、水管路流动结垢实验、注水储层伤害评价等，认为注入水与地层水不配伍是造成储层伤害的主要原因之一。开发了能够溶解硫酸钡锶垢的YHS-1清垢剂，有效解除储层结垢堵塞，恢复储层渗透率。 Jiyuan oilfield is an oil field with extremely low permeability. During the waterflooding process, because the injection water can not be concurrent with formation water, the scales at reservoir pore-throat will influence the waterflood development of oilfield. In this article, according to the analysis of injection water and formation water quality, scaling experiments of water flows, evaluations for water injection reservoir damage, it makes clear that the incompatibility of injection water and formation water is one of the main causes of formation damage. YHS-1 was employed as the cleaning agent of barium and strontium sulfate scale to relieve the reservoir scale blockage effectively and restore the reservoir permeability consequently.

Nano-hydrocarbon and the accumulation in coexisting source and reservoir

Abstract By comparison of the types, geological characteristics and exploration technologies of conventional and unconventional hydrocarbon, this paper proposes the concept of “nano-hydrocarbon” and regard nano-hydrocarbon as the development direction of oil and gas industry in the future. Nano-hydrocarbon refers to the research and production, by nano-technology, of oil and gas accumulated in the reservoir system of nano-sized pore-throats. It is mainly distributed in source rocks and the neighbouring tight reservoirs and includes shale oil, shale gas, coal-bed methane, tight sandstone oil and gas, tight limestone oil and so on, with nano-sized diameter of pore-throats in reservoirs. Oil, gas and water in nano-sized pore-throats exhibit poor percolation and phase separation, and are mainly driven by ultra-pressure, thus existing pervasively and continuously in the coexisting tight source and reservoir rocks. China's petroliferous basins develop multiple series such as coexisting tight source and reservoir, carbonate fractures and cavities, volcanic fractures and cavities, and metamorphic rock fractures. Among the series, the first type is located in the center or on the slopes of the basins, where nano-hydrocarbons are accumulated extensively within or near sources and are dominant potential sources. With accumulations within coexisting source and reservoir in the Ordos Basin and Sichuan Basin as examples, the method of “two lines and one area” to prospect continuous-type hydrocarbon accumulation is proposed, i.e. the top and bottom boundaries of a set of coexisting source and reservoir and the boundaries of hydrocarbon accumulation as lines, and “sweet spot” distributing core area as the main exploration target.

The Hot Water Oil Expulsion Technique for Geothermal Resources

With the rapid development of Chinese petroleum industry, Oil production way of burning crude oil to produce steam need change. Heavy oil reservoir with thin layer or edgewater is unsuitable thermal recovery, electric heating leads to considerable electrical consumption, low injection water temperature decreases reservoir temperature and increased crude oil viscosity. The prolonged temperature difference break up reservoir pore throat cement and framework minerals. To improve high-capacity channel communication, we proposed geothermal oil recovery. Broad-sense abundant geothermal resources and existing injection water technique equipment are used, deep-seated high temperature liquid (oil-gas-water mixture) draws geothermal warming flowing layer to transit heat upward, decreases viscidity and increases fluidity. Reservoir temperature different offer geothermal fountain. Practicability process is analyzed. statistics and reservoir temperature variation analysis of Gudong Oilfield, Shengli Oilfield Company, SINOPEC, we have designed flow-chart concept for geothermal oil recovery, suggested drilling multi-branch well in heavy oil reservoir as injection-well, at the same position of geothermal fountain well, using free-pressure pump to inject hot liquid directly to aimed oil layer, made oil recovery in surrounding wells. It is proposed that geothermal oil recovery forerunner test should be first conducted in favorable blocks.

Single-Phase Bottomhole Sampling Technology

Abstract Oilphase, a Schlumberger company, has developed and successfully tested a novel Single-phase Sampling Technology (SST), which is in use worldwide. In this system, the collected reservoir fluid pressure is maintained at or above reservoir pressure during retrieval by the release of a pre-set nitrogen charge. Subsequent to collecting the single-phase reservoir fluid, experiments were conducted in the laboratory to demonstrate the importance of SST. Results indicate that the onset of asphaltene flocculation pressure indeed varies with the amount of asphaltene content in the reservoir fluid. The collection of a non-representative reservoir fluid sample may carry a non-representative asphaltene amount due to irreversible precipitation, and hence, result in characterization of a non-representative asphaltene flocculation onset. Therefore, asphaltene characterization on a nonrepresentative reservoir fluid sample will lead to either over- or under-design of the production system. Introduction Reservoir fluids containing hydrocarbon solids are common in the petroleum industry. The primary constituents of the solids are waxes and asphaltenes. These compounds remain in solution under reservoir temperature and pressure conditions. The hydrocarbon solids will destabilize from the reservoir fluid when the thermodynamic equilibrium conditions (that is, temperature, pressure, and composition) are altered. Asphaltenes are dark brown to black solid molecules with no definite melting point. They decompose while heating, and leave a carbonaceous residue. They are non-crystalline substances or mixtures of relatively high molecular weight fractions(1) of bitumen with characteristics of strong aromatic polar substances(2, 3). Asphaltenes are defined as the n-heptane insoluble fraction of crude oil(4, 5) that are also soluble in toluene(6). They are classified by the particular solvent used to precipitate them(7). Various laboratory techniques are used to determine the onset of asphaltene flocculation.(8–13) Most of these techniques are dependent on the oil characteristics. The most important characteristic is the colour of the oil. For dark-coloured oil, the popular light-scattering technique using a laser source in the visible spectrum becomes inadequate. In this case, near-infrared (NIR) light spectrum is necessary to identify any changes in the response due to a phase change phenomenon(14). Once flocculated, asphaltenes have the propensity to grow in size, and subsequently, may start to deposit on the reservoir and production circuit (Figure 1). Flocculation and deposition of asphaltenes have reportedly caused a multitude of operations problems(15), thereby increasing the cost of production significantly. From a reservoir management point of view, high onset of asphaltene flocculation pressure can severely limit the primary recovery potential. To avoid the reservoir pore throat clogging, operators may need to implement a reservoir pressure maintenance scheme. Recently, Kabir and Jamaluddin(16) have presented their work related to the requirements of pressure maintenance in order to produce from the South Kuwait Marrat formation without having to experience the asphaltene deposition problem. Regardless of various approaches, we believe that the correct operating procedure to minimize the asphaltene problem is not well understood. This could be attributed to our inability to retrieve a representative bottomhole sample using the conventional bottomhole sampler.